FERC Review: Mystic 8 & 9 Analysis for FCA 13 Refresh

1. December 18, 2018 | Westborough, MA Norman Sproehnle (413) 540-4755 | NSPROEHNLE@iso-ne.com Review of FERC-Filed Analysis Under Planning Procedure 10 Inputs Forward Capacity Auction 13 (FCA 13): Informational Refresh of Mystic 8 & 9 Analysis Revision 1

2. In May, the ISO filed a waiver with the Commission to retain Mystic 8 & 9 for fuel-security reliability • Filing included analyses demonstrating reliability need for Mystic 8 & 9 using Operational Fuel-Security Analysis model (“Mystic Retirement Studies”) • July 2 Order found Mystic Retirement Studies were based on reasonable assumptions and methodology; directed the ISO to create a short-term cost-of-service mechanism to address fuel-security needs • In response to July 2 Order, Planning Procedure No. 10 Appendix I (PP10-I) documented reliability criteria for analyzing retiring units needed for fuel-security reliability • In response to stakeholder feedback, and to improve balance between regional reliability needs and market efficiency, certain assumptions were refined from those in Mystic Retirement Studies • While the July 2 Order determined Mystic 8 & 9 were needed for reliability, the August 31 compliance filing included analysis using the revised assumptions from PP10-I and results of that analysis again showed numerous violations of the trigger criteria across multiple scenarios

3. During PP10-I development, ISO committed to discuss application of revised assumptions by refreshing FCA 13 Mystic 8 & 9 analysis, similar to what was filed with FERC in August • At today’s meeting, the ISO will review inputs and outputs of that analysis • December 3 Order accepted ISO’s proposed fuel-security revisions; also directed ISO to submit annual informational filing regarding applicability of its study triggers, study assumptions, and study scenarios compared with actual experiences • FCA 14 fuel-security reliability review for the Mystic 8 & 9 Retirement De-list Bids (and any others received) will be performed in 2019 • Discussion of updated inputs to that analysis will be discussed with the Reliability Committee in Q1 2019

4. Discussion OF Refreshed STATIC INPUTS TO FCA 13 Mystic 8 & 9 Analysis

5. Winter 2022/2023 Peak Load and Energy Profile • The hourly demand levels from winter 2014/2015 were adjusted* to reflect the winter net 90/10 CELT load forecast of 20,342 MW (including the effects of energy efficiency) for slightly lower net peak demand in extreme winter conditions in 2022/2023 of 20,098 MW • Additionally, analyses were performed using a 50/50 CELT peak load forecast of 19,642 MW for winter 2022/2023 to provide further information *The forecast ratio used to create the energy profile load shape was0.988

6. Local Distribution Company (LDC) Gas Demand • As noted in the refined assumptions developed with the stakeholders, LDC gas demand was held at 5.262 Bcf/day, which was the amount forecasted in the ICF Study Integrated Resource Plan

7. Gas Source Capacity • Interstate pipelines serve New England, New Brunswick and the Maritimes regions and their gas capacity was accounted for in this informational analysis as follows: • Algonquin (Spectra Energy) (1.91 Bcf/day) • Tennessee (Kinder Morgan)(1.39 Bcf/day) • Iroquois ( 0.26 Bcf/day) • Portland Natural Gas Transmission System (PNGTS) ( 0.3 Bcf/day) • Total of 3.86 Bcf/day into the region • Three LNG facilities serve the region and their gas capacity was accounted for in this informational analysis as follows: • Distrigas – Boston MA direct source of gas for Mystic 8 &9 (their only source of fuel) • Can vaporize gas to Algonquin and Tennessee Pipelines (0.439 Bcf/day) • Can vaporize gas to National Grid - LCD (0.233 Bcf/day) • Canaport – St. John, New Brunswick, Canada • Vaporizes gas into the M&N pipeline (1.2 Bcf/day) • Excelerate – Offshore Near Salem, MA • Vaporizes gas into the Algonquin Pipeline hub line (0.4 Bcf/day)

8. Pipeline Capacity • Daily available gas was calculated and shaped to reflect hourly gas usage. The gas availability profile was shifted from off-peak hours to on-peak hours to follow the hourly electric demand curve • Methodology of modeled hourly gas profile: • (Total Daily Available Gas) = (Daily Pipeline Available Gas) + (Daily LNG Injections Available) + (Daily Satellite Gas Injections) • (Total Daily Available Gas for Generation) = (Total Daily Available Gas) – (New England Daily LDC Demand) – (New Brunswick Daily LDC Demand) • (Hourly Gas Available for Generation) = (Total Daily Available Gas for Generation ) * (Ratio of hourly electric demand to total electric demand for the Day)

9. Satellite LNG Injection • The total satellite LNG injection was estimated by the following equation, using heating degree day (HDD) as the predictor. This equation was developed by ICF International as part of the Assessment of New England’s Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II* HDD>HDD Trigger (53) Minimum of: 1.456 Bcf or (HDD*45.6-1874.6)/1000 • The event that triggered the model to utilize satellite LNG injections was when the HDD was greater than 53. This equates to an average daily temperature of 12°F or lower. The maximum sendout capability was 1.456 Bcf/day • For example, utilizing the winter weather of 2014/2015 in the equation above provides a maximum injection value of 0.820 Bcf/day on February 16, 2023 *https://www.iso-ne.com/static-assets/documents/2014/11/final_icf_phii_gas_study_report_with_appendices_112014.pdf

10. Oil-Only Inventory and Replenishment Levels • Tank inventories were assumed to be replenished with one proxy tanker truck per hour when the reorder level, provided in the December 2017 fuel survey, was reached • Inventory levels were set to levels determined using the December 2017 fuel surveys submitted to the ISO

11. Resource Seasonal Claimed Capability and Equivalent Forced Outage Rate Demand (EFORd) • Seasonal Claimed Capability (SCC) • For Existing Generating Capacity Resources qualified for FCA 13 and energy-only generators active in the ISO-NE markets, the winter SCC from the May 2018 CELT Report was used • For non-commercial Existing Generating Capacity Resources that were not in the CELT report, the resource’s FCA 13 winter Qualified Capacity was used • The ISO used the calculated EFORd utilizing its Generating Availability Data System (GADS) data

12. Certifications of Contractual Commitment • When the Mystic 8 & 9 analysis was refreshed using the revised assumptions, there were no submissions of certification of contractual commitment from resources being built in accordance with Attachment K to Part II of the Tariff to account for in the assessment

13. PV Forecast and Sun Profile • The PV forecast-nameplate was 4,388.8 MW as calculated from the information in the May 2018 CELT Report (sum of the Markets Total Cumulative and the Behind-The-Meter Total Cumulative values) • The ISO adjusted the observed hourly PV profile from the 2014/2015 winter to reflect the expected performance of the PV fleet for the 2022/2023 winter Winter 2022-2023 PV Capacity Factor

14. Onshore Wind Profiles • The onshore wind resource nameplate was 1,317.49 MW as calculated from the information in the May 2018 CELT Report • Observed onshore wind data from the winter of 2014/2015 was adjusted by 4% to reflect the expected performance of the fleet assumed in-service for winter 2022/2023

15. Offshore Wind Profiles • The offshore wind resource nameplate was 29.25 MW as calculated from the information in the May 2018 CELT Report • For the August 31 compliance filing, ISO utilized the National Renewable Energy Laboratory (NREL) profiles from three offshore sites in New England for the 29.25 MW of nameplate offshore wind modeled in the analysis

16. Offshore Wind Profiles, cont. • As committed to stakeholders: • The ISO is in the process of validating an hourly offshore wind profile based on the winter 2014-2015 weather • Hourly wind speed data is developed using data from NREL and NASA models • Corresponding capacity factors will be based on the resource’s turbine hub height for specific offshore locations • Any model will have negligible impact on FCA13 reviews due to very limited MWs of offshore wind in service (29 MWs) • ISO will discuss this effort with stakeholders as part of its FCA 14 reliability reviews

17. Pumped and Battery Storage Revision 1 • As described in PP10-I, Section 3.A.xvii storage resources wereset to levels using a daily profile to reflect characteristic operation of these resources to store energy during low load periods and generate electricity during the higher load periods • Pump Storage = 1,762 MW* • Battery Storage = 1 MW *Value should be 1,785 MW (Bear Swamp 584.4 MW, Rocky River 27.8 MW, Northfield Mountain 1172.5 MW)

18. Conventional Hydro-electric Generation and Demand Response Resources • As described in PP10-I, Section 3.A.xviii conventional hydro-electric resources were dispatched at an hourly output based on the weighted average hydro Capacity Factor calculated using the latest 5-year NERC EFORd Capacity Factor Class Averages for HYDRO 1-29 and HYDRO 30 Plus • From the 2018 CELT, the winter SCC for the hydro-electric resources was 1,483 MW • The weighted average hydro Capacity Factor was calculated to be 34.3% • The hourly dispatch value was 1483 * .343 = 509 MW • The winter Seasonal Claimed Capability (MW) reduction value from active Demand Response Resources was 200 MW for this informational analysis

19. Operating Procedure-4 (OP-4) Action MW Revision 1 • Once dispatch requirements were met (energy and reserves) no additional resources were dispatched • If energy and reserves were not met, OP-4 Action During a Capacity Deficiency actionswere applied to relieve system stress during the analysis

20. Discussion OF Refreshed Variable INPUTS TO FCA 13 Mystic 8 & 9 Analysis

21. Imports, LNG Injections, and Dual-Fuel Resource Tank Inventory • As described in PP10-I Section B, several inputs were varied by specific amounts to reflect system sensitivities in the informational analysis and to create the set of scenarios studied • Imports • The total net flow into New England across the New York- New England (NY-NE), New Brunswick – New England (NB-NE), and Hydro-Quebec – New England (HQ-NE) Interfaces was set at 2,800 MW, 3,000 MW, and 3,500 MW and tested as separate scenarios in this analysis • LNG Injections • The total LNG injected into the pipeline transmission system by the region’s three available LNG facilities (Canaport, Distrigas, and Buoy) was set at 0.8 Bcf, 1.0 Bcf, and 1.2 Bcf and tested as separate scenarios in this analysis • Dual-Fuel resource tank inventory • This will be a multiplier for the onsite fuel-storage tank of the individual resource and was set at 1.25 and 2 and tested as separate scenarios in this analysis

22. Discussion of Refreshed Output Metrics TO FCA 13 Mystic 8 & 9 Analysis

23. Scenario Outputs • The informational analysis results documented the following metrics per scenario as described in PP10-I, Section E • OP-4 Action 1 MWh • OP-4 Action 1 Hours • OP-4 Actions 2-5 MWh • OP-4 Actions 6-11 MWh • 10 - Minute Reserve Depletion MWh • 10 - Minute Reserve Depletion Hours • 10 - Minute Reserve Depletion less than 700 MW in Hours • OP-7 Action: Load Shedding MWh • OP-7 Action: Load Shedding Hours • OP-7 Action: Load Shedding Individual Days • Hourly curves profiling MWh of OP-4 and OP-7 were also documented

24. Trigger Criteria • As described in Appendix L of Section III of the Tariff, the following multi-prong trigger criteria was applied in the informational refresh analysis: • The retirement will result in the depletion of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one liquefied natural gas supply scenario case or, • The use of load shedding in any hour pursuant to Operating Procedure No. 7

25. Scenario Outputs Summary90/10 Winter 2022/2023 Peak Load • The informational refresh analysis showed that both of the triggers are exceeded over several different scenarios in the 90/10 peak load assessment

26. Scenario Outputs Summary90/10 Winter 2022/2023 Peak Load Hourly Curve Profile Additional 90/10 peak load hourly curve profiles are provided in Appendix I

27. Scenario Outputs Summary50/50 Winter 2022/2023 Peak Load • The informational refresh analysis showed that both of the triggers are also exceeded over several different scenarios in the 50/50 informational peak load assessment too • As noted in PP10, Appendix I, Section 2.3.1 the 50/50 peak load analysis is informational and would not be used for unit retention determinations

28. Scenario Outputs Summary50/50 Winter 2022/2023 Peak Load Hourly Curve Profile Additional 50/50 peak load hourly curve profiles are provided in Appendix II

29. Comparison of Mystic Retirement Study and the Informational Refresh Input Variables Revision 1: New Slide • In response to a stakeholder’s request, below is a comparison of the static and variable input assumptions that changed from the Mystic Retirement Study to the informational refresh

30. Comparison of Mystic Retirement Study and the Informational Refresh Output Metrics Revision 1: New Slide • In response to a stakeholder’s request, below is a comparison of the output metrics for some of the scenarios ran for the Mystic Retirement Study and the informational refresh

31. Conclusion • The ISO discussed the application of revised fuel-security analysis assumptions documented in PP10-I by refreshing the FCA 13 Mystic 8 & 9 analysis, similar to what was filed with the Commission in August • A FCA 14 fuel-security reliability review for the Mystic 8 & 9 Retirement De-list Bids will be performed in 2019. Discussion of the inputs to that analysis will be discussed during the first quarter of 2019 with the Reliability Committee

32. Norman Sproehnle (413) 540-4755 | NSPROEHNLE@iso-ne.com

33. APPENDIX I Hourly Curve Profiles for 90/10 Peak Load

34. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 2,800 MW – Tank Inventory 1.25

35. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 3,000 MW – Tank Inventory 1.25

36. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 3,500 MW – Tank Inventory 1.25

37. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 2,800 MW – Tank Inventory 2

38. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 3,000 MW – Tank Inventory 2

39. Hourly Curve ProfileLoad 90/10 – LNG 0.8 Bcf – Imports 3,500 MW – Tank Inventory 2

40. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 2,800 MW – Tank Inventory 1.25

41. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 3,000 MW – Tank Inventory 1.25

42. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 3,500 MW – Tank Inventory 1.25

43. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 2,800 MW – Tank Inventory 2

44. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 3,000 MW – Tank Inventory 2

45. Hourly Curve ProfileLoad 90/10 – LNG 1.0 Bcf – Imports 3,500 MW – Tank Inventory 2

46. Hourly Curve ProfileLoad 90/10 – LNG 1.2 Bcf – Imports 2,800 MW – Tank Inventory 1.25

47. Hourly Curve ProfileLoad 90/10 – LNG 1.2 Bcf – Imports 3,000 MW – Tank Inventory 1.25

48. Hourly Curve ProfileLoad 90/10 – LNG 1.2 Bcf – Imports 3,500 MW – Tank Inventory 1.25

49. Hourly Curve ProfileLoad 90/10 – LNG 1.2 Bcf – Imports 2,800 MW – Tank Inventory 2

50. Hourly Curve ProfileLoad 90/10 – LNG 1.2 Bcf – Imports 3,000 MW – Tank Inventory 2