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AUGUST 8, 2019|westborough, ma

AUGUST 8, 2019|westborough, ma. Marianne Perben. Detailed Assumptions. 2019 Economic Studies. Three Economic Study Requests Were Made in 2019. Three requests for an Economic Study were submitted to the ISO in 2019

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AUGUST 8, 2019|westborough, ma

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  1. AUGUST 8, 2019|westborough, ma Marianne Perben Detailed Assumptions 2019 Economic Studies

  2. Three Economic Study Requests Were Made in 2019 • Three requests for an Economic Study were submitted to the ISO in 2019 • Requests were submitted by the New England States Committee on Electricity (NESCOE), Anbaric Development Partners (Anbaric) and RENEW Northeast (Renew) • Presented to the PAC on April 25, 2019 • Draft scope of work and high-level assumptions for each of these requests were discussed with the PAC on May 21, 2019 • Today the ISO is seeking PAC input on the detailed study assumptions

  3. BACKGROUND and GENERAL ASSUMPTIONS

  4. Summary: NESCOE and Anbaric Scenarios Will Model Varying Degrees of Resource Expansions

  5. The NESCOE and Anbaric Scenarios Will Model Different Transmission Expansion Options *Some 345 kV reinforcement/expansion may still be needed for this scenario. This anticipation is preliminary (system impact studies have not been completed for all of these MW). This anticipates minimal interconnection at nameplate levels and capacity interconnection at intermittent capacity values – does not anticipate all of the MW being able to run simultaneously at nameplate levels at all times on the system. Possible off-shore wind additions* (MW and location) Mystic (MA): 1,200 MW Bourne/Canal/Pilgrim (MA): 2,400 MW Brayton Point (MA): 1,600 MW Montville (CT): 800 MW Kent County/Davisville (RI): 1,000 MW • The transmission system will be modeled using 2030 internal transmission-interface transfer capabilities • Based on the currently expected transmission system for 2030, the ISO anticipates that the following levels of off-shore wind additions (approximately 7,000 MW) have the potential to avoid major additional 345 kV reinforcements* • This assumes FCA 13 retirements have occurred, including the retirement of Mystic 8 & 9

  6. The NESCOE and Anbaric Scenarios Will Model Varying Degrees of Transmission Expansions, cont. #1: Direct injection into K Street #2: 345 kV reinforcements from the Cape to Stoughton/K. Street #3: 345 kV reinforcements from Brayton Point to Millbury/West Medway/West Walpole #4: 345 kV reinforcements between Montville and Kent County • Off-shore wind additions above 7,000 MW as shown on the prior slide would require: • Additional large units to be assumed retired in areas of new injections; and/or • Potential need for significant transmission reinforcements, as shown below • The ISO will need to assess the allowable level of injections of the assumed transmission reinforcements

  7. The NESCOE and Anbaric Scenarios Will Model Varying Degrees of Transmission Expansions, cont. • The NESCOE_2000 through NESCOE_6000 scenarios will be run without significant assumed transmission reinforcements • The NESCOE_8000 scenario will be run assuming each of the four transmission reinforcements shown on the prior slide • High-level assumptions will be made regarding the level of increases in transfer capability provided by each assumed transmission reinforcement • SEMA/RI export (assumed transmission reinforcements #2, #3, and #4) • West-East/East-West (assumed transmission reinforcement #4) • For the Anbaric scenarios, off-shore wind additions beyond 7,000 MW will utilize the additional assumed transmission reinforcements (#1 through #4) shown on the prior slide

  8. The NESCOE and Anbaric Scenarios Will Model Varying Off-Shore Wind Injection Locations Values shown in MW

  9. The NESCOE and Anbaric Scenarios Will Model Varying Degrees of Transmission Expansions, cont. • Off-shore wind additions will be modeled to cover areas off the coast of Rhode-Island and Southern Massachusetts that are close to the areas that have been auctioned by the Bureau of Ocean Energy Management (BOEM) • Based on National Renewable Energy Laboratory (NREL) data, those are the sites with the highest capacity factor

  10. The Renew Scenarios Will Model Varying Degrees of Increases in Orrington-South Transfer Capabilities • The transmission system will be modeled using 2025 internal interface transfer capabilities, with the exception of the Orrington-South interface • The base scenario will assume modified 2016 transfer limits provided by Renew • Scenarios 1 and 2 will assume increases in transfer limits • In scenario 1, the increase in operating limits requested by Renew ranges from 0 to 170 MW from the assumed modified 2016 transfer limits • In scenario 2, the increase in operating limits requested by Renew ranges from 100 to 825 MW from the assumed modified 2016 transfer limits • The analysis will be performed in two ways: with and without the interfaces downstream of Orrington-South being modeled at the transfer limits assumed for 2025

  11. All Three Economic Studies Will Include Production Cost Simulations • For all three studies, simulation runs will be performed using the ABB GridView Production Simulation Model • Generation production simulation using pipe and bubble format • Additional analyses will be developed to further address fuel security concerns (Anbaric’s request) and operating reserve requirement concerns (NESCOE’s request) • The ISO is still researching how to best arrive at these answers

  12. BHE ME NOR WMA CT SME NH SEMA RI VT New England Pipe and Bubble Representation (MW)Existing Transmission Interfaces 2025 and 2030 To NB East – West 3,500/3,000 550 To Quebec To Quebec Highgate 100 NB - NE Capacity/Energy 700/1,000 1,200 S 0 W ME - NH 200 Surowiec South Orrington South 0 Phase II Import 0 To D Capacity/Energy 1,400/2,000 1,900 1,325 1,500 Total NY-NE (Excludes CSC) North – South 2,725 Southeast NE Import 5,700 1,400 1,400 Boston Import 5,700 To F Boston 800 800 CMA/ NEMA To G 600 To K 800 330 (CSC) 0 Connecticut Import (Excludes CSC) 3,400 Norwalk - Stamford 9,999 In SEMA/RI import/Export 1,800/3,400 SWCT 369 – 428 * Southwest CT Import 2,800 0 *Rating a function of unit availabilities and/or area loads. To K

  13. Internal Transmission Interface Limits (MW) • The internal transmission interface limits for 2025 will also be used for 2030 • N-1 limits will be used in the 2019 Economic Studies • The table notes are shown in Appendix I • https://www.iso-ne.com/static-assets/documents/2019/03/a8_fca14_transmission_transfer_capabilities_and_capacity_zone_development.pdf

  14. External Transmission Interface Limits (MW) • The internal transmission interface limits for 2025 will also be used for 2030 • N-1 limits will be used in the 2019 Economic Studies • The table notes are shown in Appendix I https://www.iso-ne.com/static-assets/documents/2019/03/a8_fca14_transmission_transfer_capabilities_and_capacity_zone_development.pdf

  15. GENERIC PRODUCTION COST assumptions

  16. Common Assumptions For All Three Requests • FCM and energy-only generators will be modeled at their Seasonal Claimed Capability consistent with CELT 2019 values • These capabilities will be reduced to reflect potential forced outages • All other demand and supply variables will be modeled through the use of specific profiles, as discussed on the following section • For each scenario, an assessment will be performed to confirm that the anticipated Net Installed Capacity Requirement (NICR) will be met • The NICR will be derived using the expected reserve margin from the 2028 representative Installed Capacity Requirement (13.7%) • If additional supply is needed, a representative Natural Gas Combined Cycle will be added; in scenarios with larger amounts of retirements (Anbaric), the amount of retirements will be reduced until the NICR is met • Fuel prices for coal, oil, and natural gas will be based on recent forecasts from the Energy Information Administration (EIA) for New England • Emission allowance prices for carbon dioxide, sulfur dioxide and nitrogen oxide will be reflected for fossil-burning generation units • The ISO will review the need to update the assumptions used in the most recent Economic Studies

  17. Capacity in All Scenarios Exceeds Assumed NICR (MW) • Assumed off-shore wind additions suffice to exceed assumed NICR in all scenarios

  18. Resource Retirements – All Scenarios • Existing resource retirement in accordance with FCA 13 results and the assumed retirement of Mystic 8 & 9 • Additional retirements modeled in the Anbaric scenarios • 2,000 MW of nuclear generation • Generation at Seabrook and Millstone reduced by a total of 2,000 MW, proportionally to their Seasonal Claimed Capability • Oil units in Connecticut and Maine • All remaining coal units are located in New Hampshire

  19. Coal, Oil, and Natural Gas Fuel Prices • Based on 2019 EIA Annual Energy Outlook fuel price forecast for New England • Same method as prior Economic Study models • Natural gas prices are increased 10% over the nominal price in the winter and reduced 10% of the nominal price in the summer • Reflect the EIA Appendix prices for New England coal, oil, and natural gas • Exception: the EIA is forecasting that all coal units in New England will be retired by the year 2024 and therefore the AEO is showing 0$ coal prices starting with year 2024 • The Economic Studies will assume that the 2023 prices will be maintained in years 2024 through 2030 • See following slides for details

  20. Fuel Price Forecast: EIA’s 2019 AEO Base Forecast

  21. Fuel Price Forecast: Per Unit Multiplier for Monthly Natural Gas Price Assumptions (2025 and 2030) Winter (Nov-Feb): 1.1 Summer (Jun-Aug): 0.9

  22. Environmental Emissions Allowances Assumptions • Future Environmental Air Emission Allowances Prices • 2025 • NOX = $18.87 /ton • SO2 = $18.87 /ton • CO2 = $8.00 /ton • 2030 • NOX = $ 6.18 /ton • SO2 = $ 6.18 /ton • CO2 = $24.00 /ton • To reflect the impact of the Massachusetts Global Warming Solutions Act (GWSA), $2 will be added to the CO2 emission allowance price for affected fossil fuel generators located in Massachusetts • CO2 emissions for Massachusetts affected fossil fuel generators will also be monitored exogenously to confirm that they meet the GWSA cap

  23. Production Cost Operating Reserve Modeling • GridView production cost analysis models operating reserve requirement • Modeled similar to previous studies • The spinning reserve is 120% of the first contingency • Offshore wind interconnections respect 1,200 MW loss of source limit • Individual transmission interconnections to shore have a maximum value of 1,200 MW

  24. Active Demand Resources • Active DR (Real-Time DR) assumptions are based on FCA 13 results • The active DR will be modeled dispatchable, as was done in prior studies • First 100 MW dispatched at $50/MWh • Remainder at $500/MWh

  25. PROFILES-BASED assumptions

  26. Many Resources May Be Represented by Profiles • Many resources cannot be dispatched using production cost • Some technologies have zero or “indeterminate” production cost • Can be “curtailed” using assumed “threshold” prices • Some resource profiles can be developed to • Peak-shave and valley-fill loads • Levelize loads • The following section addresses in detail the modeling of profile-based resources

  27. Common Profiles To Be Considered in All Three Requests • Although stakeholders requested 2015 load shapes with compatible off-shore, on-shore wind, and photovoltaic profiles, the ISO is not currently able to model dependable off-shore wind profiles for the year 2015 as initially planned • The ISO is examining alternatives to recreate 2015 profiles and will keep the PAC informed of our progress with the next update • In the mean time, the ISO will run preliminary analysis using readily available 2006 profiles for load and wind and PV resources developed with methods used in the 2016 and 2017 Economic Studies • External energy delivery transfers (imports) on existing external ties will be modeled using historical diurnal profiles, averaged over the last three years (2016 through 2018) • A profile for local New England hydroelectric generation (hydros) will be developed that shifts their energy production to the higher net load hours

  28. Draft Common Profiles To Be Considered in All Three Requests, cont. • Plug-in hybrid electric vehicles (PHEVs) profiles will be developed that reflect currently known PHEV charging patterns • In prior studies, a profile for the charge and discharge of storage facilities was designed to flatten the net load profile after all other profiles have been accounted for (BTM and non-BTM PV, wind, imports, hydro, and PHEVs) • The ISO is examining the possible use of the GridView storage functionality where the storage will be dispatched to minimize production cost • For scenarios/sensitivities with additional electric demand from heat pumps, a profile will be developed to model the behavior of the heat pumps on heating days

  29. 2025 and 2030 Gross Load, EE, and BTM PV Forecasts • The model will reflect separate MW values for gross peak load, EE, and PV with locations that are consistent with the 2019 CELT • Simulations for the year 2025 will reflect the gross peak load, EE, and PV quantities summarized in the 2019 CELT • Quantities for 2030 can be determined using previous methodologies and 2019 CELT quantities • 2030 values (peak, EE, and PV) can be calculated using the 2019 CELT values for 2028 and growing them to the year 2030 using data from 2027 and 2028 • Example: For 2030 Peak Load: the 50-50 gross peak of 2028 x [(50-50 gross peak of 2028/50-50 gross peak of 2027)2] • Example: For 2030 EE and PV: total value for the year 2028 + [incremental growth for the year 2028 x 2]

  30. Gross New England 50/50 Peak and Annual Energy Demand (a) Gross 50/50 Peak calculation for 2030 = 30,831 MW x (30,831 MW/30,616 MW)2 = 31,266 MW (b) Gross Annual Energy calculation for 2030 = 161,312 x (161,312 GWh/158,999 GWh)2 = 166,039 GWh

  31. Energy Efficiency Reductions in Peak Load and Energy • The same amounts of Energy Efficiency added in 2028 (138 MW of peak load reduction and 978 GWh of energy reduction) are assumed to be added annually through 2030 • Capacity value for the year 2030 = 5,372 MW + [138 MW x 2] = 5,648 MW • Energy value for the year 2030 = 34,754 GWh + [978 GWh x 2] = 36,710 GWh

  32. Behind the Meter Photovoltaic (BTM PV) • The same amounts of BTM PV added in 2028 (178 MW of nameplate reduction and 10 MW of peak load reduction) are assumed to be added annually through 2030 • Nameplate value for the year 2030 = 4,150 MW + [178 MW x 2] = 4,506 MW • Peak load reduction value for the year 2030 = 1,051 + [10 MW x 2] = 1,071 MW

  33. Behind the Meter Photovoltaic (BTM PV), cont.

  34. Utility Scale PV • In-front-of-the-meter or utility scale PV includes FCM PV and energy-only PV • The amount of FCM PV will be maintained constant through the years • Based on FCA 13 amount • The same amounts of energy-only PV added in 2028 (106 MW of nameplate reduction) is assumed to be added annually through 2030 • Nameplate value for the year 2030 = 2,141 MW + [106 MW x 2] = 2,353 MW

  35. Interchange with Neighboring Systems • Use energy profiles for Quebec and the Maritimes with a methodology similar to the 2017 Economic Studies • Simulate imports as price takers that never set the clearing price • Assume import threshold prices for curtailments • Described in detail in later slide • Assume no interchange with New York • Cross Sound Cable (CSC) • NY AC interconnections

  36. Interchange with Neighboring Systems * Import capability for energy **Assuming no interchange allows to perform a straight comparison of the region production cost across all scenarios

  37. PHEVs Will Be Included in All of the NESCOE Scenarios and the Anbaric Sensitivity • A total of 550,000 PHEVs will be modeled in the NESCOE scenarios and the Anbaric sensitivity • Locations will be distributed by state, utilizing the same distribution that was used in the 2016 Economic Study • 43% in MA • 23% in CT • 12% in ME • 11% in NH • 6% in RI • 5% in VT • No discharge/generation back into the grid will be assumed

  38. PHEVs Characteristics • Analysis by NREL suggests that PHEV charging tends to start in the later part of the day and continue into the night • The ISO is proposing to modify the daily PHEV charging profile it used in the 2016 Economic Study to reflect this shift in the charging period • Charging ramps-up between 4 pm and midnight

  39. Storage May be Modeled to Minimize Production Cost • In prior Economic Studies, storage had been modeled through the use of a profile that equalized the daily high and low loads after all profile-based resources had been utilized • Stakeholders raised the concern that this type of profile resulted in excessive cycling • For this economic study, the ISO is examining the use of GridView’s storage functionality which seeks to dispatch storage to minimize production cost • Battery storage and pump storage will be modeled with different efficiencies • 74% efficiency for pump storage • 90% efficiency for battery storage • The NESCOE and the Anbaric scenarios will assume a different locations for battery storage • The NESCOE scenarios will model amounts of storage distributed across New England proportionally to the load • The Anbaric scenarios will model amounts of storage at the off-shore wind injection points, proportionally to the level of injection

  40. Heat Pumps Will Be Included in All of the NESCOE Scenarios and the Anbaric Sensitivity • 2,050 MW assumed based on 10 percent of the peak that occurred in December 2017 • A profile will be developed through the following steps • Assumed that a typical April day had no heating loads • Developed a typical April diurnal load shape (i.e. “no-heat” ) • Subtracted the assumed “no-heat” daily profile from all days • Residual positive loads assumed to be daily “heating energy” • Allocated additional “heating energy” from heat pumps to those residual positive loads • Non/Low Heating Days • Zero impact on summer peak loads assumed because increased air conditioning loads could be offset by additional penetration of groundwater heat pumps

  41. Threshold Prices Will Be Used to Decrease Production of $0/MWh Resources When There is Oversupply in All Three Requests • The studies will use similar threshold prices as have been used in prior Economic Studies (2016 and 2017), with two adjustments: • The behind-the-meter PV and utility scale PV will now be differentiated • A threshold price will be added to reduce firm energy delivery from the NECEC tie • These threshold prices are used to facilitate the analysis of load levels where the amount of $0/MWh resources exceeds the system load • They are not indicative of “true” cost, expected bidding behavior or the preference for one type of resource over an other

  42. load shape Impact of Profile-based Resources

  43. Load Shape Impact of Profile-Based Resources • The following slides will depict the impact of the sequential load shape adjustments caused by the profile-based resources • Actual market dynamics will be far more complex than the sequential adjustments shown here in the following example • The following slides are for illustration purpose only; they do not consider potential spilling or curtailment, or the triggering of the threshold prices • For illustration-only, the ISO is using profiles to depict the impact of storage • As explained earlier in this presentation, the ISO is examining the use of GridView’s storage functionality for the actual analysis

  44. Component Load Profiles

  45. Initial Loads

  46. Additional Loads From PHEV Technology

  47. Additional Loads From Heat Pump Technology

  48. Initial Loads with PHEV

  49. Total Loads with PHEV and Heat Pumps

  50. Individual Resource Profiles

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