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Power Supply Planning Committee August 9, 2019 | holyoke , MA

Power Supply Planning Committee August 9, 2019 | holyoke , MA. Peter Wong and Fei Zeng Resource studies and assessments. Including and Excluding Mystic Units 8 & 9 Scenarios. Proposed Installed Capacity Requirement for the Fourteenth Forward Capacity Auction (FCA 14). Acronyms.

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Power Supply Planning Committee August 9, 2019 | holyoke , MA

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  1. Power Supply Planning Committee August 9, 2019 | holyoke, MA Peter Wong and Fei Zeng Resource studies and assessments Including and Excluding Mystic Units 8 & 9 Scenarios Proposed Installed Capacity Requirement for the Fourteenth Forward Capacity Auction (FCA 14)

  2. Acronyms • ARA – Annual Reconfiguration Auction • BTM PV – Behind-the-meter Photovoltaic • FCA – Forward Capacity Auction • CCP – Capacity Commitment Period • CSO – Capacity Supply Obligation • CELT – Capacity, Energy, Loads and Transmission • CT – Connecticut • DR – Demand Resource • EE – Energy Efficiency • EFORd – Equivalent Forced Outage Rate on Demand • FCA – Forward Capacity Auction • FERC – Federal Energy Regulatory Commission • HQICCs – Hydro-Quebec Interconnection Capability Credits

  3. Acronyms, cont. • ICR – Installed Capacity Requirement • ISO – ISO New England • LRA – Local Resource Adequacy • LSR – Local Sourcing Requirement • MCL – Maximum Capacity Limit • MRI – Marginal Reliability Impact • NEPOOL – New England Power Pool • Net ICR – ICR minus HQICCs • NPCC – Northeast Power Coordinating Council • OP-4 – Operating Procedure No. 4, Action During a Capacity Deficiency • PC – Participants Committee • PSPC – Power Supply Planning Committee • RC – Reliability Committee • TSA – Transmission Security Analysis

  4. Background • The calculation of ICR-Related Values* is conducted pursuant to Section III.12 of the Tariff • In November 2018, the ISO, joined by NEPOOL, filed with FERC proposed revisions to two assumptions used in the calculation of ICR-Related Values: • Change the modeling of load relief assumed obtainable through the implementation of 5% voltage reduction action of OP-4 from 1.5% of the 90/10 peak to 1.0% • Modify the unavailability of peaking generation resources in the TSA from a 20% deterministic adjustment factor to be the units’ EFORds • FERC accepted the proposed revisions in a January 8, 2019 letter order and the revised assumptions are used in the ICR-Related Values calculations for the FCA for the CCP 2023-2024 (FCA14) and ARAs that will be conducted in 2020 *The ICR, TSA, LRA, LSR, MCL, Demand Curve values and the HQICCs are collectively referred to as the ICR-Related Values

  5. Background, cont. • Mystic Units 8 & 9 were retained for fuel security in FCA 13 • Exelon elected to continue to operate for CCP 2022-2023 • For FCA 14, Mystic Units 8 and 9 are needed for fuel security, and Exelon again has the option to unconditionally retire prior to FCA 14 • Exelon has until January 10, 2020 to decide whether to retire or continue to operate for CCP 2023-2024 • The ISO will develop and file with FERC two sets of ICR-Related Values due to the timing of Exelon’s retirement decision for Mystic Units 8 & 9 • Similar to how ICR-Related Values were developed and filed at FERC with and without Clear River Unit 1 in FCA 13 • “Including Mystic Units 8 & 9” and “Excluding Mystic Units 8 & 9” scenarios • In January 2020, it is anticipated it will be clearer which FCA 14 ICR-Related Values will be used in the FCA • Pending Exelon’s retirement decision on January 10, 2020 • Pending FERC’s approval of the ICR-Related Values in mid-January 2020

  6. Objective of this Presentation • Review the ICR values for the two Mystic Units 8 & 9 scenarios • Review the impact of the 2019 CELT Report load forecast on ICR* • Review the FCA 14 ICR-Related Values review schedule *Impact of assumption changes on ICR including and excluding Mystic Units 8 & 9 will be presented at the August 29 and September 9 PSPC meetings, respectively

  7. ICR for FCA 14 Including and Excluding Mystic Units 8 & 9 Scenarios

  8. ICR Calculation Details Including Mystic Units 8 & 9 • Notes: • All values in the table are in MW except the reserve margin shown in percent • ALCC is the “additional load carrying capability” used to bring the system to the target reliability criterion • APk is the forecast 50/50 peak load

  9. ICR Calculation Details Excluding Mystic Units 8 & 9 • Notes: • All values in the table are in MW except the reserve margin shown in percent • ALCC is the “additional load carrying capability” used to bring the system to the target reliability criterion • APk is the forecast 50/50 peak load

  10. IMPACT OF Changes to the Load Forecast Methodology on ICR for FCA 14

  11. 2019 Gross Load Forecast Changes For the study period of CCP 2023-2024, the 2019 load forecast* model for ICR calculations has incorporated the following component changes as compared to the 2018 load forecast • Forecast Cycle (Vintage) Change • This would be the normal forecast change as done in the past • Underlying input assumptions seen in 2019 vs 2018 • Model estimation period – daily peak load and weather for the historical period covering 2004-2018 (2003-2017 used last year) • 2019 Changes to the methodology of the load forecast model • Added a Second Weather Variable (Modeling Specification) • Incorporated a second weather variable, cooling degree days (CDD), in addition to weighted temperature-humidity index (WTHI) • Separated July and August Peak Modeling (Monthly Peak Demand Modeling) • Developed separate July and August monthly models rather than a combined July/August summer seasonal peak model • Shortened Weather History (Weather History Change) • Historical weather period used to generate probabilistic forecast shortened from 40 years to 25 years • New 25-year period covers 1991-2015 (1975-2014 used last year) *For details of the 2019 load forecast, please see Review of the 2019 Long-Term Load Forecast presentation at: https://www.iso-ne.com/static-assets/documents/2019/07/20190725_a03_2019_longterm_forecasts_icr.pptx For details on the load forecast methodologies and assumptions, please see: https://www.iso-ne.com/committees/reliability/load-forecast/

  12. Analysis to Identify Impact on ICR associated with the Changes in Load Forecast Methodology The following simulations were conducted using a common set of resource assumptions developed for FCA 14 ICR calculations for scenario that includes Mystic Units 8 & 9 to identify the impact of each of the methodology changes to the gross load forecast model for the CCP 2023-2024: 2018 Case • Calculate the ICR using the 2018 CELT gross load forecast for the CCP 2023-2024 Forecast Cycle Case • Calculate the ICR with the same load forecast modeling methodology as used to develop the 2018 CELT gross load forecast • Updated underlying input assumptions associated with the 2019 CELT forecast • Revised daily peak load and weather model estimation period • Used 2004-2018 instead of the 2003-2017 period used in the 2018 CELT load forecast

  13. Analysis to Identify Impact on ICR associated with the Changes in Load Forecast Methodology, cont. Second Weather Variable Case • Using the Forecast Cycle Case input assumptions modify the gross load forecast based on incorporating a second weather variable, cooling degree days (CDD), in addition to the weighted temperature-humidity index (WTHI) Separate July and August Peak Load Model Case • Using the Forecast Cycle Case input assumptions modify the gross load forecast developed by using separate July and August monthly peak models rather than a combined July/August summer seasonal peak model Shorter History Weather Period Case • Using the Forecast Cycle Case input assumptions modify the gross load forecast developed based on a shorter historical weather period, from 40 years to 25 years, to generate the probabilistic forecast. The new 25-year period covers 1991 through 2015 instead of the 40-year (1975 through 2014) period used in the 2018 CELT load forecast

  14. Analysis to Identify Impact on ICR associated with the Changes in Load Forecast Methodology, cont. Methodology to Obtain Impact of Individual Changes • The impact of the forecast cycle change is obtained by comparing the ICR of the 2018 Case with the ICR of the Forecast Cycle Case • The impact of each component change to the load forecast methodology is obtained by comparing the ICR of each case with and without the change

  15. Estimated Impacts on ICR due to 2019 Gross Load Forecast Changes

  16. FCA 14 ICR Values Summary and Observations

  17. Summary and ObservationsFCA 14 ICR Results • Summary of ICR scenarios • Due to the size of the Mystic Units 8 & 9 and their availability relative to the availability of the system resources mix, including Mystic Units 8 & 9 would increase the system ICR • However, tie benefits including Mystic Units 8 & 9 is 30 MW higher than excluding them, resulting in an overall decrease of system ICR • The net difference in ICR and net ICR between the two Mystic Units 8 & 9 scenarios are 7 MW and 5 MW, respectively • Higher ICR and net ICR when Mystic Units 8 & 9 are excluded from the system

  18. Summary and ObservationsImpact of Load Forecast Methodology on ICR • If the forecast methodology were not changed and a new load forecast is developed for the 2023-2024 CCP with the underlying forecast assumptions updated, the net ICR would have been 300 MW lower as compared with the net ICR simulated using the 2018 CELT gross loads for 2023-2024 • The change in load forecast methodology that most impacted the net ICR is the addition of a second weather variable to the methodology • It decreased the net ICR by 855 MW • A shorter historical period lowered the net ICR by 140 MW • A separate monthly peak load model for July and August increased the net ICR by 45 MW as compared with using a combined July/August peak period model

  19. FCA 14 ICR-Related values development schedule

  20. FCA 14 ICR-Related Values Development Schedule • ICR-Related Values for FCA 14 (2023-2024)

  21. Appendix I Assumptions for the FCA14 ICR-Related Values Calculations

  22. Modeling the New England Control Area for FCA 14 • The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related Values • Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus • Internal transmission constraints are addressed through the LSR and MCLs • A LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA and RI Load Zones • MCLs will be calculated for two export-constrained Capacity Zones. The Maine Capacity Zone and the Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New Hampshire and Vermont • The Maine Capacity Zone will be nested in the NNE Capacity Zone • The MRI based method for calculating demand curves will be used to develop System and Capacity Zone Demand Curves

  23. Cost of New Entry (CONE) - for the MRI Demand Curve • CONE for the cap of the MRI system Demand Curve for FCA 14 has been calculated as: • Gross CONE: $11.472/kW-month • Net CONE : $8.187/kW-month • FCA Starting Price : $13.099/kW-month • See link to Forward Capacity Market (FCM) parameters by Capacity Commitment Period:https://www.iso-ne.com/static-assets/documents/2015/09/FCA_Parameters_Final_Table.xlsx

  24. Assumptions for the ICR-Related Values Calculations • Load forecast • Net of behind-the-meter (BTM) photovoltaic (PV) forecast • Load forecast distribution • Resource data will be based on qualified existing capacity values for FCA 14 • Generating Capacity Resources • Intermittent Power Resources (IPR) • Import Capacity Resources • Active Demand Capacity Resources (ADCR) • These qualified capacity values reflect • The significant decrease of existing qualified resources • The resource retirements and terminations • The unconditional Permanent and Retirement De-List Bids and • Permanent De-List Bids that are at or above the FCA 14 Starting Price

  25. Assumptions for the ICR-Related Values Calculations, cont. • Resource availability • Generating Capacity Resources availability • IPR availability • ADCR availability • Load relief from Operating Procedure No. 4, Action During a Capacity Deficiency (OP-4) actions • Tie reliability benefits • Quebec • Maritimes • New York • 5% voltage reduction

  26. Load Forecast Data • Load forecast assumption from the 2019 Forecast Report of Capacity, Energy, Loads and Transmission (CELT) load forecast* • The load forecast weather-related uncertainty is represented by specifying a series of multipliers on the peak load and the associated probabilities of each load level occurring • The multipliers used to describe the load forecast uncertainty are derived from the 52 weekly peak load distributions described by the expected value (mean), the standard deviation and the skewness *The 2019 CELT load forecast is available at https://www.iso-ne.com/system-planning/system-forecasting/load-forecast/

  27. Load Forecast Data, cont.Modeling of BTM PV • FCA 14 ICR calculations will use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static-assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdf • Used for all probabilistic ICR-Related Values calculations • Modeled in GE MARS by Regional System Plan (RSP) 13-subarea representation • Includes an 8% transmission and distribution gross-up • Peak load reduction uncertainty is modeled (randomly selected by MARS from a seven day window distribution) • The values of BTM PV published in the 2019 CELT Report are the values of BTM PV subtracted from the gross load forecast to determine the net load forecast • The published 90/10 net load forecast for the SENE sub-areas is used in the TSA Notes: For more info on the PV forecast, see https://www.iso-ne.com/static-assets/documents/2019/04/final-2019-pv-forecast.pdf

  28. Load Forecast Data, cont. New England System Load Forecast Monthly Peak Load (MW) - Net of BTM PV Probability Distribution of Seasonal Peak Load (MW) • Corresponds to the reference forecast labeled “ISO-NE Control Area &New England States Monthly Peak Load Forecast“ from worksheet “4 Mnth Peak” of the 2019 Forecast Data • https://www.iso-ne.com/static-assets/documents/2019/04/forecast_data_2019.xlsx There is a distribution associated with each monthly peak. The distribution associated with the seasonal peak load forecast is shown below: • From Table 1.6 - Seasonal Peak Load Forecast Distributions (forecast is reference with reduction for BTM PV) of the 2019 CELT • https://www.iso-ne.com/static-assets/documents/2019/04/2019_celt_report.xls

  29. Resource Data – Generating Capacity Resources (MW) Including Mystic Units 8 and 9 • Qualified Existing Generating Capacity Resources for FCA 14 Reflect • Significant decreases • The resource retirements and terminations • The unconditional Permanent and Retirement De-List Bids and • Permanent De-List Bids that are at or above the FCA 14 Starting Price • Mystic 8 & 9 included in the values for NEMA/Boston and the system total. The simulation without these two units would reflect 1,413 MW lower in non-intermittent Generating Capacity Resources • Intermittent Power Resources (IPR) have both summer and winter values modeled; non-intermittent Generating Capacity Resources winter values provided for informational purpose

  30. Resource Data – Import Capacity Resources (MW) • Qualified Existing Import Capacity Resources for FCA 14 • The NYPA supplied Import Capacity Resources’ performance (availability) will be modeled with the performance assumptions associated with the New York AC ties

  31. Resource Data – Demand Resources (MW) • Qualified Existing Demand Resources for FCA 14 • Includes the 8% transmission and distribution loss adjustment (gross-up)

  32. Capacity Zone Resource and 50/50 Peak Load Forecast Assumptions Used in LRA and MCL Calculations (MW)Including Mystic Units 8 and 9 • An LRA requirement will be calculated for the SENE Capacity Zone; MCLs will be calculated for the Maine and NNE Capacity Zones • Zonal requirements will be determined using the load forecast and resource assumptions for the appropriate RSP sub-areas as the transmission transfer capability analysis will be performed using the RSP 14-bubbles for the import and export constrained interfaces • The 50/50 load forecast values for the Capacity Zones will be the sum of the appropriate RSP sub-areas and are shown for informational purposes • Note that the values are presented based on RSP subarea

  33. LRA, TSA & MCL Internal Transmission Transfer Capability Assumptions • Maine - New Hampshire Export • N-1 Limit: 1,900 MW • Northern New England Export (North-South interface) • N-1 Limit: 2,725 MW • Southeast New England Import • N-1 Limit: 5,700 MW • N-1-1 Limit: 4,600 MW *Based on transmission transfer capability limits presented at the March 20, 2019 Reliability Committee meeting. The presentation is available at: https://www.iso-ne.com/static-assets/documents/2019/03/a7_fca_14_transmission_transfer_capabilities_and_capacity_zone_development.pdf

  34. Availability Assumptions - Generating Capacity Resources • Forced outages assumption • Each generating unit’s Equivalent Forced Outage Rate on Demand (non-weighted EFORd) will be modeled • Based on a 5-year average (January 2014 – December 2018) of Generation Availability Data System (GADS) data submitted by generators • NERC GADS class average data will be used for immature/non-commercial units • Scheduled outage assumption • Each generating unit’s weeks of maintenance modeled • Based on a 5-year average (January 2014 – December 2018) of each generator’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance • NERC GADS class average data will be used for immature/non-commercial units

  35. Availability Assumptions - Generating Capacity Resources including Mystic Unitd 8 and 9 • Assumed summer MW weighted EFORd and maintenance weeks are shown by resource category for informational purposes. In the LOLE simulations used for determining ICR-Related Values, individual unit assumptions will be modeled.

  36. Availability Assumptions - IPR • Modeled as 100% available since their outages have been incorporated in their 5-year historical output used in calculating their Existing Qualified Capacity

  37. Availability Assumptions – Demand Resources • DR average performance percentages are applied to FCA 14 qualified Existing DR • Average of 2014 – 2018 historical summer and winter DR performance • Modeled as a forced outage rate of 1-performance in blocks by DR type and Load Zone • Historical DR performance assumed in ICR calculations • FCA 11 total New England DR modeled was 2,926 MW at 98% • FCA 12 was 3,211 MW at 98% • FCA 13 was 3,502 MW at 99%

  38. Availability Assumptions – Import Capacity Resources • System Import Capacity Resources • The forced and planned outage assumptions will be based on the availability assumptions associated with the transmission line used to import the capacity resource. The following table shows the availability assumptions updated for the external ties based on the new proposed methodology for developing external tie lines’ forced and scheduled outage rates: • Unit/plant Import Capacity Resources • The forced and planned outage assumptions will be based on the assumptions associated with the unit/plant supplying the import capacity

  39. Availability Assumptions – Tie Benefits • The tie benefits availability assumptions will be based on the availability assumptions associated with the external transmission linerecently updated using the newly proposed methodology • These are the same values used to model the performance of the Import Capacity Resources that are system based • They are repeated in this slide for clarity *Based on recently updated values using the newly proposed methodology presented at the March 30, 2019 Power Supply Planning Committee meeting. The presentation is available at: https://www.iso-ne.com/static-assets/documents/2019/05/a5_tie_line_availability_05302019.pdf

  40. OP-4 Assumptions Action 6 & 8 - 5% Voltage Reduction (MW) • Uses the 90-10 Peak load forecast minus BTM PV and all passive DR and ADCR • Multiplied by the 1.0% estimating relief obtainable from OP-4 voltage reduction

  41. OP-4 Assumptions, cont. Tie Benefits (MW) • Tie benefits are based on the results of the 2023-2024 tie benefits study. The assumptions and results of the study are discussed in a separate presentationthat can be accessed using the following link: https://www.iso-ne.com/static-assets/documents/2019/07/pspc_a05_tiebenefitswithandwithoutmystic89.pptx

  42. OP-4 Assumptions, cont. Minimum Operating Reserve Requirement (MW) • Minimum Operating Reserve will be the 10-Minute minimum Operating Reserve requirement for ISO Operations • Modeled at 700 MW in the ICR calculations

  43. Summary of all MW Modeled in the ICR Calculations Including Mystic 8 and 9 Notes: • TBD = To be determined • The tie benefits assumptions are updated based on the study • IPRs have both the summer and winter capacity values modeled • OP-4 voltage reduction includes both Action 6 and Action 8 MW assumptions. • Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO operations • Excluding the Mystic Units 8 & 9 would lower the total MW modeled by 1,443 MW and tie benefits would be 1,910 MW

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