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RC Meeting | Agenda Item August 13, 2012 |Rockport ME

RC Meeting | Agenda Item August 13, 2012 |Rockport ME. Includes Appendix of Assumptions. Installed Capacity Requirement (ICR) & Related Values for the 2016/17 Forward Capacity Auction (FCA7). Objective of this Presentation.

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RC Meeting | Agenda Item August 13, 2012 |Rockport ME

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  1. RC Meeting | Agenda Item August 13, 2012 |Rockport ME Includes Appendix of Assumptions Installed Capacity Requirement (ICR) & Related Values for the 2016/17 Forward Capacity Auction (FCA7)

  2. Objective of this Presentation • Review the proposed values, committee review and FERC filing schedules for the: • Installed Capacity Requirement (ICR), • Transmission Security Analysis (TSA), • Local Resource Adequacy Requirement (LRA), • Local Sourcing Requirement (LSR), and • Maximum Capacity Limit (MCL) • The ICR, LSR and MCL are collectively called the ICR Values

  3. ICR Review and FERC Filing Schedule • ICR Values for the 2016/17 Forward Capacity Auction (FCA7) • PSPC reviewed all assumptions – Jun 14 & Jul 31, 2012 • PSPC reviewed ISO recommendation of ICR Values – Jul 31, 2012 • RC review/vote of ISO recommendation of ICR Values – Aug 13, 2012 • PC review/vote of ISO recommendation of ICR Values – Sep 14, 2012 • File with the FERC – by Nov 2, 2012 • FCA7 conducted – Feb 4, 2013

  4. Proposed ICR Values for the 2016/17 FCA

  5. ISO Proposed ICR Values for the 2016/17 FCA (MW) * Total Resources consists of capacity resources used in the ICR Values calculation and excludes HQICCs for New England

  6. Comparison of ICR Values (MW) - 2016/17 Vs 2015/16 FCA * Total Resources consists of capacity resources used in the ICR Values calculation and excludes HQICCs for New England

  7. ICR Calculation Details • 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 0.1 Reliability Criterion.

  8. Effect of Updated Assumptions on ICR • Methodology: Begin with model for the 2015/2016 FCA ICR calculation. Change one assumption at a time and note the change in ICR caused by each change in assumption.

  9. CT & NEMA/Boston TSA Requirement (MW)

  10. 2015/16 – 2016/17 TSA Requirement Comparison (MW) • 2015/16 FCA TSA Requirement values were initially calculated and presented during the November 15, 2011 Reliability Committee Meeting.

  11. LRA- Connecticut • All values in the table are in MW except the FORz • Resources for Rest of New England excludes HQICCs

  12. LRA – NEMA/Boston • All values in the table are in MW except the FORz • Resources for Rest of New England excludes HQICCs

  13. MCL - Maine • All values in the table are in MW except the FORz • Resources for Rest of New England excludes HQICCs

  14. Assumptions for the 2016/17 FCA ICR Values Calculation

  15. Modeling the New England Control Area The New England ICR is calculated using the GE MARS model • Internal transmission constraints are not modeled. All loads and resources are assumed to be connected to a single electric bus. • Internal transmission constraints are addressed through Local Sourcing Requirements and Maximum Capacity Limits. • For FCA7, the following requirements are needed for the auction: • MCL for the Maine export-constrained Load Zone • LSR for the NEMA/Boston and Connecticut import-constrained Load Zones

  16. Assumptions for the ICR Calculations • Load Forecast • Load Forecast distribution • Resource Data Based on Existing Qualified Capacity Resources for FCA7 • Generating Capacity Resources • Intermittent Power Capacity Resources • Import Capacity Resources • Demand Resources (DR) • Resource Availability • Generating Resources Availability • Intermittent Power Resources Availability • Demand Resources Availability • Load Relief from OP 4 Actions • Tie Reliability Benefits • Quebec (includes HQICCs) • Maritimes • New York • 5% Voltage Reduction

  17. Load Forecast Data • Load forecast assumption from the 2012 CELT Report & 2012 Regional System Plan (RSP12) 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 • derived from the 52 weekly peak load distributions described by the expected value (mean), the standard deviation and the skewness.

  18. Load Forecast Data – New England System Load Forecast Probability Distribution of Annual Peak Load (MW) Monthly Peak Load (MW) – 50/50 Forecast There is a distribution associated with each monthly peak. The distribution associated with the Summer Seasonal Peak (July & August) is show below:

  19. Load Forecast Data – Comparison of RSP11 and RSP12 New England System Load Forecast Distribution Moments • The load forecast uncertainty is determined by the three moments of the distribution: the mean, standard deviation and skewness.

  20. Resource Data – Generating Capacity Resources (MW) • Existing Qualified generating capacity resources for FCA7 (Updated as of July 1, 2012 to account for terminations and Significant Increases and Decreases) • Intermittent resources have both summer and winter values modeled; non-Intermittent winter values provided for informational purpose

  21. Resource Data – Demand Resources (MW) • Existing Qualified Demand Resource capacity for FCA7 (Updated as of July 1, 2012 to account for terminations and Significant Increases and Decreases) • Includes the Transmission and Distribution (T&D) Loss Adjustment (Gross-up) of 8%.

  22. Resource Data – Import Capacity Resources (MW) • Existing Qualified Import capacity resources for FCA7 • System-backed imports modeled as 100% available • Total import forced outage rate weighted by Summer MW is 0.02% and Maintenance is 0.4 weeks

  23. Resource Data – Export Delist (MW) • Based on Administrative Delist Bid • Already accounted for as removed capacity from the resource supplying the export in the Generating Resources

  24. Availability Assumptions - Generating Resources • Forced Outages Assumption • Each generating unit’s Equivalent Forced Outage Rate on Demand (non-weighted EFORd) modeled • Based on a 5-year average (Feb 2007 – Jan 2012) of generator submitted Generation Availability Data System (GADS) data • NERC GADS Class average data is used for immature units • Scheduled Outage Assumption • Each generating unit weeks of Maintenance modeled • Based on a 5-year average (Jan 2007 – Dec 2011) of each generator’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance • NERC GADS Class average data is used for immature units

  25. Availability Assumptions - Generating Resources • Assumed summer MW weighted EFORd and Maintenance Weeks are shown by resource category for informational purposes. In the LOLE simulations, individual unit values are modeled.

  26. Availability Assumptions - Intermittent Power Resources • Intermittent Power Resources are modeled as 100% available since their outages have been incorporated in their 5-year historical output used in their ratings determination.

  27. Demand Resource Availability • Uses average of historical DR performance from summer 2010 and 2011 • Modeled by zone and type of DR with outage factor calculated as 1- performance/100

  28. Demand Resource MW & Availability – Comparison of FCA7 and FCA6 Assumptions • Passive Resources are modeled as 100% available for both FCA7 and FCA6 ICR calculations • FCA7 is calculated with historical DR performance from summer 2010 and 2011 while FCA6 DR Performance Assumptions used summer 2010 DR performance

  29. LRA & TSA Transfer Limit Assumptions • Transfer Limits – 2012 Regional System Plan (RSP) for 2016/17 • Internal Transmission Transfer Capability • Connecticut sub-area • N-1 Limit: 2,600 MW • N-1-1 Limit: 1,400 MW • Boston sub-area • N-1 Limit: 4,850 MW • N-1-1 Limit: 4,175 MW • Maine sub-area • N-1 Limit: 1,600 MW • Boston Import includes the impact of the Salem Harbor station retirement and of the recently certified Advanced North Shore Upgrades • The New England East-West Solution (NEEWS) includes the Greater Springfield Reliability Program for 2014 and the Interstate Reliability Program for December 2015 however, this project has not yet been certified to be in service by 2016 • The Maine Power Reliability Program (MPRP) is expected in service by 2015 summer. This project may result in increased transfer capability across interfaces in Maine however, sufficient testing has not been completed

  30. Resource Data Used in the LRA Calculation (MW) • Resources for New England excludes HQICCs • Load and Resource assumptions are for the corresponding RSP area used as a proxy for the load zone. DR values are the load zone values.

  31. TSA Load & Resource Assumptions • Load Forecast Data • 2012 CELT forecast • Connecticut sub-area 90/10 peak load*: 8,201 MW • Boston sub-area 90/10 peak load*: 6,520 MW • Resource Data • Based on FCA #7 Qualified Existing Capacity data • Resources terminated effective 7/1/2012 have been removed • Generating Capacity • Connecticut sub-area existing qualified capacity: 9,004 MW • Includes 6,310 MW of regular generation resources, 191 MW of intermittent generation resources and 1,533 MW of peaking generation resources • Boston sub-area existing qualified capacity: 3,228 MW • Includes 2,273 MW of regular generation resources, 70 MW of intermittent generation resources and 251 MW of peaking generation resources *The 90/10 peak load for the sub-area differs slightly from the 90/10 peak load for the Load Zone.

  32. TSA Resource Unavailability Assumptions • Resource Unavailability Assumptions • Regular Generation Resources - Weighted average EFORd • Connecticut sub-area: (Line-Gen) = 7% (Line-Line) = 6% • Boston sub-area: (Line-Gen) = 4% (Line-Line) = 2% • Intermittent Generation Resources: 0% • Peaking Generation Resources - Operational de-rating factor • Connecticut and Boston sub-areas: 20% • Passive Demand Resources: 0% • Non-RTEG Active Demand Resources - De-rating based on performance factors • Connecticut sub-area: 28% • Boston sub-area: 20% • Real-Time Emergency Generation - De-rating based on performance factors • Connecticut sub-area: 20% • Boston sub-area: 19%

  33. OP 4 Assumptions - Action 6 & 8 - 5% Voltage Reduction (MW) • Use the 90-10 Peak Load Forecast minus all Passive DR & Active DR with RTEG limited to 600 MW, if necessary • Multiplied by the 1.5% value used by ISO Operations in estimating relief obtained from OP4 voltage reduction

  34. OP 4 Assumptions - Tie Benefits (MW) • Modeled in the ICR calculations with the tie line availability assumptions shown below:

  35. Comparison of Tie Benefits for FCA6 and FCA7

  36. Summary of all MW Modeled in the ICR Calculation (MW) Notes: • Intermittent Power Resources 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

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