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Follow-up on Regional Reserve Metric Review

Follow-up on Regional Reserve Metric Review. Wayne Coste, ISO-NE Presentation to PSPC December 9, 2004. Follow-up to Questions Raised. => 1 – Tie Benefits vs Tie Capabilities => 2 – Addition Tie Benefits/ATC Ratio Graph => 3 – Tie Benefits as % of Reserves w and w/o HQICC

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Follow-up on Regional Reserve Metric Review

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  1. Follow-up on Regional Reserve Metric Review Wayne Coste, ISO-NE Presentation to PSPC December 9, 2004 Presentation to PSPC Dec 9, 2004

  2. Follow-up to Questions Raised • => 1 – Tie Benefits vs Tie Capabilities • => 2 – Addition Tie Benefits/ATC Ratio Graph • => 3 – Tie Benefits as % of Reserves w and w/o HQICC • => 4 – Tie Benefits as a % of Neighboring System • 5 – Isolated Reserve Margins Graphs • => 6 – Data Tables • => 7 – Sub-area reliability vis-à-vis pool criteria • --- 8 – Tie Benefits “term” vs. “maximum reliance on outside resources” • => 9 – Is the 45 MW (Actions 9 and 10) of Curtailable Load still applicable? • => 10 – Do other area explicitly model operating procedures (Load Relief) in setting/calculating capacity requirements • => 11 – Is it appropriate to use emergency operating procedures when setting Objective Capability? • => 12 – Is the VR % from the test results valid for the summer period (RC Discussion topics). • 13 – CT and CC rating as a function of summer month temperatures. Limited to LFU Distribution. • 14 – Availability/GADs adjustment due to transmission outages/disruptions. • 15 – Probabilities for LRP/SCR/EDRP – Availability Rate assigned in input deck? • => 16 – EFOR vs. EFORd vs. EEFORd data (with respect to Peak Unit Outages) • => 17 – EFOR vs IRM graph • 18 – Sequential all hours vs. peak hours only • --- 19 – Is it correct to rely on Tie Benefits in developing resource requirements for the capacity market place? => Issue further discussed in this presentation ~~ Issue For PSPC Discussion Presentation to PSPC Dec 9, 2004

  3. Basic Data Used • Values are from various sources and are believed to be sufficiently consistent for comparative purposes as part of a discussion of reliability issues. • “Required Reserves” are for critical season and may not reflect seasonal diversity between areas. Presentation to PSPC Dec 9, 2004

  4. Basis of Transfer Capability Metrics NERC’s 2004 Summer Assessment used as the basis of Transfer Capabilities. Non-simultaneous First Contingency Incremental Transfer Capability. New York/ New England interface values used for this are: New England to New York: 925 MW New York to New England: 1225 MW Presentation to PSPC Dec 9, 2004

  5. Tie Benefits as a Percent of FC Total Transfer Capability Note: FC Total Transfer Capability based on NERC 2004 Summer Assessment Non-Simultaneous Transfers Presentation to PSPC Dec 9, 2004

  6. Tables of Tie Benefits to FCTT Presentation to PSPC Dec 9, 2004

  7. Ties: Percent of Neighbors Reserves Note: Seasonal peak load diversity would increase Quebec’s available summer reserves. This increased denominator would reduce ratios for New England, New York and Ontario. Presentation to PSPC Dec 9, 2004

  8. Tables of Neighbor Reserve Ratio Note: Seasonal peak load diversity would increase Quebec’s available summer reserves. This increased denominator would reduce ratios for New England, New York and Ontario. Presentation to PSPC Dec 9, 2004

  9. EFOR Equations Three EFORs: EFORiso-ne and EFORd are different EFORnerc is different from EFORiso-ne EFORnerc will not be discussed here Presentation to PSPC Dec 9, 2004

  10. The EFORd Formula Presentation to PSPC Dec 9, 2004

  11. With 0 SOH Hours Presentation to PSPC Dec 9, 2004

  12. With 600 SOH Hours Presentation to PSPC Dec 9, 2004

  13. EFOR Comparison (EFORd vs. EFORiso-ne) Presentation to PSPC Dec 9, 2004

  14. Effect of Average EFOR on OC Based on OC runs presented to PSPC at the January 22, 2004 meeting. Presentation to PSPC Dec 9, 2004

  15. PJM Sensitivity to EFORd Based on PJM approved IRM values and average EFORd values used over the last seven years 1999 through 2005 Presentation to PSPC Dec 9, 2004

  16. Sub-area reliability vis-à-vis pool criteria ISO-NE / NYISO use different approaches ISO-NE uses a pool criteria NYISO uses a sub-area criteria Presentation to PSPC Dec 9, 2004

  17. NYISO and ISO-NE “ALCC” • ISO-NE reserve margin criteria procedure based on a single area reliability concept • Add load (ALCC) until unconstrained pool LOLE reaches 0.1 day per year • NYISO reserve margin procedure is based on a multi area reliability concept • Add load until transmission constrained pool LOLE reaches 0.1 day per year Presentation to PSPC Dec 9, 2004

  18. RTEP Sub-Area LOLE As load is added proportionally to each area’s peak load, NOR becomes increasingly distressed. With “No Constraints” loads can be increased by 13.5 percent. “With Transmission Constraints” loads can only be increased by 3.0 percent because of Norwalk/Stamford LOLE. VT ME ME SME SME BHE BHE NH NH BOST BOST WEMA WEMA CMAN CMAN SEMA SEMA RI RI CT CT SWCT NOR SWCT Note: Values shown here are reasonable, but, are estimated Presentation to PSPC Dec 9, 2004

  19. Effect of Constraints on ALCC Presentation to PSPC Dec 9, 2004

  20. Conceptual Impact of TransmissionConstraints on Reserve Margin • Effect of lower ALCC is to increase reserve margin • NYISO Zones J & K are ~50% of NYISO load • Norwalk/Stamford area only 5% of New England load Note: Values shown here are reasonable, but, are estimated Presentation to PSPC Dec 9, 2004

  21. Emergency Operating Procedures Issues have been raised about the appropriateness of OP4 and their modeling in OC. Presentation to PSPC Dec 9, 2004

  22. Values to Use • 45 MW of interruptible load (OP4 Actions 9/10) • Initial reaction suggests that these are not in existing LRP programs. Further review in process. • Spring Voltage Reduction tests • OP 11 requires that voltage reductions occur on distribution systems because of the potential impact on transmission limits • III A. VOLTAGE REDUCTION Voltage reduction should take place on the distribution system wherever possible. It is recognized that in certain areas, voltage reduction is implemented on the sub-transmission system. Voltage reduction should not be implemented on the transmission system operating at 69 KV and above. • Adjustment to effective % of summer peak still unresolved • Investigate historical data to see if effect can be observed absent a controlled test • Sponsor an additional test during summer high loads Presentation to PSPC Dec 9, 2004

  23. Appropriateness of OP4 Actions • Policy Issue • Appropriateness of OP-4 actions for meeting reserve requirements has been questioned. • OP4 actions are envisioned before interrupting firm customer loads. • LOLE events are interruption of some amount of firm customer loads Presentation to PSPC Dec 9, 2004

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