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TEAC9

TEAC9. May 23, 2002 Sheraton Hotel Springfield, Massachusetts. TEAC9 Agenda. Welcoming Remarks Transmission Studies Technical Session Upgrade Projects Reliability Analysis Congestion Analysis. New England Transmission Studies. Presented to TEAC May 23, 2002 Rich Kowalski. NB. HQ.

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TEAC9

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  1. TEAC9 May 23, 2002 Sheraton Hotel Springfield, Massachusetts

  2. TEAC9 Agenda • Welcoming Remarks • Transmission Studies • Technical Session • Upgrade Projects • Reliability Analysis • Congestion Analysis

  3. New England Transmission Studies Presented to TEAC May 23, 2002 Rich Kowalski

  4. NB HQ BHE RTEP Geographic Scope(2002-2006) Adequate Reliable and Economic Supply: ME Marginal Deficient VT SME Locked In NH BOST NY CMA/ NEMA WMA SEMA RI CT SWCT NOR

  5. Long Mountain Breakers • Added 2-345kV breakers (4T and 9T) • Eliminated possibility of “stuck” breaker taking out both the 398 and 352 lines or both the 321 and 352 lines • These contingencies responsible for the SWCT voltage-limited import capability

  6. Capacitor Additions • Add 25.2 MVARs @ Rocky River Substation • Add 25.2 MVARs @ Stony Hill Substation • Provides reactive correction to maintain voltage • Normally switched on during periods of high load • Area was susceptible to voltage collapse following certain contingencies

  7. Glenbrook StatCom • A dynamic reactive compensation device • Provides dynamic, fast-acting reactive power to maintain constant voltage levels • Works well in an area where the level of capacitors needed during a contingency to maintain voltage would create high voltage problems during normal operation (Norwalk-Stamford area)

  8. Breaker Conversions • IPT = Independent Pole Tripping = the ability of a single pole or phase to trip (open) independently of the other poles • There’s a greater likelihood of the system remaining stable if two phases of a line can remain energized under a line-to-ground fault scenario as compared to the entire line being taken out of service • 2 breakers @ West Medway have been converted to IPT operation • Conversions to IPT operation are underway at Sherman Road and Millbury • 4 breakers at West Walpole to be converted

  9. Interface Changes Considered Note: Various combinations of interface constraints will be tested in sensitivity cases

  10. RTEP02 Technical Session • Session Description • Scheduled for June 17, 2002 • 9:30 A.M. • Nation Grid Offices • Energy Institute

  11. Load Forecast Update David J. Ehrlich

  12. RTEP Assumptions - Load Exhibit 1a: NEPOOL Net Energy for Load History and Forecast (GWH) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 141742 136742 131742 126742 121742 116742 111742 106742 1995 1997 1999 2001 2003 2005 RTEP01 RTEP02

  13. RTEP Assumptions - Load Exhibit 1b: NEPOOL Net Energy for Load History and Forecast (GWH) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 3.5 3.0 2.5 2.0 Annual Percent Changes 1.5 1.0 0.5 0.0 1996 1998 2000 2002 2004 2006 RTEP01 RTEP02

  14. RTEP Assumptions - Load Exhibit 1c: NEPOOL Summer Peak Load History and Forecast (MW) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 26618 25618 24618 23618 22618 21618 20618 19618 1995 1997 1999 2001 2003 2005 RTEP01 RTEP02

  15. RTEP Assumptions - Load Exhibit 1d: NEPOOL Summer Peak Load History and Forecast (MW) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 4.2 3.7 3.2 Annual Percent Changes 2.7 2.2 1.7 1.2 1996 1998 2000 2002 2004 2006 RTEP01 RTEP02

  16. RTEP Assumptions - Load Exhibit 1e: NEPOOL Winter Peak Load History and Forecast (MW) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 23563 22563 21563 20563 19563 18563 1995 1997 1999 2001 2003 2005 RTEP01 RTEP02

  17. RTEP Assumptions - Load Exhibit 1f: NEPOOL Winter Peak Load History and Forecast (MW) RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06) 3.0 2.5 2.0 1.5 Annual Percent Changes 1.0 0.5 0.0 -0.5 -1.0 1996 1998 2000 2002 2004 2006 RTEP01 RTEP02

  18. RTEP01 Sub-Areas As Percent of Sum of Sub-Areas NorSt 20.0 N-CT 58.5 SW-CT 21.5

  19. RTEP01 Companies As a Percent of Sub-Areas UI:NorSt 16.8 CL&P:N-CT 62.4 UI:SW-CT 83.2 CL&P:SW-CT18.4 CL&P:NorSt 19.1 CMEEC:NorSt 10.3 CMEEC:SW-CT CMEEC:N-CT 68.2 21.4

  20. Sub-Areas as Percent of NEPOOL RTEP01 & Revised RTEP01 RR1:NorSt 5.0 R1:N-CT 12.9 RR1:SW-CT 8.5 R1:SW-CT 10.0 RR1:N-CT 13.8 R1:NorSt 4.4

  21. Sub-Areas as Percent of NEPOOL Revised RTEP01 & RTEP02 RR1:N-CT R2:NorSt 4.7 13.8 R2:SW-CT 9.2 RR1:SW-CT 8.5 R2:N-CT 13.3 RR1:NorSt 5.0

  22. 2002 Coincident Summer Peaks (MW) 2002 Coincident Summer Peaks (MW) 5000 4500 4000 3500 3000 2500 2000 1500 1000 500 0 Bost RI VT NH BHE N-CT C-ME S-ME W-MA SEMA SW-CT NORST CNEMA RTEP01 RTEP02

  23. 2002 Coincident Winter Peaks (MW) 2002 Coincident Winter Peaks (MW) 4500 4000 3500 3000 2500 2000 1500 1000 500 0 Bost RI VT NH BHE N-CT S-ME C-ME W-MA SEMA SW-CT NORST CNEMA RTEP01 RTEP02

  24. RTEP02 2002 SUMMER PEAK LOAD FORECASTS RTEP02 2002 SUMMER PEAK LOAD FORECASTS 4676 5000 4500 4000 3215 3500 3000 2304 2233 2500 2009 2001 1845 2000 1524 1214 1500 1136 1056 1000 598 389 500 0 Bost RI VT NH BHE N-CT C-ME S-ME W-MA SEMA SW-CT NORST CNEMA

  25. RTEP02 2002 WINTER PEAK LOAD FORECASTS RTEP02 2002 WINTER PEAK LOAD FORECASTS 4500 3978 4000 3500 2749 3000 2500 2094 1952 1889 1739 2000 1706 1424 1500 1184 1008 857 1000 547 344 500 0 Bost RI VT NH BHE N-CT C-ME S-ME W-MA SEMA SW-CT NORST CNEMA

  26. RTEP02 SUMMER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL RTEP02 SUMMER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL 19.3 20 18 16 13.3 14 12 9.5 9.2 10 8.3 8.3 7.6 8 6.3 5 4.7 6 4.4 4 2.5 1.6 2 0 Bost RI VT NH BHE N-CT C-ME S-ME W-MA SEMA SW-CT NORST CNEMA

  27. RTEP02 WINTER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL RTEP02 WINTER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL 20 18.5 18 16 12.8 14 12 9.8 9.1 8.8 10 8.1 7.9 8 6.6 5.5 4.7 6 4 4 2.5 1.6 2 0 Bost RI VT NH BHE N-CT C-ME S-ME W-MA SEMA SW-CT NORST CNEMA

  28. RTEP02 2002 NET ENERGY FOR LOAD (GWH) RTEP02 2002 NET ENERGY FOR LOAD (GWH) 23800 25000 20000 16408 15000 12187 11043 10847 10809 9860 10000 8196 6701 5750 5405 5000 3176 2026 0 Bost RI VT NH BHE N-CT S-ME C-ME W-MA SEMA SW-CT NORST CNEMA

  29. RTEP02 NET ENERGY FOR LOAD FORECAST AS A PERCENT OF NEPOOL RTEP02 NET ENERGY FOR LOAD FORECAST AS PERCENT OF NEPOOL 18.9 20 18 16 13 14 12 9.7 8.8 10 8.6 8.6 7.8 8 6.5 5.3 6 4.6 4.3 4 2.5 1.6 2 0 Bost RI VT NH BHE N-CT S-ME C-ME W-MA SEMA SW-CT NORST CNEMA

  30. RTEP02 SUMMER PEAK LOAD FACTOR RTEP02 SUMMER PEAK LOAD FACTOR 66 63 63 64 62.2 61.6 61.4 61 60.6 62 60.4 59.5 59.5 60 58.3 58.1 58 55.3 56 54.3 54 52 Bost RI VT NH BHE N-CT S-ME C-ME W-MA SEMA SW-CT NORST CNEMA NEPOOL

  31. NUMBER OF DAYS AT 90%+ OF SUMMER PEAK NUMBER OF DAYS AT 90%+ OF SUMMER PEAK Original Forecast and 1990-2001 Actuals 21 19 17 15 13 11 9 7 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Fcast Average Annual

  32. 2002 NEPOOL SUMMER DAILY PEAK LOAD FORECAST AS A PERCENT OF SUMMER PEAK (24,200 MW)

  33. Reliability Analysis Presented to TEAC May 23, 2002 Edward Tsikirayi

  34. New England Sub-Area Model

  35. Important Note • It must noted that this is a Sub-Area Resource Adequacy Assessment which takes into account the effects of static transmission limits simplification between the various sub-areas. Transmission security issues relating to generation and transmission operations and their interdependencies are not modeled in this analysis.

  36. A Result Presented at TEAC 7 • Upgrading the SWCT and CT import interfaces will result in the greatest improvement to NEPOOL system reliability.

  37. Case Outline • RTEP02 shows the impact of the non-transmission assumption updates( load and generation) when compared to RTEP01. • RTEP02A shows the impact of increasing the SWCT import limit to 1,850 MW as compared to RTEP02. • RTEP02B shows the impact of increasing the SWCT import limit to 2,150 MW as compared to RTEP02A. • RTEP02C shows the impact of further increasing the SWCT import limit to 2,450 MW as compared to RTEP02B. • RTEP02D shows the impact of the new SEMA, SEMA/RI and East-West transfer limits based on the recent analysis as compared to RTEP02. • RTEP02E shows the impact of the improvements from the IPT Breaker upgrades as compared to RTEP02D. • RTEP02F shows what synergies are gained by improving both the SWCT and SEMA/RI transfer limits simultaneously as compared to RTEP02C and E.

  38. Case Assumptions

  39. Interface Changes Considered

  40. MARS LOLE ResultsAll Cases – No Unit Retirements Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  41. Incremental Reliability Benefit of Capacitor Upgrade * * Upgrade assumed in-service on May 1 2002 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  42. Incremental Reliability Benefit of Static Compensator Upgrade * * Upgrade assumed in-service on May 1 2004 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  43. Sensitivity Analysis –Norwalk Harbor 1 and 2 and Cos Cob Unavailable * * Norwalk Harbor 1 and 2 and Cos Cob assumed retired on January 1, 2004 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  44. Incremental Reliability Benefit of345 kV Phase I Upgrade* assuming Norwalk Harbor 1 and 2 andCos Cob Unavailable * 345 kV Phase I upgrade assumed in-service on December 1, 2004 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  45. Devon 7,8 and 10 Deactivation* Scenarios (per 18.4 Application) * Deactivation assumed effective as of August 1, 2002 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

  46. Summary of Findings • The Long Mountain Breakers & Capacitors and the Glenbrook StatCom upgrades to the SWCT interface will provide short to long term reliability benefits to the NEPOOL system. • The SWCT Phase I upgrade will provide medium to long term reliability benefits to the NEPOOL system especially in the event of extended outages of generating units.

  47. Next StepsLong Term Reliability Analysis • 2002 - 2011 MARS • Generation Assumptions • 2002 - 2006 new units • 2007 - 2011 no retirements/additions • 2 Retirement Sensitivity Cases • Fossil Steam over 40 years old • Boston -480 MW, WEMA -17MW, NH - 142MW • SWCT - 213MW, SME - 105MW • Nuclear Retirement Sensitivity • 5 years prior to NRC license expiration

  48. RTEP 02 Congestion Cost Evaluation Presentation to the Transmission Expansion Advisory Committee May 23, 2002 Wayne Coste Principal, IREMM, Inc.

  49. Where We Have Been • RTEP01 identified key transmission constraints • In RTEP01 economic congestion was estimated • Economic congestion created higher prices for some sub-areas • Interface ratings were significant • Focus was on price volatility during high load periods • Congestion Management System • Assumed in place at the start of 2002 • - ARR / FTR revenue reallocation same as RTEP01 • Various assumptions tested using sensitivity cases • Tested the impact on several alternative bidding strategies • Did not include transmission “uplift” (generally off-peak) • TEAC 6 - Illustrated impact of Price Responsive DSM on SWCT • TEAC 7 - Illustrated impact of relieving transmission constraints

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