NEPOOL Participant’s Committee Meeting February 5, 2003 Boston, MA

1. NEPOOL Participant’s Committee Meeting February 5, 2003 Boston, MA Stephen G. Whitley Senior Vice President & COO

2. Agenda • System Operations • Energy & Congestion Uplift • Cost of Maine Constrained Down Generation • New Generation Update • Summer 2003 – “A Look Ahead” • RTEP • ISO/NEPOOL Cost Causation Workshop • Back-up Detail

3. System Operations

4. Operation’s Highlights • Boston & Hartford Weather Pattern: • Temperatures were 5% below the average with below normal precipitation. • Peak Load • All-time winter peak reached on January 22 at 1900 of 21,597 MW • During December • Request for Shared Activation of Reserves (SAR) – January 3, 13, 15 & 19. • Type 6 Load Management – January 21, 22 & 27. • Solar Magnetic Disturbance – January 21 & 25 • The following were not implemented in January: • M/S#2; • M/S#3; • OP#4 • Posturing; • Emergency Purchases/Sales; • Solar Magnetic Disturbance; and, • Excess generation.

5. Energy and Congestion Uplift Reports

6. Total Congestion & Energy Uplift Payments 2001 & 2002

7. Total Congestion & Energy Uplift MWH 2001 & 2002

8. Total Congestion Costs May 1999 - October 2002 Incomplete

9. Cost of Maine Constrained DownGeneration

10. Cost of Maine Constrained Down GenerationMonthly Comparison 2001 to 2002(No changes since January 2003 meeting)

11. New Generation

12. New Generation Update • No new generating resources were added in December. • Approximately 3,500 MW expected by June 2003. • ISO New England continues to hold weekly conference calls with new generators to expedite interconnection, testing and commercial operation.

13. Summer 2003

14. Capacity Assessment • Positive capacity margins forecasted from May through September 2003.

15. Summer 2003 Capacity AssessmentReference Case - Weeks Beginning June 7th – June 21st MW Projected Peak 25,120 Operating Reserve Required 1,700 Total Operable Cap. Required 26,820 Projected Capacity 32,150 Assumed Outages 3,000 Total Capacity 29,150 Operable Capacity Margin 2,330

16. Summer 2003 Capacity Assessment

17. Summer 2003 Capacity Assessment

18. RTEP Update

19. RTEP03 Update • TEAC Meeting held on January 23rd • reviewed assumptions • discussed transmission improvements for the North Shore, Downtown Boston, and SEMA-RI • Next meeting tentatively planned for the beginning of March, 2003.

20. Interregional System Planning ProcessImplementation Plan – Short-term Goals • Reduce Both Process and Physical System Planning Seams • Issue Draft Coordinated NY/NE System Plan by 1st Qtr. 2004 • Expand upon NPCC planning process • Include MAAC/PJM • Increase coordination under NY and NE agreements with IMO and New Brunswick • Work toward removing other major seams

21. ISO/NEPOOL Cost Causation Workshops

22. Cost Causation Workshop #4 NEPOOL/ISO NECost Causation WorkshopFebruary 21, 2003Boston, MA

23. Back-up Detail

24. Summer 2003 Capacity Assessment

25. Summer 2003 Capacity Assessment

26. RTEP Projects Update - NEMA

27. RTEP Projects Update - SEMA

28. RTEP Projects Update - SWCT

29. Transmission Cost Allocation Workshops • Three Workshops Conducted: • Important background information has been presented; • History of Transmission Funding and Development in New England, • Practices in other areas of the country, • Economics of transmission funding in the new market – Dr. David Patton, • Status Report filed with the FERC on January 6; and, • Target Date for Workshop Four is late February. • Essential stakeholders are at the table: • TOs, Generators, State Regulators, Consumers and Public Advocates and FERC all participating; and, • Two Stakeholder Surveys have been completed. • Consensus Achieved on Six Principles. • Four allocation methods proposed: • NECPUC utilized this process to advance a regional compromise; and, • A Listing of Pros and Cons is under development. • Stakeholder Discussion is Robust – Process is working.

30. Transmission Cost Allocation Workshops (con,t) • Principles Guiding Stakeholder Working Group 1. Recognize Dynamics of the Power Grid. 2. Encourage Proper Investment. 3. Send Proper Price Signals. 4. Establish Fairness and Equity to All Market Participants. 5. Provide Price Certainty to Investors and Consumers. 6. Provide for Ease of Implementation.

31. Transmission Cost Allocation Workshops (con,t) “Strawmen” Methods Proposed 1. Initial RTEP-Planning Horizon (5 years) Study determines cost allocation for life of project. 2. Initial RTEP-Planning Horizon Study determines cost allocation for 5 years, and then regionalized cost allocation. • If RTEP-Planning Horizon Study shows regional benefits, then cost regionalization occurs from “Day One” 3. “PJM-Style” Tiered Approach (costs allocated to local area/region based on size of voltage of facility) 4. Regionalize 69kV and higher • No regionalization of generator interconnection & radial lines

32. For More Detail: Refer to the COO Monthly Operations Review Report located on the ISO New England website at: http://www.iso-ne.com/sysops_reports/ Thank you!