NEPOOL Participants Committee Meeting April 4, 2003 Boston, MA

1. NEPOOL Participants Committee Meeting April 4, 2003 Boston, MA Stephen G. Whitley Senior Vice President & COO

2. Agenda • System Operations • Gas Study Initiative • SMD Market Operations Update • Summer 2003 – “A Look Ahead” • ISO/NEPOOL Cost Causation Update • Demand Response Kickoff Update • Back – Up Details • Demand Response • New Generation • SW CT/Boston

3. System Operations

4. Operation’s Highlights • Boston & Hartford Weather Pattern: • Temperatures were below the average (longest sustained 6-month period in 50 years) with normal to above normal precipitation. • Peak Load • Peak load of 18,039 MW at 20:00 hours on March 31. • During March • Minimum Generation on March 22 & 28. • Requested Shared Activation of Reserves (SAR) – March 5, 7 and 20(2); Provided SAR on March 29. • Resources postured on March 22, 23, 28 and 30. • Emergency Sales on March 3. • Solar Magnetic Disturbances – K7 forecasts on March 17 & 18. • The following were not implemented in March: • M/S#2; • M/S#3; • OP#4; and, • Class 6 Load Management.

5. Gas Study

6. Gas Study Update • Northeast very dependent on gas storage during winter heating season. • Too much cold weather beginning in November – January 2003 – Almost a peak design/month. • Depletion of working gas storage inventories. • Maintenance of line pack is a daily issue. • LNG is OK (Distrigas). • ISO-NE is performing a post-winter assessment to determine the capacity impacts on gas-fired generation.

7. Gas Study Update Winter Capacity of Gas Capable Units Includes 2003 units: AES GRANITE RIDGE, MILFORD PDC, SITHE FORE RIVER, SITHE MYSTIC

8. Gas Study Update Temperature Impacts on Gas-FiredGenerating Capacity, 12/02 – 3/03 Peak Day Temp.

9. Gas Study Update – Scope of Work “A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

10. Gas Study Update – Scope of Work, cont. “ A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

11. Gas Study Update – Scope of Work, cont. “A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

12. SMD Operations

13. SMD Experience in March • Standard Market Design (SMD) cut-over was virtually seamless. • The March implementation date was designed to allow for a learning curve prior to the summer. • Energy prices were consistent with the cost of fuel: • Higher fuel costs in the first few weeks created higher energy prices; and, • Recently, energy prices have decreased consistent with the downward trend of fuel prices. • Software and business systems have generally worked well and functioning as designed. • Limited number of hardware and software issues, resulted in interruption of data flow.

14. SMD Experience in March (cont.) • Potential for error is elevated during this learning process: • Internally • Data – issues such as Non-PTF Loss Factors • Operator Error – RT dispatch or selection in day ahead • Externally • Methods used to reflect “Seller Choice” strategies • Self Scheduling • Internal decisions reviewed and business process and software tools enhanced to mitigate potential for repeat. • No reliability issues since going live. • NERC Control Performance within criteria. • Conditions experienced in Real-time so far: • Congestion; • Excess ramping curtailments; • Minimum generation emergency; • Major generation contingencies; and, • Emergency sales.

15. SMD Action Plan

16. Day-ahead & Real-time Prices, ISO-NE Hub

17. Day Ahead – LMP Average by Zone & Hub (-1.4) (+0.1) (-1.3) (-2.7) (-2.8)

18. Real Time – LMP Average by Zone & Hub (-1.5) (+0.1) (-2.6) (-2.0) (-5.7) (+0.1) 97.4%

19. Real-time LMP

20. DAM LMP

21. Summer 2003

22. Summer 2003 Capacity AssessmentLeast Operable Capacity Margin - Weeks beginning June 7, 14 and 21 MW Projected Peak (50/50) 25,120 Operating Reserve Required 1,700 Total Operable Cap. Required 26,820 Projected Capacity 31,920 Assumed Outages 3,600 Total Capacity 28,320 Operable Capacity Margin 1,500

23. Summer 2003 Capacity Assessment

24. Summer 2003 Capacity Assessment

25. Summer 2003 Capacity AssessmentLeast Operable Capacity Margin - Weeks beginning June 7, 14 and 21 MW Projected Peak (90/10) 26,630 Operating Reserve Required 1,700 Total Operable Cap. Required 28,330 Projected Capacity 31,920 Assumed Outages 3,600 Total Capacity 28,320 Operable Capacity Margin (10)

26. Summer 2003 Capacity Assessment

27. Summer 2003 Capacity Assessment

28. Cost Causation for System Upgrades

29. Transmission Cost Allocation Workshops • ISO-NE presented “staff recommendation” for transmission cost allocation at the fourth and final stakeholder workshop on March 14. • Workshop participants included regulators from all six New England states and the FERC. (ISO-NE Board members also in attendance). • ISO-NE invited further comment beyond the workshop. • Next steps: • Present ISO-NE staff proposal to NECPUC and NEPOOL Tariff Committee (April); • Investigate least-cost-planning and resource parity issues with NECPUC and NEPOOL (April-June); • Present proposal to NPC and ISO-NE Board (May); and, • File proposal with the FERC (May).

30. ISO-NE Cost Allocation Method Proposal • ISO-NE/NEPOOL define upgrade categories. • Through RTEP, ISO staff recommends to SPARC/BOD each upgrade’s assignment to the appropriate category. • If the assignment can be reasonably made to both local or regional, Regional Cost Allocation is utilized. • Regional Mechanism – Project is “Regionalized” for the life of the project if: • Project provides loop/network benefits… 2-way traffic; and, • Project is 115-kV and above. • Any discretionary costs are borne by the entity requiring the special design (e.g. entities requesting underground).

31. System Upgrade Categories

32. Demand Response Summit

33. New England Demand Response Summit • Radisson Hotel • 75 Felton Street • Marlborough, MA • April 17, 2003 • 8:30 a.m. – 12:00 p.m.

34. Back-Up Details

35. Demand Response(as of March 31, 2003) * Represents former Type 2 Interruptible Loads

36. New Generation Update (Revised) • No new generating resources were added in March • Approximately 3,382 MW expected by June 2003 • Generation Projects as of March 14, 2003 No.MW In Construction 6 3,382 with 18.4 approval Not in Construction 5 1,783 with 18.4 Approval

37. RMR Contracts • NRG • NRG filed Cost-of-Service RMR Contracts on February 26. • Annual fixed cost of about $180 million, including $44 million for normal and deferred maintenance. • FERC issued an order on NRG’s emergency motion on March 25, putting the “Reliability Cost Tracker” in place effective February 27. • ISO-NE to serve as escrow agent for these funds. • PPL • PPL Requesting Cost of Service RMR Contracts for Wallingford Station – Four of Five Nominal 45MW Peaking Units. • Filed on January 16, 2003. FERC issued Deficiency Letter on February 28, 2003. • PPL responded on March 31 and stated they will file an 18.4 Application for temporary deactivation effective July 1, 2003.

38. RMR Contracts (cont.) • PG&E (PGET and USGen New England) • Considering filing an 18.4 Application for Salem Harbor 1-4 effective October 1, 2004. • Governor has stated that units must be in environmental compliance by that date or shut down. • PG&E was planning environmental upgrades for compliance by October 1, 2006. • October 1, 2004 date is under appeal before a DEP ALJ. • ISO in discussion with DOER and DTE, National Grid and NSTAR on NEMA reliability needs and possible transmission improvements.