TEAC19

1. TEAC19 Friday, January 16, 2004 Radisson Hotel Marlborough, Massachusetts Redacted Version for Posting

2. TEAC19 Agenda • Welcoming Remarks/Announcements • Process Updates • RTEP04 Planning Assumptions • Fuel Diversity Working Group Report • Boston Area Planning Studies Review • Q&A – Boston Area Studies Summary Report

3. RTEP Process Updates • RTEP03 Approval • ISO-NE BOD on November 13, 2003 • Transmission Project Listing • Draft Update to be sent to TEAC mid- February • To be finalized in March • Inter-regional Planning Process • Draft Protocol under ISOs review • Consensus Protocol to be reviewed by Stakeholders

4. Draft Northeastern ISO/RTO Planning Coordination Protocol • Coordinates system planning activities • Establishes • - Inter-area planning stakeholder advisory committee • - Joint ISO/RTO planning committee • Data and information exchange • Coordinates Tariff studies • Northeastern coordinated system plan • Dispute resolution

5. RTEP04 Planning Assumptions • Assessment Overview • Generation • Unit Availabilities • New Units • Unit Deactivations • Base Case Transfer Limits • Load Forecast

6. RTEP04 Assessments Overview & Assumptions Peter K. Wong

7. RTEP04 • Resource Adequacy Assessment 2004 - 2013 • Economic Assessment 2004 - 2013

8. Resource Adequacy Assessment • Resource Adequacy Assessment (reliability analysis) to identify NEPOOL system reliability based on meeting the 1 Day in 10 Years Loss of Load Expectation criterion (disconnection of firm customers). • The Westinghouse Capacity Model Program and the GE Multi-Area Reliability Simulation (MARS) program will be used for this assessment. • Model New England as a single bus system and as a 13 Sub-area system.

9. Economic Assessment • Economic assessment to identify possible congestion trend and the impact on “Resource Cost”, “LSE Expense” and “Generator Impact” due to congestion. • Economic assessment will be conducted using the Inter Regional Energy Market Model (IREMM), a market based energy production simulator. • Modeling methods and assumptions are under review and will be discussed at TEAC20.

10. Load and Resource Assumptions • New England Loads – April 2004 CELT data • Generating Capacity – April 2004 CELT like data • Interruptible/dispatchable load and demand response values are based on ISO-NE Settlement data as of October 31, 2003 • Generating Unit Availability – 5 year historical performance (1999 through 2003) • Transmission Transfer/interface limits – latest interface limits determined through load flow (thermal & voltage) and stability analysis

11. 2004 New England Annual Peak Load Forecast 50 and 10 Percent Chance of Exceeding (MW)

12. Unit Addition Assumptions • Generating unit additions are based on approved 18.4 Applications and reflect those that have started construction as of January 2004. • Sensitivity cases will reflect all units with approved 18.4 applications. • The exceptions are resource assumptions relating to the SWCT RFP. It is assumed that 200 MW of resources will be added by June 1, 2004 in response to the RFP.

13. Capacity Addition Assumptions Summer Rating (MW) Milford Units 1 + 2 (SWCT)490 Millstone 2 Uprate (CT) 31 Total 521 SWCT RFP (NOR & SWCT) 200 All assumed in service by June 1, 2004

14. SWCT RFP Modeling • Total of 200 MW assumed from SWCT RFP • 150 MW Modeled as small generation – six 25 MW units with 7.7 EFOR and 2 maintenance weeks per year • 50 MW modeled as Load Response Resources as perfect capacity (No EFOR) • Sensitivity cases to be conducted that reflect updated information

15. Generation Retirements • Generation retirements are based on approved 18.4 Applications in the base case. Generating resources that have applied for, but denied retirement or deactivation (some of them are currently under RMR contract) are assumed in service during the study period in the base case. Their retirements or deactivations are modeled in sensitivity cases. • Additional retirements are assumed in to-be-determined sensitivity cases, if any.

16. Generating Unit Retirements Summer Rating (MW) Mason 4 – 6 98 Total 98 Assumed to be retired by June 1, 2004

17. Generating Unit Retirements* • To-be-Retired Units currently under RMR • Devon 7 and 8 • New Boston • Salem Harbor 1 – 4 (RMR under negotiation) • Units applied for 18.4 Deactivation (but denied) • Wallingford 2-5 * To be assumed in sensitivity cases. Additional generating unit retirement sensitivity scenarios need to be developed.

18. Generating Unit Availability • Individual generator unit availabilities are based on 5-year average of historical data (1999 - 2003). • Data Sources are as follows: • NABS for January thru April 1999. • ISO Short Term Generator Outage Data Base for May 1999 thru April 2000. • ISO Unit Availability Database for May 2000 thru November 2003. • December 2002 used again in place of December 2003 data to represent full 5-year worth of data.

19. Generating Unit Availability • For new CC units, unit immaturity is assumed for first 3 years of operation. After this period, Target Unit Availabilities (TUA) are used until a full five years of operating history is available. • For Nuclear units, any outage lasting longer than 6 months is represented by • The extended outage is divided into 2 parts: The first 6 months are considered a forced outage, and the remaining outage period assigned TUA’s (ESOF = 17.31%, EFOR = 10.66%, and EAF = 73.88%)

20. Existing Generating Unit AvailabilityAssumptions (Percent)

21. New CC Unit Availability Assumptions

22. OP-4 – Action During an Emergency Action 1 – Implement Power Caution and advise generators to prepare to provide emergency energy Action 2 – Order on generation < 5 MW, opting for OP 4 triggered dispatch per OP 14. Request “Settlements Only” units under 5 MW to come on line via Special Notices Action 3 – Interrupt Real-Time Demand Response, 2 hour or less notifications – Block A Interrupt Real-Time Profiled Response Resources 0 MW 47 MW 1 MW 136 MW

23. OP-4 – Action During an Emergency Action 4 – Interrupt Real-Time Demand Response, 2 hour or less notification – Block B Action 5 – Interrupt Real-Time Demand Response, 2 hour or less notification – Block C Action 6 – Begin to allow depletion of 30-minute reserve Action 7 – Interrupt Real-Time Demand Response, 2 hour or less notification – Block D Action 8 – Interrupt Real-Time Demand Response, 2 hour or less notification – Block E 0 MW 0 MW About 600 MW 0 MW 0 MW

24. OP-4 – Action During an Emergency Action 9 – Voluntary load curtailment of NEPOOL Participants’ facilities Interrupt Real-Time Demand Response – 30 minutes or less notification, not requiring voltage reduction to be implemented Implement Power Watch 40 MW 31 MW 0 MW

25. OP-4 – Action During an Emergency Action 10 – Customer generation contractually available to NEPOOL Participants during a capacity deficiency Action 11 – Schedule Participant-submitted EETs Arrange to purchase Control Area-to-Control Area emergency 5 MW Variable (0 – 1000 MW)

26. OP-4 – Action During an Emergency Action 12 – Implementation of 5% VR requiring more than 10 minutes Interrupt Real-Time Demand Response – 30 minute or less notification, requiring voltage reduction to be implemented In later Actions of OP 4, the New England 10-min reserve may be allowed to diminish to maintain an absolute minimum required level 5 MW 74 MW About 1000 MW

27. OP-4 – Action During an Emergency Action 13 – Implementation of 5% VR requiring 10 minutes or less Action 14a – Customer generation not contractually available to NEPOOL Participants during a capacity deficiency Action 14b – Voluntary load curtailment by large industrial and commercial customers Action 15 – Radio and TV appeals for voluntary load curtailments Implement Power Warning 355 MW 5 MW 200 MW 200 MW

28. OP-4 – Action During an Emergency Action 16 – Request state governors to reinforce appeals for voluntary load curtailment Declaration of Power Warning 100 MW Grand Total 2,999 – 4,004 MW Notes: Action 2 relief based on Summer Ratings. Assumes 25% of total MW of Settlement Only units <5 MW will be available and respond Action 14b relief is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced notice that can be given.

29. Tie Benefit Assumptions Tie Reliability Benefit Assumptions June – Sept MW* * Tie Reliability Benefits for NY and NB are assumed to be 0 MW during the non-Summer rating months of October through May.

30. HQICC Values

31. Demand Response Capacity As of October 31, 2003

32. Demand Response Capacity • Demand response assets in Real-Time Price Response derated by 50% and treated as capacity in Resource Adequacy Assessment. • Demand response assets in Real-Time 30-min, Real-Time 2-hour, and Real-Time Profiled Response treated as capacity with 100% availability in Resource Adequacy Assessment.

33. OP-4 Assumptions

34. Transmission Interface Limits • Represent potential limiting areas of the NEPOOL transmission system that may become constrained under a variety of system conditions. • The most limiting transmission facility and critical contingency, which limit the interface transfer, may change, depending on unit dispatch, load level and load distribution. • For modeling purposes these interface limits are shown as static. • These interface limits have been defined to gauge the amount of power which can be transferred between or through various Sub-areas before a limitation is reached.

35. Transmission Interface Transfer Limits • Changes from 2003 RTEP Study • Boston Import – 3,600 MW to 3,800 MW in 2004 and 3,800 MW to 4,500 MW in 2006 • SEMA Export – 2,300 MW to no limit • SWCT – 2,600 MW to 2,550 MW in 2005 • NOR – 1,500 to 1,650 MW in 2008 • NY to NE – 1,550 MW to 1,225 MW (summer) and 975 MW to 1,475 MW (winter) • NB to NE – 700 MW to 1,000 MW in 2006 • Orrington South Export – 1,050 MW to 1,200 MW in 2006

36. Transmission Interface Transfer Limit Assumptions(Static Limits Used for Modeling)

37. Transmission Interface Transfer Limit Assumptions(Static Limits Used for Modeling)

38. Transmission Interface Transfer Limit Assumptions(Static Limits Used for Modeling)

39. Transmission Interface Transfer Limit Assumptions(Static Limits Used for Modeling)

40. Generating Unit Energy • Generation from fossil fueled units will be calculated as a function of their short run marginal costs. • Generation from hydro units are modeled using a historical monthly generation profile. • Generation from pumped-storage units will reflect an assumed 10% capacity factor and 75% efficiency.

41. Other Assumptions for Economic Assessment • To be presented at TEAC20. • Fuel Cost • Interchange with Neighboring Control Areas • Treatment of Emission Allowance Costs

42. The 2004 NEPOOL, States, and RTEP Sub-area Energy & Peak Forecasts David J Ehrlich – ISO-NE Load Forecasting / System Planning

43. Changes to 2004 Forecast • New Economic Forecast: • Slower growth in income per Household • 2003 Historical NEPOOL, State, and Operating Company Hourly Loads

44. Changes to 2004 Forecast New Network Model: Operating Company Growth Rates Bus Load Proportions Better Handling of non NEPOOL and non-conforming busses New Operating Company DSM Forecasts: Differs by state, largest changes in CT due to mandated spending reductions