TEAC14

1. TEAC14 Thursday, January 23, 2003 Radisson Hotel Marlborough Marlborough, Massachusetts Version for posting on the ISO-NE website. Certain information as been redacted for security reasons. Other corrections/changes made are noted.

2. SWCT Reports Available • To obtain paper or electronic version of the following reports contact ISO-NE Customer Service at 413 540 4220 • Southwestern Connecticut Electric Reliability Study - Volume 1 - Final Power - Flow, Voltage and Short circuit • Southwestern Connecticut Electric Reliability Study - A Comparative Analysis of 345 kV Plumtree-Norwalk Overhead versus 2 -115 kV Cables from Plumtree - Norwalk.

3. TEAC14 Agenda • Welcoming Remarks • RTEP03 Scope Overview • Planning Assumptions • Update on Transmission Studies • SEMA/RI Export • Boston /NEMA - • Downtown • North Shore • RTEP Projects

4. RTEP03 Scope • Reliability and Economic Assessments • Updated planning assumptions • MARS analysis by RTEP sub-area • SCED bus by bus analysis at selected load levels • Expanded IREMM analysis to reflect SMD • Historical Losses • Unit Commitment • Uplift • Several Cases to be studied • Incremental MARS & IREMM Analysis -2004

5. RTEP03 Cases

8. RTEP03 Scope • Transmission Planning Studies • SEMA/RI Export Improvement • ME Export Improvement • NEMA/Boston Improvement • Support Approved RTEP02 Projects • SWCT 345 kV • NW Vermont

9. RTEP03 Scope • Fuel Diversity Study • Analysis of Air Emission Impacts • Distributed Resources • LRP • Interregional Coordination

10. RTEP 03 Congestion Cost Methodology Presentation to the Transmission Expansion Advisory Committee January 23, 2003 Wayne Coste Principal, IREMM, Inc.

11. Where We Have Been - RTEP 01 • RTEP01 identified key transmission constraints • Economic congestion was estimated • Economic congestion created higher prices for some sub-areas • Interface ratings were significant (static) • Focus was on LMP effect of price volatility during high loads • ISO-NE Congestion Management System • Assumed SMD in place at the start of 2002 • - ARR / FTR revenue reallocation same as RTEP01/02 • Various assumptions tested using sensitivity cases • Tested the impact on several alternative bidding strategies • Did not include transmission “uplift” (generally off-peak),losses,load forecast uncertainty or sub-area internal limits • Tested relaxation of transmission constraints

12. Where We Have Been - RTEP 02 • Used basic RTEP01 economic framework • Modeling refinements • Assumption updates for • fuel • new units • transmission upgrades • interchange assumptions • Interchange: combination of fixed import and CC based value • Effect of full unit outages on congestion • Limited representation of operating reserve • Monthly hydro profile developed • RTEP02 quantified impact of relaxation of transmission constraints

13. RTEP03 Goals • Forecast on-peak congestion (same as RTEP02) • Quantify off-peak “uplift” • Renamed in SMD “Operating Reserve Charges and Credits” • Will remain due to need to securely dispatch the system • Market screens approved by FERC on Dec 20th • Develop a more secure unit commitment • Include N-2 considerations • Loss of largest unit • Loss of second transmission element • Incorporate Transmission Losses • Transmission losses under SMD may be relatively high • Roll up results to SMD Reliability Zones

14. Improve Secure Dispatch Representation • ISO-NE has always operated under a secure dispatch • SMD will continue this operating practice • RTEP03 should reflect this practice • RTEP02 respected N-1 transmission limits • Operations also considers N-2 transmission limits • Typically transmission outages are the most constraining • For second contingency transmission outages • Interface ratings are lower • Count a portion of quick-start resources • Include ramp-rate from on-line units • Include OP-4 actions • Include allowable amounts of load shedding

15. Unit Commitment Process • Three (or more) passes for unit commitment • First pass - all units can operate at any level when needed • Interfaces at N-2 limits. • Identify units that could be flagged “ON” for economics • Remaining “uneconomic” units flagged “OFF” • Second pass with flagged “OFF” units, price spikes occur • Interfaces at N-2 limits. • Identify units that are needed to avoid price spikes • Remaining “uneconomic” units flagged “OFF” • Third pass with units flagged “ON” typically at LOL • Interfaces at N-1 limits. • Committed min block bids in at zero

16. Unit Commitment Data • Relatively few units can be added in unit commitment process • We will examine the following for impacts: • Start-up cost • Minimum run hours • Low operating limit • Incremental heat rates • Use physical limits for LOL (typically 25%)

17. LMP • LMP’s have three components • Energy Clearing Price • Congestion • - in areas of bottled generation • + in load pockets • Losses • + close to load center • - in remote exporting areas

18. Proxy CT Bid Screens in Constrained in Areas • Allowable safe harbor bids into import constrained areas • Addressed in FERC Dec 20th order • FERC desires to allow limited scarcity pricing • Based on cost of hypothetical new Proxy CT • Reduction due to prevailing ICAP revenue offset • Net difference in fixed cost is allocated over 500 or 2000 hr • At 500 hours - adder can be in the range of 300% • At 2000 hours - adder can be in the 50 - 80 % range

19. Indicative LMPs by Load Zone - Energy Component • Energy component is • uniform in all zones • (HISTORICAL • DATA)

20. Indicative LMPs by Load Zone - Congestion Component • Congestion • component can be • significant when • transmission • contingency is • binding • (HISTORICAL DATA)

21. Indicative LMPs by Load Zone - Loss Component • Loss component is • very non-linear and • affect importing and • exporting regions • Differently • (HISTORICAL DATA)

22. Indicative LMPs by Load Zone - Loss Component • Maine has lowest loss • component while Vermont • has the highest. • (Sept 2002)

23. Including Losses in RTEP03 • We will use historic loss data by unit • Implications of loss component • Need to develop loss changes due to transmission upgrades • Distant generation may be penalized • Prevailing prices may rise if marginal units are • Electrically distant and • High losses

24. SCED Analysis • SCED - Security Constrained Economic Dispatch program developed by PTI • GOAL – To identify the specific transmission facilities that may constrain and cause congestion on the New England system

25. SCED Basics • Analysis focuses on optimal operation of the system (generator dispatch + phase shifters) • Transfers and dispatches are calculated as part of an optimization process • Uses network load flow model employing a dc linearized powerflow calculation • Provides estimates of costs incurred to securely operate around transmission constraints • Identifies reliability problems when secure system operation is infeasible • Identify HUB price divergence

26. SCED Analysis Assumptions • Similar Analysis performed as part of RTEP01 • 2004 Summer Peak to be analyzed at a number of varying load levels (50, 60, 70, 80, 90 and 100%) • Sensitivities will be studied with larger units out of service

27. InterregionalSystem Planning ProcessImplementation Plan

28. Goals • Reduce Both Physical and Process 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

29. Existing Physical and Process System Planning Seams • Tie Line Capabilities • Phase II HVdc vs. Central East and PJM Interfaces • Interconnection and Tariff Studies • Queues • Interconnection Standards • Cost Allocation • Single Coordinated Plan

30. Process Issues • Timing of FERC Decisions • SMD Rule • Planning • Pricing • Interconnection Rule • Queuing • Cost Sharing across ISO Borders • TO/ITC Issues • Differences in NY License Plate vs. NE Network Tariffs • Obligation to Build • Accommodation of Potential ITC(-s) • Formalization of Planning Process • State Issues

31. Opportunities to Address Physical Issues • Identify and Address Physical Seams • Form Initial Plan based upon Existing Procedures • RTEP02 and RTEP03 • NY Power Alert • Existing NY and NE Interconnection Procedures • NPCC Annual Reviews • NPCC CP-10 Studies • Initiate Joint Studies • NY-NE Transfer Analysis • Loss of HQ Phase II Project • UPNY-SENY Impact on NE • Identify Small Ticket Improvements • Develop Preliminary Designs for Further Analysis

32. Process to Address Physical Seams • Establish NY-NE Liaison Committee • Define Plan • Transmission Plan • Initially utilize existing planning procedures as approved by FERC • Coordinate with Regulatory Agencies • NYS DPS • NECPUC • FERC • Engage MP Committees • NEPOOL Participants Committee • NY Operating Committee • TEAC • Utilize agreements with IMO and NB to increase regional planning scope • Coordinate with NPCC and MAAC/PJM

33. Scope of Work • Assessment • Study Assumptions • Load Forecast • Generation I/S and Availability • Transportation Limits • Transmission Projects • Load Response/Distributed Resources • Establish Common Databases • MARS • IREMM/MAPS Congestion Projections • Transmission Analysis • NPCC Studies • Annual Reviews • CP-10 • CP-8 • Other TFSS Activities • Transmission Plan • Summary of Transmission Planning Studies • Include Project Status • Ensure Full Coordination of System Impact Studies and Transmission Improvements

34. RTEP03 Assessments Overview & Assumptions Peter K. Wong

35. RTEP03 • Reliability Analysis 2003 - 2012 • Economic Impact Assessment 2003 - 2012

36. Reliability Analysis • Reliability analysis (Resource Adequacy Assessment) to identify NEPOOL system reliability based on meeting the 1 Day in 10 Years Loss of Load Expectation criterion (disconnection of firm customers). • GE Multi-Area Reliability Simulation (MARS) program will be used for this analysis.

37. Economic Impact Assessment • Congestion cost assessment to identify possible congestion trend is based on meeting NEPOOL energy requirements. • Congestion cost assessment will be conducted using a market based energy production simulator (IREMM).

38. Economic Impact Assessment • Estimate congestion cost as result of transmission constraints identified in transmission studies. • Estimate congestion cost as result of different bidding strategies. • Congestion based on price differences between sub-areas (market areas) • Estimate LMP losses component • Estimate Uplift impacts

39. Load and Existing Resources • Load and existing generating resource capability assumptions will be based on the 2003 CELT Report forecast. • Interruptible/dispatchable load and demand response assumptions will be based on the latest ISO-NE Settlement data.

40. Unit Addition Assumptions • Generating unit additions are based on approved 18.4 Applications and reflect those that have started construction as of January 2003.

41. Unit Addition Assumptions Summer Rating (MW) AES Granite Ridge (NH)678 Milford Units 1 + 2 (SWCT)490 Mystic Units 8 + 9 (BOSTON) 1,414 Fore River (SEMA) 700 English Station 7 + 8 (CT) 70 Great Northern Hydro (BHE)*126 Total 3,478 All assumed in service by June 1, 2003 *18.4 Application submittal expected in Feb/Mar 2003

42. Generation Out of Service • Devon 7 and 8 are assumed deactivated when Milford units are in service. • New Boston 1 is assumed retired when Sithe Mystic 9 is in service. (corrections in red) • No other generation deactivations or retirements are assumed in the base case.

43. 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.

44. RTEP AssumptionsGeneration Other Adjustments • CELT Capacity Changes • Change in effective MW due to different forced outage rates

45. Generating Unit Availability • Generator unit availabilities are based on 5-year average of historical data (1998 - 2002). • Data Sources are as follows: • NABS for 1998 thru April 1999. • ISO Short Term Generator Outage Data Base for May 1999 thru April 2000. • ISO Unit Availability Database for May 2000 thru December 2002.

46. Generating Unit Availability • For new units, unit immaturity is assumed for first 3 years of operation. After this period, unit historical data and TUA is used to develop the 5 year average. • Forced outage assumptions for nuclear units with extended outage are based on NEPOOL Target Unit Availabilities except for the first year of the long outage.

47. Generating Unit Availability • For the first year of the long nuclear outage, any outage longer than 6 months would be represented by 6 months of forced outage averaged with either historical data or TUA (TUA is used if the unit is on outage the remainder of the year).

48. Existing Generating Unit Availability(Percent) (edited to indicate gas turbine and jet statistics separately)

49. Interchange Assumptions for Base Economic Impact Analysis Updated RTEP02 methodology with base plus price sensitive transactions • LI sound cables (Scenario Based)

50. Fuel Price Assumptions • Fuel Price Forecast Based on Energy Information Administration’s • Annual Energy Outlook (Dec 2002 AEO) for 2004+ • Short term outlook for 2003, 2004 • “Reference Case” forecast was used