TEAC10

1. TEAC10 July 31, 2002 Marriott Hotel Providence, Rhode Island

2. TEAC10 Agenda • Welcoming Remarks • Inter-Regional Coordination • Reliability Analysis • Congestion Analysis • Fuel Diversity Issues • Air Emission Impacts • RTEP02 • Review of Schedule • TEAC Comments on Draft Technical Sections

3. Inter-Regional Coordination • Resource Adequacy Issues (NPCC CP-8) • Dynamics Issues (NPCC SS38) • Collaborative Planning Initiative (NPCC CP-10 ) • NPCC Regional Planning Forum - (Studies to Assess Large Loss-of-Source Events) • New England Interim Review of Transmission Reliability 2002-2007 (NPCC TFSS) • New England Comprehensive Review of Transmission Reliability 2003-2008 (NPCC TFSS)

4. NPCC CP-8 • Probabilistic analysis of short-term resource adequacy (using GE MARS program) • Evaluated interconnection benefits • Comprehensive Review of Resource Adequacy • Reliability impacts of fuel supply & emissions restrictions • Impacts of evolving market rules

5. NPCC SS-38 • Analysis of dynamic phenomena with potential inter-Area impact • 2001 Transmission Adequacy Assessment – dynamic response of key design and extreme contingencies (PJM and ECAR contingencies also tested- completed) • NPCC 2002 Adequacy of Under-Frequency Load Shedding • Triennial Review • Shorten Time Delay Under-frequency Relays

6. NPCC CP-10 • Identify and prioritize transmission bottlenecks in NPCC & MAAC • Phase I identified potential constraints for 2006, focus on inter-Area transfer impediments, not local issues • Completed • Phase II will use GE MAPS program to prioritize based on potential adverse reliability impacts • Scheduled for Fall 2002 Completion

7. NPCC Studies to Assess Large Loss-of-Source Events • NPCC Regional Planning Forum & CP10 joint effort • Assess inter-Area impact of large loss-of-source events • Large loss-of-source events adversely affect NY & PJM voltages, continues to limit Phase II operation • Loss of Phase II HVDC at 2000 MW is the largest contingency • Consider alternatives to increase acceptable size of source loss

8. Resource Adequacy Assessment: 2002-2011 Presented to TEAC July 31, 2002

9. New England Sub-Area Model

10. 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.

11. Resource Adequacy Assessment: 2002-2011 • Period covered: 2002 – 2011 • RTEP02 hourly loads. • Interface assumptions same as for RTEP02F (TEAC 9) except SWCT limit only up to 2,150 MW. • New unit additions same as for 2002-2006 analysis (TEAC 9). • No unit retirements in Base Case. • Several unit retirement scenarios.

12. Cases Studied Base Case This case assumes no generation unit retirements. Base Case without New Boston 1 This case studies the impact on NEPOOL reliability of the retirement of the New Boston 1 unit effective July 1, 2002.

13. Cases Studied Base Case with Fossil Steam Unit Retirements Studies the impact of retiring all fossil steam units over 40 years old effective January 1, 2003.

14. Cases Studied Base Case with Nuclear Retirement Sensitivity This case studies the impact of the possible retirement of the nuclear units 5 years prior to their NRC operating license expiration dates. Affected units are Millstone 2, Vermont Yankee and Pilgrim.

15. Results • Base Case • The results of the Base Case show that NEPOOL complies with the Resource Planning Reliability Criterion throughout the 2002-2011 period since the LOLE is better than 0.1 days/year not accounting for sub-area internal constraints. Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

16. Results • Base Case without New Boston 1 • The retirement of New Boston 1 does not have an adverse reliability impact on the NEPOOL bulk power system. Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

17. Results • Base Case with Fossil Steam Units Retirement • The assumed retirement of the fossil steam units, which are over 40 years old would worsen NEPOOL system reliability from an LOLE perspective but the system would still be in compliance with the Resource Planning Reliability Criterion not accounting for sub-area internal constraints. Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

18. Results • Base Case with nuclear retirement sensitivity • The assumed retirement of the nuclear units five years before their current license expiration dates would result in NEPOOL complying with the Resource Planning Reliability Criterion given the current load and capacity projections not accounting for the sub-area internal constraints. Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

19. RTEP 02 Congestion Cost Evaluation: Effect of Full Unit Outages and Fuel Diversity Presentation to the Transmission Expansion Advisory Committee July 31, 2002 Wayne Coste Principal, IREMM, Inc.

20. Additional Analysis of Congestion Cost Uncertainty • - Graphs illustrating uncertainty were shown in TEAC 9 • Effect of load increases • Effect of long term generator outages • - RTEP analyses performed using capacity de-rating to reflect EFOR • - Estimates of congestion are influenced by simultaneous outages • - Simultaneous outages could occur if “full-unit” random outages were modeled using a Monte Carlo technique. • - Monte Carlo based full unit forced outages can then be used to investigate the impact of generator status influenced interface limits because a specific status is known in each hour.

21. 2003 RTEP01 BOST and CT Bid Higher (RTEP02) Load Increases Shown as Effective Capacity Reductions For 2003 Effect of Capacity Reductions on SWCT/NOR Congestion For Year 2003 Capacity Reductions Occur on Jan 1, 2003 SWCT Import Capability at 1700 MW 600 Long-Term Outage of 450 500 MW 74 MW of Capacity on Long-Term 400 Outage Congestion Cost ($Million) 300 200 $68.8 Million in 2003 with RTEP01(No Sensitivity Cases) 100 0 0 200 400 600 800 1000 Effective MW of Capacity Reduction 2003 RTEP02 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

22. Effect of Changes in Loads on Congestion Costs For 2003 Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

23. Monte Carlo based Congestion Costs • Monte Carlo based congestion costs investigated using 23 cases. • Each case has a different “seed” • Congestion based on difference with “completely uncongested” • “Completely uncongested” case based on de-rated EFOR • May be appropriate to compare to similar Monte Carlo case • All cases may be averaged together for comparison • Trends show that random simultaneous full unit forced outages impact congestion • Volatility between cases is informative • Much of the congestion increases shown in subsequent graphs are due to New England wide caused by locked in generation in ME and SEMA/RI

24. Monte Carlo Based EFOR Derated Capacity EFOR Effect of Monte Carlo Based Full Unit Outages - BOST 2006 BOST For Year 2006 20.0 15.0 ($ Million) Annual Congestion 10.0 5.0 0.0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Monte Carlo Case Congestion cost increases shown are due, in part, to locked in generation in ME and SEMA/RI Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

25. Monte Carlo Based EFOR Derated Capacity EFOR Effect of Monte Carlo Based Full Unit Outages - SWCT 2006 SWCT For Year 2006 20.0 15.0 ($ Million) Annual Congestion 10.0 5.0 0.0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Monte Carlo Case Congestion cost increases shown are due, in part, to locked in generation in ME and SEMA/RI Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

26. Monte Carlo Based Congestion - Maine/NH Interface • Maine / NH interface is dependent upon a number of issues • Voltage, stability and thermal limitations • These factors can be influenced by specific unit status • Three cases were investigated for ME/NH Interface • Reference with interface at 1400 MW • Interface de-rated from 1400 MW to 1200 MW all hours • Loss of specific unit de-rates interface to 1100MW • Monte Carlo based congestion costs investigated using 23 cases • 1200MW interface de-rating costs $13.3 Million over 5 years • Specific unit effect costs $14.2 Million over 5 years

27. Effect ME/NH Interface De-rating Due to Loss of Seabrook Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

28. RTEP Fuel Diversity Analysis

29. Fuel Diversity Implications • Fuel diversity issues are important to system reliability • Each fuel has infrastructure concerns • Coal: Strikes and Transportation • Residual Oil: Global supply disruption • Natural Gas: Pipeline security / delivery precedence • Distillate Oil: Limited inventory and resupply capability • Hydro is affected by rainfall • Transmission will shift fuel consumption from export constrained sub-areas to import constrained areas • Transmission may impede the utilization of available fuels • LOLE risk may increase with fuel constraints • Fuel policies may be influenced by transmission constraints • Critical Variables: Fuel inventories, winter demands for natural gas

30. Reference Case GWh Generation by Fuel Type - 2002

31. Reference Case GWh Generation by Fuel Type - 2006

32. Effect of Constraints - GWh Generation by Fuel Type - 2002

33. Effect of Constraints - GWh Generation by Fuel Type - 2006

34. Insufficient Fuel Diversity Increases Reliability Risk • Reliability implications of fuel diversity not well understood • Qualitative understanding provides “warm fuzzy” feeling • Quantitative understanding much more difficult to obtain • Expected fuel inventories are not known • Resupply infrastructure is not known • Gas available for electric generation affected by priority uses • Winter day demand for natural gas is primary risk • The colder the day, the less is available for electric generation • Firm transportation could send remaining gas outside • Alternative fuel (e.g.. distillate oil) inventories may be insufficient for sustained reliance

35. Fuel Diversity Analysis Framework • Framework for analysis is under development for future analysis • Results presented here are conceptual • Solicit comments from TEAC for future analysis • Use a Monte Carlo based reliability model • Include fuel designations for each unit • Include a heat rate for fuel efficiency (Btu/kWh) • Allocate scarce fuels to most efficient resources • Respect transmission constraints • Provide results in terms of LOLE by RTEP sub areas • The IREMM model’s multi-area reliability module was used for this analysis

36. Effect of Combined Distillate and Natural Gas Fuel Constraint Variation of LOLE with the Changes of Distillate Limits Fuel Availability in Terms of Percent of Unconstrained Fuel Consumption 2.5 2 1.5 1 0.5 0 20% 40% 60% 80% 100% Percentage of Distillate Fuel Oil Value (100% = unconstrained consumption) NG = 100% NG = 80 % NG = 60 % NG= 40 % Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

37. BHE BOST DEC CT CMAN NOV ME OCT SEP NH AUG JUL NOR RI JUN MAY SEMA APR SME MAR SWCT VT FEB JAN WEMA Effect of Combined Distillate and Natural Gas Fuel Constraint Sub-area Monthly LOLE (NG = 100 %, Distillate = 40 ) 2 1.8 1.6 1.4 1.2 1 LOLE( Days/Year) 0.8 0.6 0.4 0.2 0 Note: This is a Preliminary Illustrative Example Subarea Month

38. BHE BOST CMAN CT DEC NOV ME OCT SEP NH AUG NOR JUL RI JUN SEMA MAY SME APR MAR SWCT VT FEB JAN WEMA Effect of Combined Distillate and Natural Gas Fuel Constraint Sub-area Monthly LOLE (NG = 40%, Distillate = 40%) 2 1.8 1.6 1.4 1.2 1 LOLE( Days/Year) 0.8 0.6 0.4 0.2 0 Note: This is a Preliminary Illustrative Example Subarea Month

39. Fuel Diversity Analysis Future Work • Future effort is required to develop an understanding of: • Fuel constraints and interaction with transmission constraints • Interpretation of resulting reliability indices • Fuel constraints are based on many variables • Data is not readily available • Fuel inventory • Actual fuel switching capability of units • Fuel inventory re-supply infrastructure • Gas Pipelines: delivery, competing uses (LDC) and pass-through • Formal Benchmark of the IREMM model’s multi-area reliability module with MARS and Westinghouse is needed

40. RTEP02 Environmental Assumptions and Results A presentation to the Transmission Expansion Advisory Committee (TEAC) July 31, 2002 Scott HodgdonPower Supply & Reliability ISO New England Inc.

41. Purpose • Understand the impacts that proposed transmission upgrades may have on New England’s fossil-fueled generator’s air emissions. • Estimate New England total emissions of SO2, NOX, and CO2. • Results based on IREMM production simulations used in congestion cost analysis.

42. Emission Rate Assumptions

43. Emission Rate Assumptions • Developed in conjunction with the NEPOOL Environmental Planning Committee • Emission rates developed using a hierarchy of data sources • US EPA Scorecard 2000 • Henwood Energy Services Inc. (HESI) GenReporter • US EPA E-Grid 2000 • HESI estimation • Annual average values.

44. Emission Rate Assumptions • New Combined Cycle Unit Emission Rate Estimates (M = 106) • SO2 = 0.0006 lbs/MBtu • NOX = 0.01 lbs/MBtu • CO2 = 117 lbs./MBtu

45. Emission Rate Assumptions Total Capacity by Emission Rate Assumptions Reference

46. Emission Rate Assumptions • Existing generating unit emission rates affected by state regulations/legislations • Connecticut • Massachusetts • Other state’s regulations are not modeled because they are not applicable to the study timeframe

47. Emission Rate Assumptions Connecticut State Legislations/Regulation Assumptions

48. Emission Rate Assumptions Massachusetts Compliance Standards and Dates • Compliance path is the dates that a station is scheduled to meet the state emission standards. • Generating stations compliance path depicted by their Emission Control Plans (2 stations on Path I and 4 on path 2) • The value of X can be found in each stations Emission Control Plans

49. Emission Calculations

50. Emission Calculations • Total aggregate emissions for New England calculated using: • Unit emissions rates (lbs/MBtu) • Annual fuel use as output from the IREMM production simulation runs from congestion cost analysis • Emission formula