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TEAC5

TEAC5. October 15, 2001 Sheraton Hotel Framingham, Massachusetts. TEAC5 Agenda. Welcoming Remarks TEAC Process MARS Results DSM/Resource Addition Impacts on Congestion RTEP02 Work Plan Status of Active Transmission Studies. TEAC Process. Beginning RTEP02 Effort

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TEAC5

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  1. TEAC5 October 15, 2001 Sheraton Hotel Framingham, Massachusetts

  2. TEAC5 Agenda • Welcoming Remarks • TEAC Process • MARS Results • DSM/Resource Addition Impacts on Congestion • RTEP02 Work Plan • Status of Active Transmission Studies ISO-NE TEAC5 10/15/01

  3. TEAC Process • Beginning RTEP02 Effort • Continuation of TEACMATTERS@iso-ne.com • ISO web site for postings • Plan meetings every six weeks ISO-NE TEAC5 10/15/01

  4. Sub-Area Resource Adequacy Assessment using GE MARS Presentation to TEAC October 15, 2001

  5. Presentation Overview • Objectives of the Assessment • Why we need to use GE MARS • Comparison of GE MARS and ABB Westinghouse • Cases Studied and the Results • What’s Next? ISO-NE TEAC5 10/15/01

  6. Objectives of the Assessment • To assess the reliability of the New England bulk power generation system taking into account internal transmission limits. • The assessment covers the 2002 through 2006 time period with assumptions that are consistent with the 2001 Regional Transmission Expansion Plan (RTEP01) • The results supplement RTEP01. ISO-NE TEAC5 10/15/01

  7. Why we need to use GE MARS • Traditionally generation reliability analyses were conducted using a single-bus methodology (ABB Westinghouse Program). • NEPOOL generation interconnection standards required the full integration of generating resources. • With the advent of deregulation, NEPOOL modified its rules to allow for a Minimum Interconnection Standard. ISO-NE TEAC5 10/15/01

  8. Why we need to use GE MARS • Less stringent interconnection standard coupled with market forces has promoted the installation of merchant generation and many such units will be added to the NEPOOL system during 2002 to 2006. • Many of these generation units are in regions in which existing transmission facilities are inadequate to handle the additional supply. • It has become necessary to model the transmission limits on the bulk power system using a multi-area model, hence the use of GE MARS. ISO-NE TEAC5 10/15/01

  9. Comparison of Westinghouse and MARS • Program Basics • Westinghouse is a Single Area program whereas MARS is a Multi-Area program. • Westinghouse uses probabilistic calculations to capture the random nature of loads and unit availability whereas MARS uses a sequential Monte Carlo simulation. ISO-NE TEAC5 10/15/01

  10. Comparison of Westinghouse and MARS • Load Representation • Westinghouse load model is probabilistic and uses distributions of daily peak loads for a week, explicitly taking into account load uncertainty. The load model is developed from only weekday peaks and excludes weekend loads. This assumes that weekend loads will contribute negligibly to the system risk. • The MARS load model is chronological. Chronological hourly load data(8760/8784 hours) must be input in standard EEI format. ISO-NE TEAC5 10/15/01

  11. Comparison of Westinghouse and MARS • Mars can include the effects of load uncertainty through the use of load multipliers. Load multipliers are per unit multipliers used for computing the loads for which to calculate the reliability indices. Each per unit multiplier represents a load level (up to ten can be represented in MARS), which is assigned a probability of that load level occurring. The mean or 1.0 multiplier, represents the forecast peak load and the cumulative probabilities of a normal distribution define the probabilities for each multiplier. The multipliers are allowed to vary by month. ISO-NE TEAC5 10/15/01

  12. Comparison of Westinghouse and MARS • Maintenance Scheduling • Both programs have options for user specified or automatic maintenance scheduling. • For automatic maintenance scheduling, Westinghouse schedules maintenance in such a way as to levelize the weekly reliability throughout the year. MARS schedules maintenance to levelize reserves on either an area, pool or system basis. ISO-NE TEAC5 10/15/01

  13. Comparison of Westinghouse and MARS • Simulation of Unit Outages • In Westinghouse the expected amount of unavailable capacity on the system as a result of forced outages is the product of the capacity and forced outage rate of each individual unit summed for all units that are available to the system to serve load. ISO-NE TEAC5 10/15/01

  14. Comparison of Westinghouse and MARS • Since MARS is based on a sequential Monte Carlo simulation, it uses state transition rates to model the random forced outages of units. From the transition rates for a unit, the program calculates 2 primary quantities that are needed to model the random forced outages of the unit: the average (mean) time that the unit resides in each capacity state, and the probability of the unit transitioning from each state to each other state. Each time a unit changes capacity states, 2 random numbers are generated. The first is used to calculate the amount of time that the unit will spend in the current state. It is assumed that the time in a state is exponentially distributed. The second random number is combined with the state transition probabilities to determine the state to which the unit will transition when it leaves its current state. ISO-NE TEAC5 10/15/01

  15. Comparison of Westinghouse and MARS • Daily LOLE Computation • In Westinghouse the system margin density is generated for each week of the year by combining the load density for the week with the corresponding available capacity density. The negative portion of the margin density represents the average daily LOLE for the week. The program calculates and outputs the LOLE for 13 four week periods during the year and for the full year. ISO-NE TEAC5 10/15/01

  16. Comparison of Westinghouse and MARS • In MARS daily LOLE is calculated for the hour at which the Pool peaks and each sub-area’s LOLE is calculated at that hour. The reliability of the pool as a whole is determined by the reliability of the individual sub-areas in the pool. In other words if a sub-area is experiencing a loss of load for the hour that the pool peaks, the pool itself is considered to be in a loss of load state. ISO-NE TEAC5 10/15/01

  17. Cases Studied using GE MARS(using RTEP01 assumptions) • Single Area Case • Base Case • NB 700 MW Case • NB and HQ Import Case • Cross Sound Cable Import and Export Cases • Attrition Cases ISO-NE TEAC5 10/15/01

  18. Summary of GE MARS Results • The reliability of the NEPOOL System decreases when internal transmission limits are reflected in the reliability assessment. This indicates the existence of internal transmission constraints. ISO-NE TEAC5 10/15/01

  19. Summary of GE MARS Results • From an import perspective, the SWCT Import Interface is the most constraining. This interface limits the amount of power that can flow into the SWCT and NOR sub-areas. ISO-NE TEAC5 10/15/01

  20. Summary of GE MARS Results • From an export perspective, the SEMA-RI Export limit is the most constraining, indicating locked in generation behind this interface. • NEPOOL reliability would significantly deteriorate if the 14 “high environmental impact” plants or an equivalent amount of other generation were to become unavailable starting from Year 2002. • The Cross Sound Cable could provide increased system reliability. ISO-NE TEAC5 10/15/01

  21. MARS Single-Area Results (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  22. MARS Sub-Area Results - Base Case (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  23. MARS Sub-Area Results - NB 700 MW Import (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  24. MARS Sub-Area Results - NB and HQ Import (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  25. MARS Sub-Area Results - Cross Sound Cable Export (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  26. MARS Sub-Area Results - Cross Sound Cable Import (LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  27. MARS Sub-Area Results - Attrition Cases (NEPOOL LOLE in Days Per Year) ISO-NE TEAC5 10/15/01

  28. What’s Next? • Further work on understanding the differences between the GE MARS and ABB Westinghouse Models. • Policy issues concerning the need for a sub-area reliability criterion will need to be addressed. ISO-NE TEAC5 10/15/01

  29. ISO-NE TEAC5 10/15/01

  30. DSM Impacts on Transmission Congestion Presentation to TEAC October 15, 2001

  31. Transmission Congestion • Congestion is caused by: • Imbalance in the location of supply vis-a-vis demand • Demand for electricity is a function of many factors: • Customer type • Day of the week • Hour of the day • Season of the year • Weather • etc. • Supply of electricity may be available, but • transmission may not be sufficient to transport to demand • fewer suppliers that can deliver increases market concentration • increased concentration leads to ability to influence prices ISO-NE TEAC5 10/15/01

  32. Demand is Determined by Aggregate Customer Actions • Most Demand is Inelastic • Generation is required to supply any and all demand • Customers have unlimited “call option” for power • Limited ability to shape customer demand • Customer perceived Value Of Lost Load (VOLL) is high • Large classes of consumers need and expect supply certainty • But • Some customers have flexibility • Short notice ability to change consumption • Day-ahead ability to change consumption • Change in consumption • Reduce kWh consumption • Self generation ISO-NE TEAC5 10/15/01

  33. DSM Alternatives • There are two primary DSM alternatives • Customer reduction in consumption • Conservation • Real Time Response • Customer self-generation • Cogeneration / self serving generation • Utilization of unused standby resource ISO-NE TEAC5 10/15/01

  34. DSM Cost Assumptions • Cost Assumptions for DSM can be handled in several ways • Conservation and Customer Self Generation • Economic value is internalized by customers • No explicit assumptions • Effect is seen through reduced demand from LSEs • Price Responsive DSM • Need a strike price (dispatch price) for responsiveness • Use of standby resources may be relatively inexpensive • Use of routine “price responsive” DSM may be inexpensive • Extraordinary “price responsive” DSM may be expensive • Study assumed $140/MWh for price responsive DSM ISO-NE TEAC5 10/15/01

  35. DSM Alternatives Investigated • Two cases investigated: • General Conservation • All loads reduced by 1.4 percent • Equal conservation throughout New England • Approximately one year load growth delay • Could be Fluorescents, Fuel Cells or Cogeneration • Price Responsive DSM • Resources located in NOR, SWCT, CT, BOST • 500 MW total (125 MW in each Sub-area) • Could be demand reduction • Could be use of standby emergency generators • CMS assumed in place at the start of 2002 ISO-NE TEAC5 10/15/01

  36. RTEP Sub- Areas and “Price Responsive” DSM 125 MW DSM 125 MW DSM 125 MW DSM 125 MW DSM ISO-NE TEAC5 10/15/01

  37. VT Load 1353879 MW Under Construction RTEP LoadCapacity Peak Load and Installed Capacity MW by Area - 2006 NB-NE - 700 Phase II - 1500 Highgate - 225 HQ NB Orrington South - 1050 Surowiec South - 1150 ME-NH -1400 ME S-ME BHE Load 11561093 MW Load 5751493 MW Load 376874 MW NH Load 19143590 MW Boston - 3600 East-West - 2150 BOSTON North-South - 2700 Load 52573984 MW NY-NE - 1400w/o Cross Sound Cable W-MA CMA/NEMA Load 20413654 MW Load 1548243 MW NY SEMA/RI - 1600 SEMA RI CT Load 23293346 MW CSC -330 Load 20585419 MW Load 33194359 MW South West CT - 1700 SEMA - 1000 KEY: Connecticut - 2500 NOR Regional Transmission Expansion Plan Sub-area SWCT Load 1129463 MW Load 26622112 MW Priority Studies Required Norwalk-Stamford - 1100 Other Studies Required

  38. Conservation Results • Because loads are reduced by one year’s load growth • Congestion is “delayed” by one year • Effect is seen across all RTEP zones • Static analysis did not consider • Delay of resource additions in response to conservation • Accelerated unit retirements due to reduced growth • Conservation may delay the need for generation or transmission improvements • Need to separate cost reductions due to fewer kWh sales and the impact on transmission congestion ISO-NE TEAC5 10/15/01

  39. Difference in Total LSE Expense Cost – Conservation Case Total cost to LSEs is reduced $530 Million from lower sales ISO-NE TEAC5 10/15/01

  40. Difference in Congestion Cost – Conservation Case Total congestion is reduced $165 Million compared to the results of the reference case where generators are assumed bidding in at approximately fuel cost (Case 1A). ISO-NE TEAC5 10/15/01

  41. “Price Responsive” DSM Results – NOR and SWCT The impact of DSM in SWCT / NOR suggests that the average annual energy cost savings of $52 Million is attributed to 250 MW of DSM within the SWCT / NOR sub-areas. These savings are probably sufficient to induce not only DSM, but also new generating resources. Effect of price responsive DSM in CT and BOST was negligible Location of price responsive DSM is important ISO-NE TEAC5 10/15/01

  42. RTEP02 Work Plan Presentation to TEAC October 15, 2001

  43. Building on the RTEP01 Process • RTEP02 will be a follow-up to the RTEP01 recommendations • ISO-NE seeking TEAC Input • Several Work Streams ISO-NE TEAC5 10/15/01

  44. Short-Term Upgrades • SWCT to address the reliability concerns • SEMA/RI to address locked in generation ISO-NE TEAC5 10/15/01

  45. Reliability Analysis -MARS • 2003 - 2012 Time Frame • Assumptions on New Units/Retirements • Load Forecast by Sub-Area • Update Transfer Limits • Run Cases ISO-NE TEAC5 10/15/01

  46. Congestion Mitigation • Determine economic benefits to improvements over RTEP01 Base Case • SEMA/RI Export • Maine Export • SWCT Import • Boston Import • Screen Recommendations ISO-NE TEAC5 10/15/01

  47. Congestion Mitigation • Conceptual Upgrade Studies • Transfer Limit Improvements • Cost Estimates ISO-NE TEAC5 10/15/01

  48. Congestion Mitigation • Refine Congestion Estimates based on transfer Limits from Conceptual Studies • Base Cost Benefit Analysis • Emission Impacts of Upgrades • SCED Analysis • Screen for Market Responses • Formulate Recommendations • RFP Process - TBD ISO-NE TEAC5 10/15/01

  49. Revisit RTEP01 Assumptions(2002 -2006) • Fuel Cost Estimates • New Units • Transmission Upgrades • Load Forecast • Update Congestion Estimates as Required ISO-NE TEAC5 10/15/01

  50. RMR Issues • Examine History and Costs • Confidentiality Issues • Determine Root Causes • Screen for Sub-Area Transfer Problems • Determine if Studies are Warranted ISO-NE TEAC5 10/15/01

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