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RSP05 Emissions Analysis Results

RSP05 Emissions Analysis Results. Scott Hodgdon PAC04 – May 4, 2005. Assumptions. Most assumptions used in the analysis have been presented in PAC01, PAC02, and PAC03. Additional assumptions, specific to the IREMM model, are presented here. IREMM Specific Assumptions. Fuel costs

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RSP05 Emissions Analysis Results

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  1. RSP05 Emissions Analysis Results Scott Hodgdon PAC04 – May 4, 2005

  2. Assumptions • Most assumptions used in the analysis have been presented in PAC01, PAC02, and PAC03. • Additional assumptions, specific to the IREMM model, are presented here.

  3. IREMM Specific Assumptions • Fuel costs • Interchange with surrounding Control Areas • Transmission interface limit assumptions

  4. Fuel Price Forecast • Fuel price forecast based on Energy Information Administration’s forecast • March 2005 Short Term Energy Outlook (STEO) for 2005 & 2006 • “Reference Case” forecast was used • Dec 2004 Annual Energy Outlook (AEO) for 2008 through 2014 • Fuel price in 2007 is the average of 2006 from STEO and 2008 from AEO

  5. Fuel Price Forecast (RSP05)

  6. Fuel Price ComparisonRSP05 Forecast - RTEP04 Forecast

  7. Interchange Assumptions for IREMM • NY - VT • 85 MW import –NYPA contract (All hours) • NB - BHE • 200 MW fixed import (All hours) • 500 MW (800 MW after 2007) import modeled as a gas fired combined cycle unit (Dispatchable based on price) • Cross Sound Cable - CT • 300 MW load in CT Sub-area (All hours)

  8. Interchange Assumptions for IREMM • HQ Phase II – CMA/NEMA • 300 MW fixed import (All hours) • 500 MW import modeled as a gas fired combined cycle unit (Dispatchable based on price) • 500 MW import modeled as a gas fired steam unit (Dispatchable based on price) • 200 MW import modeled as a distillate GT (Dispatchable based on price) • HighGate - VT • 210 MW fixed import (All hours)

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

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

  11. Basecase Annual Air Emissions

  12. Decreases in 2007 & 2009 due to state (MA) regulation assumptions.

  13. Decreases in 2007 due to state (MA) regulation assumptions.

  14. No regulations assumed to affect generator CO2 emission rates therefore total CO2 emissions increasing with load growth.

  15. Modeled Capacity Factors

  16. 2006 Air Emissions and Changes in Price of Natural Gas

  17. As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate at 155% and 80% of the base price of natural gas (all else remaining constant).

  18. As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate at 155% and 80% of the base price of natural gas (all else remaining constant).

  19. As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate at 155% and 80% of the base price of natural gas (all else remaining constant).

  20. 2006 Air Emissions and Changes CMA/NEMA Load

  21. Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.

  22. Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.

  23. Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.

  24. 2006 Decreases in CMA/NEMA Load Due to DG/Renewables

  25. DG Emission Rate • As covered in PAC03 presentation, the following emission rates were used in the emission calculations.

  26. Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate SO2 emissions could be decreased from or equal to (Uncontrolled Diesel Engine) those produced without a reduction in New England load.

  27. Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate NOX emissions would increase from the case without a reduction in New England load.

  28. Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate NOX emissions would slightly increase (Uncontrolled Microturbines) or decrease (other listed options) from the case without a reduction in New England load.

  29. Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate CO2 emissions would increase from the case without a reduction in New England load. If the load reduction was achieved with renewable resources or demand side management, the total CO2 emissions would decrease.

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