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Modeling Work Group Discussion Points

Modeling Work Group Discussion Points

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Modeling Work Group Discussion Points

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  1. Modeling Work GroupDiscussion Points MWG Meeting June 6, 2011 Web Meeting

  2. Tentative Agenda • Welcome and business Tom Miller • COI Nomogram Results Stan Holland • Gridview Comparison Discussion • Modeling Southern California Thermal Discussion • New- Modeling California Cap and Trade Discussion • Other? • Next Meeting Tom Miller

  3. PROMOD run w Updated COI Nomogram • Updated the COI Nomogram based on parameters provided by Sherman Chen • Nomogram models 2011 Spring AC/DC Nomogram from CAISO • 4 nomogram segments based on percent of Northern California hydro • Not a significant difference in the COI flow versus run using old nomogram

  4. COI Flows The run with new COI nomogram (PC0_98COI) overlays run with old nomogram (PC0_84)

  5. COI Nomogram 90 – 100% COI Nomogram 1 = COI + Alturas + .53(NCal Hydro) The upper limit is 6378 MW

  6. COI Nomogram 80 – 90% COI Nomogram 2 = COI + Alturas + .41(NCal Hydro) Upper Limit = 5923 MW

  7. COI Nomogram 70 – 80% COI Nomogram 3 = COI + Alturas + .35(NCal Hydro) Upper Limit = 5726 MW

  8. COI Nomogram 60 – 70% COI Nomogram 4 = COI + Alturas + .29(NCal Hydro) Upper Limit = 5549 MW

  9. COI AC/DC Nomogram - Spring

  10. Sample COI Nomogram Results Nomogram not binding as NCal Hydro less than 2000 MW. The assumed maximum NCal Hydro is 4245 MW, although many of the units have monthly derates that reduce the maximum output level.

  11. More Nomogram Results

  12. More Nomogram Results Hard to tell if Ncal Hydro is causing nomograms to be binding.

  13. N. Cal. Hydro Duration Plot

  14. COI Flow – PC2 High Load case This shows that the COI flow is sensitive to the load forecasts. The difference in load between the Promod PC0 and Gridview PC0 was 3.2%. The PC2 loads were about 4% higher than the PC0 loads. Without the same loads the comparison is invalid.

  15. Input/Run Assumptions

  16. Input/Run Assumptions (2)

  17. PDCI Comparison PROMOD’s piece-wise linear DC loss implementation is obvious, but results compare well with 2008 historical.

  18. Discussion • How can a true “apples to apples” comparison be accomplished? • What is purpose of comparison? • What is the effect of changes between the 2008 and 2020 systems?

  19. Southern California Local Area Requirements • Imports into Southern California is supported by inertia • Today’s existing fleet of Units provides majority of inertia (mass) • Peaker and renewables have small to insignificant inertia • If high imports can not be supported then many more new resources are needed into the load pockets then retired • Peakers have usually higher energy costs and higher rates of emissions • Limits based on the percentage of Under-Frequency Load Shedding (UFLS) requirements for the individual Participating Transmission Owner’s (PTO’s) area • California Long-term Planning Study • LA Basin 60/40 Rule: there needs to be generation equal to 40 percent of load at all times • SDG&E 75/25 Rule: : there needs to be generation equal to 25 percent of load at all times • '*San Onofre 2 & 3 Units contribute 80% of their generation to the SCE Min Gen Requirements, and 20% of their generation to the SDGE Min Gen Requirements • SCE has provided Lists of units that can support

  20. California Cap and Trade • Uncertainty about what GHG costs will be. • $10/ton floor starting 2012 for CA Plants • Escalate at 5% + CPI • Imports: • Unspecified Resource: .435 metric tons/MWh about 8215 mmbtu/MWh on NG • LADWP Intermountain Coal: .95 metric tons/MWh • SB 1368 Coal Imports (2020): 1100lbs/MWh higher Base Load (contract term no longer than 5-years at 50% capacity factor) • GHG Costs downstream from liquid trading hubs: hence no change in wholesale price of NG • Modeling Question: • California as an “island” or WECC-Wide GHG cost? • CA Imports “Hurdle” rate raise to account for emission costs? • Next Steps

  21. Wrap-up and Next meeting • Wrap-up • Next meeting • Not first Monday of July – Holiday

  22. Questions?