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Modeling Work Group Discussion Points MWG Meeting June 6, 2011 Web Meeting.

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Presentation on theme: "Modeling Work Group Discussion Points MWG Meeting June 6, 2011 Web Meeting."— Presentation transcript:

1 Modeling Work Group Discussion Points MWG Meeting June 6, 2011 Web Meeting

2 2 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 Tentative Agenda

3 3 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 PROMOD run w Updated COI 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 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 15 ElementPROMOD Gridview Study Case2020 PC0 (w/o IPP nomogram) Load ForecastPC0 LRS forecast AC LossesSingle Pass (no impact to loads, but applied to gen dispatch) Full loss (loads increased by transmission losses) DC LossesI 2 R (reduced penalty) Hydro - HTCCanada 42% Northwest 50% California 46% COI + Alturas Limit5100 MW COI NomogramUpdated version from Sherman IPP DC NomogramTurned offTurned on (generation forced onto line) Input/Run Assumptions

16 16 ElementPROMOD Gridview John Day vs COI/PDCI nomograms Not updated since 2008 SCE Import NomogramFall 2010 version Hurdle RatesNot updated Maintenance OutagesFixed schedule Forced OutagesRandom pattern generated by Promod Gas Prices$7.28 Henry Hub (2010 $) with monthly profile Gas TransportNPCC Inferred Values Conversion changesn/aSpecify reference buses Correct impedance issues Correct other data issues Input/Run Assumptions (2)

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

18 18 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? Discussion

19 19 Imports into Southern California is supported by inertia –Todays 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 Owners (PTOs) 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 Southern California Local Area Requirements

20 20 Uncertainty about what GHG costs will be. o $10/ton floor starting 2012 for CA Plants o Escalate at 5% + CPI Imports: o Unspecified Resource:.435 metric tons/MWh about 8215 mmbtu/MWh on NG o 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: o California as an island or WECC-Wide GHG cost? o CA Imports Hurdle rate raise to account for emission costs? o Next Steps California Cap and Trade

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

22 Questions?

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