modeling work group discussion points mwg meeting june 6, 2011 web meeting
TRANSCRIPT
Modeling Work GroupDiscussion Points
MWG Meeting
June 6, 2011
Web Meeting
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• 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
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• 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
COI Flows
The run with new COI nomogram (PC0_98COI) overlays run with old nomogram (PC0_84)
COI Nomogram 90 – 100%
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
COI Nomogram 1 - Daily Max/Min/Ave (MW)
COI Nomogram 1 = COI + Alturas + .53(NCal Hydro)The upper limit is 6378 MW
COI Nomogram 80 – 90%
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
COI Nomogram 2 - Daily Max/Min/Ave (MW)
COI Nomogram 2 = COI + Alturas + .41(NCal Hydro)Upper Limit = 5923 MW
COI Nomogram 70 – 80%
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
COI Nomogram 3 - Daily Max/Min/Ave (MW)
COI Nomogram 3 = COI + Alturas + .35(NCal Hydro)Upper Limit = 5726 MW
COI Nomogram 60 – 70%
0
1,000
2,000
3,000
4,000
5,000
6,000
COI Nomogram 4 - Daily Max/Min/Ave (MW)
COI Nomogram 4 = COI + Alturas + .29(NCal Hydro)Upper Limit = 5549 MW
COI AC/DC Nomogram - Spring
Sample COI Nomogram Results
0
1000
2000
3000
4000
5000
6000
4/13/2020 4/14/2020 4/15/2020 4/16/2020 4/17/2020
COB Flow with Nomograms (NCal Hydro)
NCH-100
NCH-90
NCH-80
NCH-70
NCH-60
COB
NCalHydro
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.
More Nomogram Results
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
7/23/2020 7/24/2020 7/25/2020 7/26/2020 7/27/2020
COB Flow with Nomograms (NCal Hydro)
NCH-100
NCH-90
NCH-80
NCH-70
NCH-60
COB
NCalHydro
More Nomogram Results
Hard to tell if Ncal Hydro is causing nomograms to be binding.
N. Cal. Hydro Duration Plot
0
500
1000
1500
2000
2500
3000
3500
4000
4500
118
436
755
073
391
610
9912
8214
6516
4818
3120
1421
9723
8025
6327
4629
2931
1232
9534
7836
6138
4440
2742
1043
9345
7647
5949
4251
2553
0854
9156
7458
5760
4062
2364
0665
8967
7269
5571
3873
2175
0476
8778
7080
5382
3684
1986
02
Meg
awatt
s
Northern California Hydro Duration Plot
NCalHydro
NCH60
NCH70
NCH80
NCH90
NCH100
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.
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Element PROMOD 9.8.04 Gridview
Study Case 2020 PC0 (w/o IPP nomogram)
Load Forecast PC0 LRS forecast
AC Losses Single Pass (no impact to loads, but applied to gen dispatch)
Full loss (loads increased by transmission losses)
DC Losses I2R (reduced penalty)
Hydro - HTC Canada 42%Northwest 50%California 46%
COI + Alturas Limit 5100 MW
COI Nomogram Updated version from Sherman
IPP DC Nomogram Turned off Turned on (generation forced onto line)
Input/Run Assumptions
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Element PROMOD 9.8.04 Gridview
John Day vs COI/PDCI nomograms
Not updated since 2008
SCE Import Nomogram Fall 2010 version
Hurdle Rates Not updated
Maintenance Outages Fixed schedule
Forced Outages Random pattern generated by Promod
Gas Prices $7.28 Henry Hub (2010 $) with monthly profile
Gas Transport NPCC Inferred Values
Conversion changes n/a Specify reference busesCorrect impedance issuesCorrect other data issues
Input/Run Assumptions (2)
PDCI Comparison
PROMOD’s piece-wise linear DC loss implementation is obvious, but results compare well with 2008 historical.
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• 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
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• 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
Southern California Local Area Requirements
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• Uncertainty about what GHG costs will be. o $10/ton floor starting 2012 for CA Plantso Escalate at 5% + CPI
• Imports: o Unspecified Resource: .435 metric tons/MWh about 8215 mmbtu/MWh on NGo 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
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• Wrap-up
• Next meetingoNot first Monday of July – Holiday
Wrap-up and Next meeting
Questions?