Module 1: MARKET OPERATIONS AND TRADING Scheduling, Pricing and Dispatch
Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
Presentation Outline Hour-ahead Real-time Dispatch (RTD) Effect of Transmission Loss Factor (TLF) on Dispatch and Usage on Scheduling Determination of Ex-ante Price (EAP), RTD Schedule and Ex-ante Quantity (EAQ) for Generator and Load Customer Real-time Expost Dispatch(RTX) Determination of Ex-post Price (EPP) for Generator and Load Customer Examples 2 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
HOUR-AHEAD REAL TIME DISPATCH (RTD) “Ex-Ante”
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HOUR-AHEAD REAL TIME DISPATCH (RTD) •It is the Hour-Ahead Dispatch Schedule which determines the target loading, in MW, of facilities at the end of the trading interval. •The RTD calculates the Ex-ante Nodal Prices.
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HOUR-AHEAD REAL TIME DISPATCH (RTD) MW 120
Initial MW (EAIQ) for H (Optimized by MMS)
Hour - Ahead Dispatch Schedule RTD/Target MW (EATQ) for H+1
100 80 60 40 20 0
Time H (Start of Trading Interval)
H+1 (End of Trading Interval) 5 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
RTD Market Trading Mechanism Trading Participant
Market Operator
System Operator
System Demand Forecast
Market Input Data: • Energy offers (Price, Quantity, Ramp Rate)
Market Management System
System Conditions: •System Snapshot •Outage Schedules •Security Limits •Contingency Lists •Transmission limits •Reserve Requirement
Market Dispatch Optimization Model (MDOM) •Pricing and Scheduling
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Table 1.1 - Generator Offers (Trading Participants) Region
Participant
Luzon Lhydro_G01 Lgeo_G01 Lcoal_G01 Ldiesel_G01 Lnat_G01 Visayas Vgeo_G01 Vcoal_G01 Vdiesel_G01 Total
Pmin (MW) 3,025.00 70.00 110.00 1,080.00 0 1,765.00 465.00 216.00 249.00 0 3,490.00
Quantity Price (MW) (Php/MWh) 6,312.20 684.60 1,000.00 369.00 270.69 2,400.60 2,168.32 143.00 7,469.00 2,715.00 -1.00 1,485.80 616.50 0.00 622.00 1,981.70 247.30 18,500.19 7,798.00
Ramp-rates (MW/min) RRDN RRUP 30 30 3 3 4 4 4 4 6 6 3 4 2
3 4 2
Note: Price-Qty Offer must be up to 10 energy blocks.
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Table 1.2 - System Demand Forecast (Market Operator) Region
Luzon Visayas Total
System Demand* Forecast (MW) 5,348 932.1 6,280.1
Note: * - System Demand = Demand + Losses
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General Constraint
Generation =
Losses
+
Demand
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Effect of Transmission Loss Factors on Dispatch •The incremental transmission losses based on the location of the resource with respect to the reference bus and flow of power on the grid •This factor is called the Transmission Loss Factor, or Penalty Factor
TLFi =
1 ∂PLoss 1 − ∂Pgen i
Change in System Losses
Change in Unit’s MW Output
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Usage of Transmission Loss Factors on Scheduling •The amount of power (MW) that needs to be generated/consumed at the resource bus in order to consume/supply 1MW at the reference bus (Richview). •The factor that is multiplied to the offer and bids to come up with a value of those offers and bids relative to the reference bus. 11 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
Usage of Transmission Loss Factors on Scheduling •An increment in generation results in an increase in system losses, • The price offer is adjusted higher
∂PLoss 0< <1 ∂Pgeni
TLFi =
1 ∂PLoss 1 − ∂Pgen i
>1
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Usage of Transmission Loss Factors on Scheduling •An increase in generation results in a decrease in system losses then: • The price offer is adjusted lower
∂PLoss 0> > −1 ∂Pgeni
TLFi =
1 ∂PLoss 1 − ∂Pgen i
<1
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Usage of Transmission Loss Factors on Scheduling •The generator adjusted as:
offer
price
will
be
Adjusted Offer Price = Offer x TLF
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Table 1.3 - Adjusted Generator Price Offers Region
Adjusted Offer Price (Php/MWh)
Participant
Offer Price (Php/MWh)
TLF
Lhydro_G01 Lgeo_G01 Lcoal_G01 Ldiesel_G01 Lnat_G01
1,000.00 270.69 2,168.32 7,469.00 -1.00
1.0000 0.9937 1.0013 0.9705 1.0483
1,000.00 268.98 2,171.14 7,248.66 -1.05
Vgeo_G01 Vcoal_G01 Vdiesel_G01
0.00 1,981.70 18,500.19
1.0243 0.9978 0.9974
0.0000 1,977.34 18,452.09
Luzon
Visayas
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Determination of Generator Dispatch Schedules and System Marginal Price System Demand Forecast
Price (P/MWh)
Adjusted Price Offers System Marginal Price, λ λ = (Price Offer x TLF)Marginal Plant
Non-contestable Qty
G2
G3
G4
G5G5
G1 Schedule
Quantity (MW)
Non-contestable Qty.: Pmin, Must-run Unit (MRU), New and Renewable Energy and/or Non-scheduled Generator
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Determination of Generator Dispatch Schedules and System Marginal Price Over-all System Demand Forecast 6,280.1 MW
Price (P/MWh)
V isayas System Demand Forecast 932.1 MW
Luzon System Demand Forecast 5,348 MW
System Marginal Price, λ= Php 2,171.1/MWh Marginal Plant: Lcoal_G01
Vdiesel_G01 Adj. P= 18452.09 Q = 247.3 Ldiesel_G01 Adj. P = 7248.66 Q = 143
Vgeo_G01 Adj. P= 0 Qty = 400.5
ΣPmin = 3,490 MW
Lgeo_G01 Adj. P = 268.98 Q = 259
Lhydro_G01 Adj. P= 1,000 Q = 614.6
Lcoal_G01 Adj. P= 2171.1 Vcoal_G01 Adj. P= 2002.51 Q= 193 Q = 373
Lnat_G01 Adj. P = -1.05 Q = 950
Quantity (MW) ΣGen Offer = 7,798 MW
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RTD HVDC Flow
HVDC Flow = 306.40 MW
Luz Gen Sched = 5,041.60 MW System Demand = 5,348 MW
Vis Gen Sched = 1,238.5 MW System Demand = 932.1 MW
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Table 1.4 - Generator Dispatch Schedules Participants
Offered Qty. (MW)
RTD* (MW)
Lnat_G01
2,715.00
2,715.00
Vgeo_G01
616.5
616.5
Lgeo_G01
369
369
Lhydro_G01
684.6
684.6
Vcoal_G01
622
622
Lcoal_G01
2,400.60
1,273.00
Ldiesel_G01
143
Not Cleared
Vdiesel_G01
247.3
Not Cleared
7,798.00
6,280.10
Total
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Determination of Load Nodal Schedules
∑ Gen
region
± HVDC
Nodal Load Pattern
System Snapshot Node 1 Node 2 Node 3
Nodal Demand Schedules per Region
MW →
MW →
System Demand Forecast per Region
LD Node 1
LD Node 2
LD Node 3
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Table 1.5 - Determination of Load Nodal Schedules System Demand Forecast: Load Demand Losses System (MW) Demand (MW) (MW) Region
Load MTN: Participants Luzon
RTD (MW) 5,260.60
Luzon
5260.6
87.4
5,348
LC01_L01
1,308.26
Visayas
915.3
16.8
932.1
LC02_L01
2,403.48
LC03_L01
1,548.86
Visayas
915.30
VC01_L01
101.00
VC02_L01
548.67
VC03_L01
151.27
VC04_L01
29.95
VC05_L01
84.40
Total
6,175.90 21
Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
Table 1.6 - Generator and Load Nodal Schedules Generator MTN: Participants Lnat_G01
RTD (MW) 2,715.00
Vgeo_G01
616.50
Lgeo_G01 Lhydro_G01
369.00 684.60
Vcoal_G01
622.00
Lcoal_G01
1,273.00
Ldiesel_G01
0.00
Vdiesel_G01
0.00
Total
6,280.10
Load MTN: Participants Luzon LC01_L01 LC02_L01 LC03_L01 Visayas VC01_L01 VC02_L01 VC03_L01 VC04_L01 VC05_L01 Total
RTD (MW) 5,260.60 1,308.26 2,403.48 1,548.86 915.30 101.00 548.67 151.27 29.95 84.40 6,175.90
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Determination of Scheduled Nodal Energy Generation/Consumption MW
Initial MW (EAIQ) for H
Hour - Ahead Dispatch Schedule RTD/Target MW (EATQ) for H+1
120 100
EAQ 80 60
= ½(EAIQ+ EATQ) EAQ – Ex-ante Qty EAIQ – Ex-ante Initial Qty.
40 20
EATQ – Ex-ante Target Qty. Scheduled Nodal Energy Generation / Consumption
0
Time H (Start of Trading Interval)
H+1 (End of Trading Interval) 23 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
Table 1.7 - Forecasted/Scheduled Nodal Energy Generation/Consumption Ex-ante Quantity (EAQ) Generator MTN: EAIQ Resources (MW) Lcoal_G01 1,084.95
Load MTN: EATQ (MW) 1,273.00
EAQ (MWh) 1,178.97
Lgeo_G01
239.05
369.00
304.02
Lhydro_G01
794.48
684.60
739.54
Lnat_G01
2,369.89
2,715.00
2,542.44
Vcoal_G01
349.35
622.00
485.67
Vgeo_G01 Ldiesel_G01 Vdiesel_G01
467.60 0 0
616.50 0 0
542.05 0 0
Total
5,305.31
6,280.10
5,792.70
Resources EAIQ (MW) EATQ (MW) EAQ (MWh) LC01_L01
1,165.40
1,308.26
1,236.83
LC02_L01
1,862.80
2,403.48
2,133.14
LC03_L01
1,490.30
1,548.86
1,519.58
VC01_L01
82.80
101.00
91.90
VC02_L01
392.20
548.67
470.43
VC03_L01
120.80
151.27
136.04
VC04_L01
26.30
29.95
28.13
VC05_L01
70.90
84.40
77.65
Total
5,211.50
6,175.90
5,693.70
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Nodal Prices/Locational Marginal Prices (LMP) Marginal cost of supplying the next increment of electric energy at a specific location while considering the generation marginal cost and the physical aspects of the transmission system. LMP
=
Generation Price (SMP)
LMPi =
λ
Cost of Losses
+
1
+
TLF i
1
+
*λ +
Transmission Congestion Cost
Σ µj aij
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Nodal Prices/Locational Marginal Prices (LMP) If no congestion occurs, λ LMPi = TLF i Generator:
PFi = TLFi =
Load:
1 1 − ∂PL ∂Pgen i
PFi = TLFi =
1 1 + ∂PL ∂Pload i
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Table 1.8 - Ex-ante Price (EAP) Nodal Price / Locational Marginal Price (LMP) Load MTN:
Generator MTN: Resources
TLF
Lnat_G01 Vgeo_G01 Lgeo_G01 Lhydro_G01 Vcoal_G01 Lcoal_G01 Ldiesel_G01 Vdiesel_G01
1.0483 1.0243 0.9937 1.0000 1.0105 1.0013 0.9705 0.9974
EAP (Php/MWh) 2,071.10 2,119.63 2,184.90 2,171.10 2,148.58 2,168.32 2,237.13 2,176.80
Resources
TLF
LC01_L01 LC02_L01 LC03_L01 VC01_L01 VC02_L01 VC03_L01 VC04_L01 VC05_L01
0.9704 0.9752 1.0046 0.9919 1.0096 0.9714 0.9611 0.8503
EAP (Php/MWh) 2,237.36 2,226.35 2,161.20 2,188.87 2,150.49 2,235.06 2,259.01 2,553.38
λ= Php 2,171.1/MWh
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REAL TIME EX-POST DISPATCH (RTX) “Ex-post”
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REAL TIME EX-POST DISPATCH (RTX) •It is a real time dispatch schedule process performed at the end of a trading interval utilizing actual operations data. •The RTX calculates the Ex-post Nodal Prices. 29 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
RTX Market Trading Mechanism Trading Participant
Market Operator
Market Input Data: • Energy offers (Price, Qty, and Ramp Rate
Market Management System
System Operator
System Condition: •System Demand (System Snapshot ) •Outage Schedules •Security Limits •Contingency Lists •Transmission limits
Market Dispatch Optimization Model (MDOM) •Pricing and Scheduling
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Table 1.9 - Generator Offers* (Trading Participants) Region
Participant
Luzon Lhydro_G01 Lgeo_G01 Lcoal_G01 Ldiesel_G01 Lnat_G01 Visayas Vgeo_G01 Vcoal_G01 Vdiesel_G01 Total
Pmin (MW) 3,025.00 70.00 110.00 1,080.00 0 1,765.00 465.00 216.00 249.00 0 3,490.00
Quantity Price (MW) (Php/MWh) 6,312.20 684.60 1,000.00 369.00 270.69 2,400.60 2,168.32 143.00 7,469.00 2,715.00 -1.00 1,485.80 616.50 0.00 622.00 1,981.70 247.30 18,500.19 7,798.00
Ramp-rates (MW/min) RRDN RRUP 30 30 3 3 4 4 4 4 6 6 3 4 2
3 4 2
Note: Same as Ex-ante
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Table 1.10 - RTX System Demand (System Operator) Region
Luzon Visayas Total
System Demand* (MW) 5,357.7 963.4 6,321.1
Note: * - System Demand = Genregion ± HVDC (Import/Export of power) - Based on the system snapshot at the end of the trading interval from SO
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Table 1.11 - Adjusted Generator Price Offers Region
Adjusted Offer Price (Php/MWh)
Resources
Offer Price (Php/MWh)
Lhydro_G01 Lgeo_G01 Lcoal_G01 Ldiesel_G01 Lnat_G01
1,000.00 270.69 2,168.32 7,469.00 -1.00
1.0000 0.9956 1.0004 0.9778 1.0442
1.0000 269.50 2,169.19 7,303.19 -1.04
Vgeo_G01 Vcoal_G01 Vdiesel_G01
0.00 1,981.70 18,500.19
1.0067 0.9961 0.9947
0.0000 1,973.97 18,402.14
TLF
Luzon
Visayas
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Determination of System Marginal Price Over-all System Demand 6,321.1 MW
Price (P/MWh)
V isayas System Demand Forecast 963.4 MW
Luzon System Demand Forecast 5,357.7 MW
System Marginal Price, λ= Php 2,169.19/MWh Marginal Plant: Lcoal_G01
Vdiesel_G01 Adj. P= 18402.14 Q = 247.3 Ldiesel_G01 Adj. P = 7303.19 Q = 143
Vgeo_G01 Adj. P= 0 Qty = 400.5
ΣPmin = 3,490 MW
Lgeo_G01 Adj. P = 269.50 Q = 259
Lhydro_G01 Adj. P= 1,000 Q = 614.6
Lcoal_G01 Adj. P= 2169.19 Vcoal_G01 Adj. P= 1973.97 Q= 234 Q = 373
Lnat_G01 Adj. P = -1.04 Q = 950
Quantity (MW) ΣGen Offer = 7,798 MW
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RTX HVDC Flow
HVDC Flow = 275.10 MW
Luz Gen Sched = 5,082.60 MW System Demand = 5,357.70 MW
Vis Gen Sched = 1,238.5 MW System Demand = 963.4 MW
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Table 1.12 - Ex-post Price (EPP) Nodal Price / Locational Marginal Price (LMP) Load MTN:
Generator MTN: Resources
TLF
EPP (Php/MWh)
Resources
TLF
Lnat_G01
1.0442
2,077.37
LC01_L01
0.9782
EPP (Php/MWh) 2,217.53
Vgeo_G01
1.0067
2,154.75
LC02_L01
0.9826
2,207.60
Lgeo_G01
0.9956
2,178.77
LC03_L01
1.0074
2,153.25
Lhydro_G01
1.0000
2,169.19
VC01_L01
0.9753
2,224.12
Vcoal_G01
0.9961
2,177.68
VC02_L01
1.0005
2,168.10
Lcoal_G01
1.0004
2,168.32
VC03_L01
0.9837
2,205.13
Ldiesel_G01
0.9778
2,218.44
VC04_L01
0.9569
2,266.89
Vdiesel_G01
0.9947
2,180.75
VC05_L01
0.8753
2,478.22
λ= Php 2,169.19/MWh Marginal Plant:Lcoal_G01 38 Philippine Electricity Market Corporation (PEMC) Copyright © 2012 by Philippine Electricity Market Corporation
Table 1.13 - Ex-ante and Ex-post Prices and Schedules (Generator MTN) Generator MTN: Resources Lcoal_G01 Lgeo_G01 Lhydro_G01 Lnat_G01 Vcoal_G01 Vgeo_G01 Ldiesel_G01 Vdiesel_G01
EAIQ (MW) EATQ (MW) EAQ (MWh) EAP (Php/MWh) EPP (Php/MWh) 1,084.95 1,273.00 1,178.97 2,168.32 2,168.32 239.05 369.00 304.02 2,184.90 2,178.77 794.48 684.60 739.54 2,171.10 2,169.19 2,369.89 2,715.00 2,542.44 2,071.10 2,077.37 349.35 622.00 485.67 2,175.93 2,177.68 467.60 616.50 542.05 2,119.63 2,154.75 0 0 0 2,237.13 2,218.44 0 0 0 2,176.80 2,180.75
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Table 1.14 - Ex-ante and Ex-post Prices and Schedules (Load MTN) Load MTN: Resources LC01_L01 LC02_L01 LC03_L01 VC01_L01 VC02_L01 VC03_L01 VC04_L01 VC05_L01
EAIQ (MW) EATQ (MW) EAQ (MWh) EAP (Php/MWh) EPP (Php/MWh) 1,165.40 1,308.26 1,236.83 2,237.36 2,217.53 1,862.80 2,403.48 2,133.14 2,226.35 2,207.60 1,490.30 1,548.86 1,519.58 2,161.20 2,153.25 82.80 101.00 91.90 2,188.87 2,224.12 392.20 548.67 470.43 2,150.49 2,168.10 120.80 151.27 136.04 2,235.06 2,205.13 26.30 29.95 28.13 2,259.01 2,266.89 70.90 84.40 77.65 2,553.38 2,478.22
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End of Presentation
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