Download - Congestion Management Settlement Credits
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Congestion Management Settlement Credits
December, 2002
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Market Design Principles
• The price of energy at each time and place should reflect the marginal cost of producing or not consuming one more unit of energy (at that time and place)
• Dispatchable market participants should be compensated for the effects of constraints
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Congestion
Occurs when physical capability of the transmission system cannot meet market
requirements
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Operating Profit
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Operating Profit
• Operating Profit is the difference between operating cost and revenue
• Market Rules written assuming participants bid and offer based on marginal benefit/cost
• Marginal Cost - Cost of producing next MW• Marginal Benefit - Benefit of consuming next
MW
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OP = Revenue - Cost
Quantity (MW)Quantity (MW)
MCP = 20MCP = 20
Price ($/MWh)Price ($/MWh)
MQSI=60MQSI=60100100
1515
1010
55
2525
3030
808060604040202000
OP+OP+OP+OP+
OP+OP+
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Skill Check
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Skill Check• Generator A offer:
• 0-20 MW $15• 21-30 MW $25• 31 - 40 MW $100
Dispatched to 30 MW
• Load B bid:• 0-10 MW $1,000• 11-20 MW $500• 21-30 MW $20
Dispatched to 20 MW
If MCP is $30, what is the OP for A and B?
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Congestion Management Settlement Credits
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Congestion Management Settlement Credit
• CMSC payments are based on the difference between the Operating Profit that would result from the Market Schedule and Operating Profit resulting from the Dispatch Instruction
OP (MQSI) - OP (DQSI)Where MQSI = Market Quantity Scheduled for Injection
DQSI = Dispatch Quantity Scheduled for Injection
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Market Schedule
Requirement is Requirement is 190 MW190 MW• Gen 1: 100 MWGen 1: 100 MW• Gen 2: 90 MWGen 2: 90 MW• MCP $20MCP $20• GEN 3: does not runGEN 3: does not run
Region 2Region 2Region 1Region 1
nonotransmissiontransmission
line limitline limit
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Generator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
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Transmission Congestion
Requirement is Requirement is 190 MW190 MW• Gen 1: 100 MWGen 1: 100 MW• Gen 2: 50 MWGen 2: 50 MW• Gen 3: 40 MWGen 3: 40 MW• MCP $20MCP $20
Generator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Region 2Region 2Region 1Region 1
150 MW150 MWtransmissiontransmission
line limitline limit
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CMSCFor Generator 2 in this case:MQSI = 90 Offer = $20DQSI = 50 MCP = $20
CMSC = OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI
= (20-20) x90 - (20-20) x 50= 0 - 0= $0
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CMSCFor Generator 3 in this case:MQSI = 0 Offer = $25DQSI = 40 MCP = $20
CMSC = OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI
= (20-25) x 0 - (20-25) x 40= 0 - (-$200)= $200
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Gen 1- Constrained Off
Requirement is Requirement is 190 MW190 MW• Gen 1: 95 MWGen 1: 95 MW• Gen 2: 55 MWGen 2: 55 MW• Gen 3: 40 MWGen 3: 40 MW• MCP $20MCP $20
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Region 2Region 2Region 1Region 1
150 MW150 MWtransmissiontransmission
line limitline limit
95 MW limit95 MW limitGenerator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
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Constrained Off PaymentGenerator 1
• Market Schedule: 100 MW• Dispatch : 95 MW• Offer: $15 /MWh• MCP: $20 /MWh
CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = (20-15) x 100 - (20-15) x 95 = $25
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Gen 2 - Constrained Off
Requirement is Requirement is 190 MW190 MW• Gen 1: 95 MWGen 1: 95 MW• Gen 2: 55 MWGen 2: 55 MW• Gen 3: 40 MWGen 3: 40 MW• MCP $20MCP $20
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Region 2Region 2Region 1Region 1
150 MW150 MWtransmissiontransmission
line limitline limit
9595MWMW
100100MWMW
Generator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
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Constrained Off PaymentGenerator 2
• Market Schedule: 90 MW• Dispatch : 55 MW• Offer: $20 /MWh• MCP: $20 /MWh
CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI
= (20-20) x 90 - (20-20) x 55 = $0
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Constrained On PaymentGenerator 3
• Market Schedule: 0• Dispatch : 40 MW• Offer: $25• MCP: $20 /MWh
CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI
= ($20-$25) x 0 - ($20-$25) x 40 MW = $200
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Constraint Payments
When Actual Quantity Different than Dispatch Quantity
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Gen 1- Constrained Off
Requirement is Requirement is 190 MW190 MW• Gen 1: 95 MWGen 1: 95 MW• Gen 2: 55 MWGen 2: 55 MW• Gen 3: 40 MWGen 3: 40 MW• MCP $20MCP $20
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Region 2Region 2Region 1Region 1
150 MW150 MWtransmissiontransmission
line limitline limit
95 MW limit95 MW limitGenerator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
Actually produces 50 MW
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Constraint Payments
MQSI = 0 MW, DQSI=40 MW, AQEI =50MWMCP = $20 Offer = $25
CMSC = OP (MQSI) - MAX [OP (DQSI), OP (AQEI)]= (20-25) x 0 - MAX [(20-25) x 40, (20-25) x 50]= $0 - MAX [$-200, $-250]= $-(-200)= $200
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CMSC for a Dispatchable Load
• Load may be dispatched off or on• Any time constrained and unconstrained are
different, possibility exists for CMSC
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CMSC for a Dispatchable LoadE.G.• Load A bids for 100 MW at $2,000• Market Clearing Price = $100• Load A is dispatched to only 75 MW• At a bid price of $2,000 Load A will be scheduled by the unconstrained algorithm for all 100
MW
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CMSC for a Dispatchable Load• Bid = $2,000 MCP = $100• MQSI = 100 MW, DQSI = 75 MW• CMSC = OP(MQSI) - OP(DQSI)
= ($2,000 - $100) x 100 - ($2,000 - $100) x 75)
= $1900 x 100 - $1900 x 75 = $47,500
• The lost Operating Profit is $47,500
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Negative CMSC
• CMSC payments bring the participant back to the market schedule operating profit
• Generally CMSC payments will be a top-up to restore operating profit
• Sometimes the schedule would lead to lower profit than dispatch instructions
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CMSC
• CMSC payments bring the participant back to the market schedule operating profit
• While CMSC can be negative, it is more often a payment to participants
• The cost of CMSC is recovered from loads based on their activity in the market