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Congestion Management Settlement Credits

Congestion Management Settlement Credits. December, 2002. 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)

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Congestion Management Settlement Credits

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  1. Congestion Management Settlement Credits December, 2002

  2. 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

  3. Congestion Occurs when physical capability of the transmission system cannot meet market requirements

  4. Operating Profit

  5. 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

  6. OP+ OP+ OP+ OP = Revenue - Cost Price ($/MWh) 30 25 MCP = 20 15 10 5 0 20 40 60 80 100 MQSI=60 Quantity (MW)

  7. Skill Check

  8. 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 Skill Check If MCP is $30, what is the OP for A and B?

  9. Congestion Management Settlement Credits

  10. OP (MQSI) - OP (DQSI) Where MQSI = Market Quantity Scheduled for Injection DQSI = Dispatch Quantity Scheduled for Injection 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

  11. Generator 1 100 MW $15 Load 190 MW Generator 2 100 MW $20 Generator 3 100 MW $25 Market Schedule no transmission line limit • Requirement is • 190 MW • Gen 1: 100 MW • Gen 2: 90 MW • MCP $20 • GEN 3: does not run Region 1 Region 2

  12. Transmission Congestion Generator 1 100 MW $15 Load 190 MW Generator 2 100 MW $20 Generator 3 100 MW $25 150 MW transmission line limit • Requirement is • 190 MW • Gen 1: 100 MW • Gen 2: 50 MW • Gen 3: 40 MW • MCP $20 Region 1 Region 2

  13. CMSC = OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = (20-20) x90 - (20-20) x 50 = 0 - 0 = $0 CMSC For Generator 2 in this case: MQSI = 90 Offer = $20 DQSI = 50 MCP = $20

  14. CMSC = OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = (20-25) x 0 - (20-25) x 40 = 0 - (-$200) = $200 CMSC For Generator 3 in this case: MQSI = 0 Offer = $25 DQSI = 40 MCP = $20

  15. Gen 1- Constrained Off Generator 1 100 MW $15 Load 190 MW 95 MW limit Generator 2 100 MW $20 Generator 3 100 MW $25 150 MW transmission line limit • Requirement is • 190 MW • Gen 1: 95 MW • Gen 2: 55 MW • Gen 3: 40 MW • MCP $20 Region 1 Region 2

  16. CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = (20-15) x 100 - (20-15) x 95 = $25 Constrained Off Payment Generator 1 • Market Schedule: 100 MW • Dispatch : 95 MW • Offer: $15 /MWh • MCP: $20 /MWh

  17. Gen 2 - Constrained Off Generator 1 100 MW $15 Load 190 MW 95MW Generator 2 100 MW $20 Generator 3 100 MW $25 150 MW transmission line limit 100MW • Requirement is • 190 MW • Gen 1: 95 MW • Gen 2: 55 MW • Gen 3: 40 MW • MCP $20 Region 1 Region 2

  18. CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI =(20-20) x 90 - (20-20) x 55 = $0 Constrained Off Payment Generator 2 • Market Schedule: 90 MW • Dispatch : 55 MW • Offer: $20 /MWh • MCP: $20 /MWh

  19. CMSC= OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = ($20-$25) x 0 - ($20-$25) x 40 MW = $200 Constrained On Payment Generator 3 • Market Schedule: 0 • Dispatch : 40 MW • Offer: $25 • MCP: $20 /MWh

  20. Constraint Payments When Actual Quantity Different than Dispatch Quantity

  21. Actually produces 50 MW Gen 1- Constrained Off Generator 1 100 MW $15 Load 190 MW 95 MW limit Generator 2 100 MW $20 Generator 3 100 MW $25 150 MW transmission line limit • Requirement is • 190 MW • Gen 1: 95 MW • Gen 2: 55 MW • Gen 3: 40 MW • MCP $20 Region 1 Region 2

  22. 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 Constraint Payments MQSI = 0 MW, DQSI=40 MW, AQEI =50MW MCP = $20 Offer = $25

  23. CMSC for a Dispatchable Load • Load may be dispatched off or on • Any time constrained and unconstrained are different, possibility exists for CMSC

  24. CMSC for a Dispatchable Load E.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

  25. 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

  26. 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

  27. 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

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