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Congestion Management Settlement Credits December, 2002

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

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Operating Profit

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5 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 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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6 OP = Revenue - Cost Quantity (MW) MCP = 20 Price ($/MWh) MQSI=60 100 15 10 5 25 30 806040200 OP+OP+OP+

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7 Skill Check

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8 Generator A offer: 0-20 MW $15 21-30 MW $25 31 - 40 MW $100 Dispatched to 30 MW 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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10 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 OP (MQSI) - OP (DQSI) Where MQSI = Market Quantity Scheduled for Injection DQSI = Dispatch Quantity Scheduled for Injection

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11 Market Schedule Requirement is 190 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 2 Region 1 notransmission line limit Generator 3 100 MW $25 Load 190 MW Generator 1 100 MW $15 Generator 2 100 MW $20

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12 Transmission Congestion Requirement is 190 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 1 100 MW $15 Generator 2 100 MW $20 Generator 3 100 MW $25 Load 190 MW Region 2 Region 1 150 MW transmission line limit

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13 CMSC For Generator 2 in this case: MQSI = 90Offer = $20 DQSI = 50MCP = $20 For Generator 2 in this case: MQSI = 90Offer = $20 DQSI = 50MCP = $20 CMSC = OP(MQSI) - OP(DQSI) = (MCP-Offer) x MQSI - (MCP-Offer) x DQSI = (20-20) x90 - (20-20) x 50 = 0 - 0 = $0 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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14 CMSC For Generator 3 in this case: MQSI = 0Offer = $25 DQSI = 40MCP = $20 For Generator 3 in this case: MQSI = 0Offer = $25 DQSI = 40MCP = $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 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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15 Gen 1- Constrained Off Requirement is 190 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 3 100 MW $25 Load 190 MW Region 2 Region 1 150 MW transmission line limit 95 MW limit Generator 1 100 MW $15 Generator 2 100 MW $20

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16 Constrained Off Payment Generator 1 Market Schedule: 100 MW Dispatch : 95 MW Offer: $15 /MWh MCP: $20 /MWh Generator 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 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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17 Gen 2 - Constrained Off Requirement is 190 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 3 100 MW $25 Load 190 MW Region 2 Region 1 150 MW transmission line limit 95 MW 100 MW Generator 1 100 MW $15 Generator 2 100 MW $20

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18 Constrained Off Payment Generator 2 Market Schedule: 90 MW Dispatch : 55 MW Offer: $20 /MWh MCP: $20 /MWh Generator 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 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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19 Constrained On Payment Generator 3 Market Schedule: 0 Dispatch : 40 MW Offer: $25 MCP: $20 /MWh Generator 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 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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21 Gen 1- Constrained Off Requirement is 190 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 3 100 MW $25 Load 190 MW Region 2 Region 1 150 MW transmission line limit 95 MW limit Generator 1 100 MW $15 Generator 2 100 MW $20 Actually produces 50 MW

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22 Constraint Payments MQSI = 0 MW, DQSI=40 MW, AQEI =50MW MCP = $20Offer = $25 MQSI = 0 MW, DQSI=40 MW, AQEI =50MW MCP = $20Offer = $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 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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23 CMSC for a Dispatchable Load Load may be dispatched off or on Any time constrained and unconstrained are different, possibility exists for CMSC Load may be dispatched off or on Any time constrained and unconstrained are different, possibility exists for CMSC

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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 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

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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 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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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 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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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 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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