1. Market Evolution Program Day Ahead Market Project How the DSO Calculates Nodal Prices DAMWG October 20, 2003

2. 2 Review: What is LMP?  A Locational Marginal Price is the cost of serving the next MW of load at a given location (node)  LMPs are formulated using a security constrained dispatch and the marginal costs of supply are based upon participant offers and bids  LMP consists of three components: LMP Marginal Cost of Generation Marginal Cost of Losses Marginal Cost of Transmission Congestion = ++

3. 3 Dispatch Scheduling Optimizer  Uses linear programming to create security constrained dispatch and calculate nodal prices  Price determination: 1) Calculate system marginal cost at reference bus (Richview) 2) Calculate shadow prices for all binding transmission constraints, i.e., those that require out of merit dispatch to solve 3) Use 1 and 2 to calculate nodal prices

4. 4 Inputs  Offers and bids  Forecast demand for the next interval based upon a snapshot of current demand modified by the expected +/- in the next interval  Load profile based upon the current system snapshot  Physical model of the transmission system  Security limits  Penalty Factors represent losses between nodes and the reference bus IMO uses fixed losses for each node based on historical power flows

5. 5 Reference Bus Merit Order Delivery Point Offer/Bid Stack Gen C 100 MW @ $60 Gen B 100 MW @ $70 Gen A 100 MW @ $75 Gen D 100 MW @ $50.95 1.01.90 1.3 Penalty Factors Gen C 100 MW @ $57 Gen B 100 MW @ $70.7 Gen A 100 MW @ $67.5 Gen D 100 MW @ $65 Richview Equivalent Offer/Bid Stack Subsequent calculation addresses quantity differences due to the effect of losses

6. 6 Effective Price Delivery Point Offer/Bid Stack Gen D 100 MW @ $501.3 Penalty Factors Gen D 100 MW @ $65 Richview Equivalent Offer/Bid Stack If we generate 100 MW at Gen D, only 100/1.3 or 76.9 MW shows up at Richview due to losses 100 MW at Gen D costs 100 x $50 = $5,000, which only yields 76.9 MW at Richview, resulting in an effective price of $5000/76.9 MW = $65 /MW

7. 7 Determine Unconstrained Economic Solution Current system demand +/- forecast change in next interval Richview Equivalent Offer/Bid Stack Gen C 100 MW @ $57 Gen B 100 MW @ $70.7 Gen A 100 MW @ $67.5 Gen D 100 MW @ $65 Forecast Demand

8. 8 Introduce Physical Network  Allocate forecast demand to nodes based on load profile of current system  Run load flow to solve power balance using offers and bids at appropriate nodes, physical characteristics of transmission system and system limits  Determine System Marginal Cost at Richview 1% 2% 6% 5% 3% 10% 2% 4% 5% 2% 4% Richview Gen D Gen C Gen A Gen B

9. 9 System Marginal Cost: No Congestion  If power balance is solved without any need to redispatch to respect limits; there is no congestion and the system marginal cost will equal that determined in the purely economic merit order i.e., Gen D will set the system marginal cost  System Marginal Cost ( λ s ) = $65 Gen C 100 MW @ $57 Gen B 100 MW @ $70.7 Gen A 100 MW @ $67.5 Gen D 100 MW @ $65 Forecast Demand

10. 10 Marginal Cost of Generation λsλs System Marginal Cost at Reference Bus Marginal Cost of Losses Marginal Cost of Transmission Congestion Cost of transmission constraints incurred for the next MW of load at the node Σ α nk* μ k Calculate Nodal Prices LMP Nodal Price λ n = + + Cost of losses incurred for the next MW of load at the node (DF n - 1)* λ s

11. 11 Nodal Prices: No Congestion Richview = λ s Offer Price Gen C Gen B Gen A Gen D $60 $70 $75 $50 0.95 1.01 0.90 1.30 $3.42 -$0.64 $7.22 -$15.00 Penalty Factor Losses Cost 0 0 0 0 Congestion Cost $68.42 $64.36 $72.22 $50.00 Nodal Price $65.00

12. 12 $68.42 $50.00 Nodal Prices and Dispatch: No Congestion Offer prices:  Gen A $75  Gen B $70  Gen C $60  Gen D $50 Which generators should be dispatched? $65.00 Gen D Gen C Richview Gen A Gen B $64.36 $72.22   Fully dispatched Partially dispatched

13. 13 Congestion  If a transmission limit on the line from Gen D prevents its economic dispatch another more expensive resource must be dispatched to meet demand  This congestion will raise the system marginal cost and affect nodal prices throughout the system Gen D Gen C Richview Gen A Gen B Binding Transmission Limit Line 1

14. 14 System Marginal Cost: Congestion  Congestion on Line 1 from Gen D: redispatch from economic merit order to respect limit  System marginal cost is now set by Gen A  System Marginal Cost ( λ s ) = $67.5  There is a constraint shadow price associated with Line 1 Gen C 100 MW @ $57 Gen B 100 MW @ $70.7 Gen A 100 MW @ $67.5 Gen D 100 MW @ $65 Forecast Demand

15. 15 Line 1 Constraint Shadow Price  Determine shadow price by relaxing constraint by 1 MW and measuring impact on system costs  Increase Gen D by 1 MW results in +.77 MW at Richview due to losses  To maintain the generation/load balance we must reduce Gen A by.69 MW  Net impact is $50 x.77 MW - $75 x.69 MW = -$1.92 Binding Transmission Limit Gen D Gen C Richview Gen A Gen B Line 1

16. 16 Nodal Prices: Congestion Richview = λ s Offer Price Gen C Gen B Gen A Gen D $60 $70 $75 $50 0.95 1.01 0.90 1.30 $3.55 -$0.67 $7.50 -$15.58 Penalty Factor Losses Cost 0 0 0 -1.92 Congestion Cost $71.05 $66.83 $75.00 $50.00 Nodal Price $67.50

17. 17 $71.05 $50.00 Nodal Prices and Dispatch: Congestion Offer prices:  Gen A $75  Gen B $70  Gen C $60  Gen D $50 Which generators should be dispatched? $67.50 Gen D Gen C Richview Gen A Gen B $66.83 $75.00 Binding Transmission Limit Line 1    Partially dispatched Fully dispatched

18. 18 Nodal Price Comparison Richview = λ s Gen C Gen B Gen A Gen D $68.42 $64.36 $72.22 $50.00 $65.00 Nodal Price (No Congestion) $71.05 $66.83 $75.00 $50.00 $67.50 Nodal Price (Congestion)

19. 19 Getting Nodal Price Information  Nodal prices available on IMO FTP site only (in.csv format)  Go to Market Data page: http://www.theimo.com/imoweb/marketdata/marketData.asp  Scroll down to hyperlink: ftp://aftp.theimo.com/pub/reports/PUB/  Select DispConsShadowPrice folder  Choose report date and hour i.e., Sept 20 for Hour 1: PUB_DispConsShadowPrice_2003092001.csv 1 6 RICHVIEW-230.G_SLACKA 36.13 1.12 0.77 0.77 DSO-RD; Hour Interval Node Operating Reserve 10S/10NS/30 Energy