Nodal Pricing Basics. Drew Phillips Market Evolution Program

Transcription

1 Nodal Pricing Basics Drew Phillips Market Evolution Program 1

2 Agenda What is Nodal Pricing? Impedance, Power Flows Losses and Limits Nodal Price Examples No Losses or Congestion Congestion Only Impact of Transmission Rights Losses Only How DSO Calculates Nodal Prices 2

3 What is Nodal Pricing? Nodal Pricing = Locational Marginal Pricing (LMP) = Locational Based Marginal Pricing (LBMP) Nodal Pricing is a method of determining prices in which market clearing prices are calculated for a number of locations on the transmission grid called nodes Each node represents the physical location on the transmission system where energy is injected by generators or withdrawn by loads Price at each node represents the locational value of energy, which includes the cost of the energy and the cost of delivering it, i.e., losses and congestion IMO publishes nodal prices for information purposes; they are referred to as shadow prices 3

4 What causes locational differences? Losses Due to the physical characteristics of the transmission system, energy is lost as it is transmitted from generators to loads Additional generation must be dispatched to provide energy in excess of that consumed by load Transmission congestion Prevents lower cost generation from meeting the load; higher cost generation must be dispatched in its place In both cases, the associated costs are allocated to each node in a manner that recognizes their individual contribution to/impact on these extra costs 4

5 Impedance, Power Flows, Losses and Limits 5

6 Impedance and its effect on power flows Impedance Is a characteristic of all transmission system elements Signifies opposition to power flow A higher impedance path indicates more opposition to power flow and greater losses Impedance between two points on the grid is related to: Line length Number of parallel paths Voltage level Number of series elements such as transformers Impedance will be lower where there are: Shorter transmission lines More parallel paths Higher voltage Fewer series transformers 6

7 Relative Impedance and Power Flow Gen Load Transformer 230 kv 115 kv Energy will flow preferentially on the 230 kv path: Higher voltage More lines in parallel Fewer transformers 7

8 Power Flows Power will take all available paths to get from supply point to consumption point Power flow distribution on a transmission system is a function of: Location and magnitude of generation Location and magnitude of load Relative impedance of the various paths between generation and load The following examples ignore the effect of losses 8

9 Power Flows N Load 75 % N W Gen W E E Gen S 25 % All lines have equal impedance Path W-S-E-N has three times the impedance of path W-N Flow divides inversely to impedance If W Gen supplies N Load, flow W-S-E-N is one third flow W-N If N Load is 100 MW, 75 MW flows on path W-N, 25 MW flows on path W-S-E-N 9

10 What if E Gen supplies N Load? N Load N 75 % W 25 % E E Gen S Path E-S-W-N has three times the impedance of path W-N Flow divides inversely to impedance If E Gen supplies N Load, flow E-S-W-N is one third flow E-N If N Load is 100 MW, 75 MW flows on path E-N, 25 MW flows on path E-S-W-N 10

11 Superposition N Load 100 MW N ( ) MW 45 MW ( ) 30 MW 60 MW W Gen W 10 MW E E Gen 40 MW (15 10) 5 MW 5 MW 15 MW (15 10) S What if W Gen supplies 60 MW and E Gen supplies 40 MW to N Load? Both W Gen and E Gen s output will flow in proportion to the impedance of the paths to N Load Resulting line flows represent the net impact of their flow distribution 11

12 Loss Comparison for 100 km Lines 90 MW 180 A 89.9 MW 500 kv 90 MW 390 A 88.5 MW A 230 kv 90 MW 780 A 115 kv 79.5 MW Current (Amps) Losses are: proportional to Current 2 x Resistance (I 2 R) lower on higher voltage lines because resistance is lower and current flow is lower for a given MW flow 12

13 Loss Comparison Losses (M W) Current (I) Losses are higher on a line that is heavily loaded for the same increase in current = 13

14 Security Limits Security limits are the reliability envelope in which the market operates Power will take all available paths to get from supply point to consumption point Transmission lines do not control or limit the amount of power they convey Power flows are managed by dispatching the system (normally via dispatch instructions and interchange scheduling) Must respect current conditions and recognized contingencies 14

15 Nodal Price Examples 15

16 How are nodal prices derived? Marginal cost is the cost of the next MW; the marginal generator is the generator that would be dispatched to serve the next MW This is the basis of our current unconstrained market clearing price A nodal price is the cost of serving the next MW of load at a given location (node) Nodal prices are formulated using a security constrained dispatch and the costs of supply are based upon participant offers and bids Nodal prices consist of three components: Nodal Price Marginal Cost of Generation Marginal Cost of Losses = + + Marginal Cost of Transmission Congestion 16

17 Current Pricing Scheme $ Uniform Price Market Participants Bids/ s IMO Bids/ s Unconstrained Calculation ignores physical limitations Constrained Calculation considers physical limitations Market Schedule Schedule CMSC able resources produce or consume MWs Nodal Prices Currently calculated for information purposes only 17

18 Nodal Price Calculations No Congestion or Losses With Congestion With Losses Process: Determine least cost dispatch to serve load Determine resulting power flows to ensure security limits are respected Calculate prices by determining the dispatch for one additional MW at each node (while still respecting all limits) 18

19 No Congestion or Losses 19

20 No Congestion or Losses: Transmission Limit = 85 MW N Load N 100 MW 75 MW 25 MW $30 W Gen W E E Gen $ MW 25 MW S 25 MW 0 MW Least cost solution would have W Gen supply all 100 MW to N Load, based on W Gen s offer price Resultant flow is within limits Nodal price is the cost of serving the next MW What are the prices at each node? 20

21 No Congestion or Losses: Node N Price $30 Transmission Limit = 85 MW N Load 100 MW + 1 MW N ( ) MW $ MW ( ) W Gen 100 MW +1 MW W MW MW ( ) S ( ) E E Gen $35 0 MW Price at Node N is the cost of supplying next 1 MW to N Least cost solution would have W Gen supply the next MW to N, based on W Gen s offer price Resultant flow would be within limits (net of existing flow and increment to serve additional 1 MW at Node N) W Gen is the marginal generator and Node N price = $30 21

22 No Congestion or Losses: Node W Price Transmission Limit = 85 MW N Load N 100 MW 75 MW 25 MW $ MW W Gen W $30 E E Gen $ MW +1 MW 25 MW S 25 MW 0 MW Price at Node W is the cost of supplying next 1 MW at W Least cost solution would have W Gen supply the next MW to W, based on W Gen s offer price Resultant flow would be within limits (net flow change is zero) W Gen is the marginal generator and Node W price = $30 22

23 No Congestion or Losses: Node E Price Transmission Limit = 85 MW N Load N 100 MW (75 +.5) 75.5 MW 24.5 MW (25 -.5) $30 W Gen W + 1 MW $30 E E Gen $ MW +1 MW 25.5 MW 25.5 MW (25 +.5) S (25 +.5) 0 MW Price at Node E is the cost of supplying next 1 MW to E Least cost solution would have W Gen supply the next MW to N, based on W Gen s offer price Resultant flow would be within limits (net of existing flow and increment to serve additional 1 MW at Node E) W Gen is the marginal generator and Node E price = $30 23

24 No Congestion or Losses: Node S Price Transmission Limit = 85 MW N Load N 100 MW ( ) MW MW ( ) $30 W Gen W E E Gen $ MW +1 MW MW $ MW ( ) S ( ) + 1 MW 0 MW Price at Node S is the cost of supplying next 1 MW at S Least cost solution would have W Gen supply the next MW to S, based on W Gen s offer price Resultant flow would be within limits (net of existing flow and increment to serve additional 1 MW at Node S) W Gen is the marginal generator and Node S price = $30 24

25 Summary The previous examples demonstrate the method used to derive nodal prices As we would expect, the nodal prices at all nodes on a transmission system will be the same in the absence of losses and congestion Unfortunately, no such transmission system exists The following examples will apply the same method to illustrate the calculation under conditions of congestion and then losses Examples: are not representative of how the IMO-controlled grid is dispatched and therefore the impact on nodal prices is entirely fictitious; these scenarios were designed to illustrate a concept while keeping the calculation as simple as possible are for illustrative purposes only and do not imply a settlement basis for a nodal pricing methodology for Ontario 25

26 Congestion, No Losses 26

27 Congestion (No Losses): Transmission Limit = 75.2 MW N Load N 100 MW 75 MW 25 MW $30 W Gen W E E Gen $ MW 25 MW S 25 MW 0 MW Assume the transmission limit is reduced; dispatch can be solved as in the no congestion case, but what is the effect on nodal prices? 27

28 Congestion (No Losses): Node N Price Transmission Limit = 75.2 MW N Load 100 MW + 1 MW N 75.2 MW $ MW $30 W Gen W E 100 MW 24.7 MW 24.7 MW -.1 MW S E Gen $35 0 MW +1.1 MW An increase in output of 1 MW by either W Gen or E Gen alone will increase the W-N line flow over the limit; we must redispatch the system using both generators If we reduce W Gen output by 0.1 MW (75% of the reduction will appear on W to N flow) and increase E Gen output by 1.1 MW (25% flows from N to W), net effect is on line W-N is a flow increase of.2 MW This is the lowest cost way to meet an additional 1 MW at N Node N price = $35.50 (1.1 X $ X $30) 28

29 Congestion (No Losses): Node E Price Transmission Limit = 75.2 MW N Load N 100 MW $30 W Gen 100 MW +.4 MW W 75.2 MW 24.8 MW 25.2 MW S $ MW + 1 MW E E Gen $35 0 MW +.6 MW An increase in output of 1 MW by either W Gen or E Gen alone will increase the W-N line flow over the limit; we must redispatch the system using both generators If we increase W Gen output by 0.4 MW (50% flows from W to N) and increase E Gen output by.6 MW (0% flows from N to W), net effect is on line W-N is a flow increase of.2 MW This is the lowest cost way to meet an additional 1 MW at E Node E price = $33 (0.6 X $ X $30) 29

30 Congestion (No Losses): Node S Price Transmission Limit = 75.2 MW N Load N 100 MW 75.2 MW 24.8 MW $30 W Gen W E E Gen $ MW +.9 MW 25.7 MW $30.50 S + 1 MW 24.7 MW 0 MW +.1 MW An increase in output of 1 MW by either W Gen or E Gen alone will increase the W-N line flow over the limit; we must redispatch the system using both generators If we increase W Gen output by 0.8 MW (25% flows from W to N) and increase E Gen output by.2 MW (25% flows from N to W), net effect is on line W-N is a flow increase of.2 MW This is the lowest cost way to meet an additional 1 MW at E Node S price = $30.50 (0.1 X $ X $30) 30

31 Congestion (No Losses): Node W Price Transmission Limit = 75.2 MW N Load N 100 MW 75 MW 25 MW $ MW W Gen W $30 E E Gen $ MW +1 MW 25 MW S 25 MW 0 MW Least cost solution would have W Gen supply the next MW to W, based on W Gen s offer price W Gen can meet the additional MW at Node W without affecting the transmission system (net flow change is zero) W Gen is the marginal generator and Node W price = $30 31

32 Congestion (No Losses): Summary Transmission Limit = 75.2 MW N Load 100 MW N 75 MW $ MW $30 W Gen W $30 $33 E E Gen $ MW 25 MW $30.50 S 25 MW 0 MW System is congested on line W-N Combination of W Gen and E Gen redispatch is necessary to meet incremental loads at Node N,E and S If W Gen and N Load are settled at their respective nodal prices, the difference will result in a settlement surplus Surplus due to the congestion component of different nodal prices is used to fund transmission rights 32

33 Transmission Rights Provide a hedge against congestion charges between two locations Transmission rights holders receive the difference in congestion charges between the two locations defined by the transmission right Using our example: Price at N - Price at W = Congestion Charge $ $30 = $5.50/MW If N load holds 100 MW of transmission rights, they will receive 100 x $5.50 = $550 N Load: Pays 100 x $35.50 = $3550 for energy Receives 100 x $5.50 = $550 for transmission rights Net = $3000 W Gen is paid 100 x $30 = $

34 Exercise One N Load N 100 MW 75 MW 25 MW $30 W Gen W E E Gen $ MW 25 MW S 25 MW 0 MW Transmission Limit = 25 MW Assume the transmission limit is on line S-E (for simplicity we ll allow flow to equal the limit, although in reality flow must be less than the limit) The load at N is being served by W Gen with flows on the transmission system as shown What are the nodal prices at N and S? 34

35 Exercise Answer: Node N Price ( ) N Load 100 MW + 1 MW N 75.5 MW $ MW ( ) $30 W Gen W E E Gen $ MW +.5 MW 25 MW 25 MW ( ) S ( ) Transmission Limit = 25 MW 0 MW +.5 MW W Gen cannot be used as sole supply as any increase in output will increase the S-E line flow; must redispatch the system Must increase W Gen output by 0.5 MW (25% flows from S to E) and increase E Gen output by 0.5 MW (25% flows from E to S) Resultant flow would be within limits Node N price = $32.50 (0.5 X $ X $30) 35

36 Exercise Answer: Node S Price ( ) N Load 100 MW N MW MW ( ) $30 W Gen W E E Gen $ MW +1 MW MW $ MW ( ) S ( ) + 1 MW 0 MW Transmission Limit = 25 MW W Gen can be used as sole supply; the increase in output to serve Node S will decrease the S-E line flow Increase W Gen output by 1.0 (75% flows from E to S) Resultant flow would be within limits Node S price = $30 36

37 Losses, No Congestion 37

38 Losses (No Congestion): 75 MW N Load N 100 MW 25 MW $30 W Gen W 78 MW 26 MW E E Gen $ MW S 0 MW Least cost solution would have W Gen supply all 100 MW to N Load due to its lower offer price, but due to losses must generate 104 MW Resultant flow is within limits Nodal price is the cost of serving the next MW What are the prices at Node N? 38

39 Losses (No Congestion): Node N Price MW N Load N $ MW MW + 1 MW $30 W Gen 104 MW MW 78.9 MW W 26.3 MW Price at node N is the cost of supplying next 1 MW W Gen must generate an additional 1.04 MW to N to deliver 1 MW at Node N Resultant flow would be within limits Node N price = $31.20 (1.04 X $30) Prices at Nodes E and S would be similarly calculated Price at Node W = $30 as an increment of load can be supplied from W Gen with no impact to transmission flows S E E Gen 0 MW $35 39

40 Summary When more than one generator is on the margin, prices may be: higher than any offer lower than any offer (and could even be negative) For additional examples see the Market Evolution Day Ahead Market web page and in particular: Even when there is no congestion on the transmission system directly connecting them, prices may be different between two nodes due to: losses and/or their differing impact on congested paths elsewhere in the system If a generator is partially dispatched: nodal price = offer price If a generator is fully dispatched: nodal price > than offer price If a generator is not dispatched: nodal price < than offer price 40

41 How the Scheduling Algorithm (DSO) Calculates Nodal Prices 41

42 Scheduling Optimizer (DSO) Two methods are available to calculate nodal prices: 1) calculate nodal prices at each node directly (as in previous examples) 2) calculate a reference node price then derive prices at all other nodes The DSO uses method 2 as it requires less computing power and is faster: It yields the same results as method 1 It does not matter which node is chosen as the reference bus 42

43 Calculate Nodal Prices Nodal Price Cost of losses incurred for the next MW of load at the node LMP Marginal Cost? of s Generation (DF n - 1)*? s Marginal Cost of Losses? n = + + Marginal Cost of Transmission S a nk* µ k Congestion System Marginal Cost at Reference Node Cost of transmission limits incurred for the next MW of load at the node 43

44 Inputs s 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 (losses) represent losses between nodes and the reference bus IMO uses fixed losses for each node based on historical power flows 44

45 Penalty Factors PF = 1.3 = 23% losses Gen D Load Z Non-dispatchable PF =.97 = - 3.1% losses Richview Gen C PF =.95 = - 5.3% losses Gen B PF = 1.01 = 1% losses Gen A PF =.9 = % losses Represent incremental impact on losses for generation or load at each node based on a representative power flow distribution on the grid If PF > 1: losses are incurred for each MW delivered to Richview If PF < 1: losses are reduced for each MW delivered to Richview 45

46 Nodal Price Calculation in DSO Penalty Factors Bids and s Forecast Load System Limits Transmission Model Load Profile Penalty Factors Richview Nodal Price Congestion Impact DSO Calculation 1 DSO Calculation 2 Richview Nodal Price Congestion Impact Instructions All Other Nodal Prices 46

47 Reference Bus Merit Order Delivery Point /Bid Stack Gen A 100 $75 Gen B 100 $70 Gen C 100 $60 Gen D 100 $50 Penalty Factors Richview Equivalent /Bid Stack Gen B 100 $70.7 Gen A 100 $67.5 Gen D 100 $65 Gen C 100 $57 Subsequent calculation addresses quantity differences due to the effect of losses 47

48 Effective Price Delivery Point /Bid Stack Penalty Factors Richview Equivalent /Bid Stack Gen D 100 $ Gen D 100 $65 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 48

49 Determine Unconstrained Economic Solution Richview Equivalent /Bid Stack Current system demand +/- forecast change in next interval Gen B 100 $70.7 Gen A 100 $67.5 Gen D 100 $65 Gen C 100 $57 Forecast Demand 49

50 Introduce Physical Network Load Z Gen D 4% 4% 3% 1% Richview 5% 3% 2% Gen C 4% 5% Gen B 6% 10% 2% Gen A 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 50

51 System Marginal Cost: No Congestion Gen B 100 $70.7 Gen A 100 $67.5 Gen D 100 $65 Gen C 100 $57 Forecast Demand 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 (? s ) = $65 51

52 Nodal Prices: No Congestion Price Penalty Factor Losses Cost Congestion Cost Nodal Price Gen A $ $ $72.22 Gen B $ $ $64.36 Gen C $ $ $68.42 Gen D $ $ $50.00 Load Z N/A 0.97 $ $67.01 Richview =? s $

53 Nodal Prices and : No Congestion $50.00 Gen D Partially dispatched $65.00 Richview $68.42 Gen C Fully dispatched Gen B $64.36 Gen A $72.22 prices: Gen A $75 Gen B $70 Gen C $60 Gen D $50 Which generators should be dispatched? 53

54 Congestion Binding Transmission Limit Load Z Gen D Line 1 Richview Gen C Gen B Gen A 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 54

55 System Marginal Cost: Congestion Gen B 100 $70.7 Gen A 100 $67.5 Gen D 90 $65 Gen C 100 $57 Forecast Demand 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 (? s ) = $67.5 There is a cost associated with the Line 1 transmission limit 55

56 Line 1 Transmission Limit Cost Binding Transmission Limit Load Z Gen D Line 1 Richview Gen C Gen B Gen A Determine transmission limit cost by relaxing constraint by 1 MW and measuring impact on total system costs Note: results are rounded on the following diagrams 56

57 Line 1 Transmission Limit Cost Load Z +1 MW 23% losses Gen D Gen C Gen B Richview +.77 MW % losses Gen A -.69 MW Increase Gen D by 1 MW results in MW at Richview due to losses To maintain the generation/load balance we must reduce Gen A by.6923 MW Net cost is $50 x 1 MW - $75 x.6923 MW = -$

58 Nodal Prices: Congestion Price Penalty Factor Losses Cost Congestion Cost Nodal Price Gen A $ $ $75.00 Gen B $ $ $66.83 Gen C $ $ $71.05 Gen D $ $ $50.00 Load Z N/A 0.97 $ $69.59 Richview =? s $

59 Nodal Prices and : Congestion Binding Transmission Limit $50.00 Gen D Partially dispatched Line 1 $67.50 Richview $71.05 Gen C Fully dispatched Gen B $66.83 Gen A $75.00 Partially dispatched prices: Gen A $75 Gen B $70 Gen C $60 Gen D $50 Which generators should be dispatched? 59

60 Nodal Price Comparison Gen A Gen B Gen C Gen D Nodal Price (No Congestion) $72.22 $64.36 $68.42 $50.00 Nodal Price (Congestion) $75.00 $66.83 $71.05 $50.00 Load Z $67.01 $69.59 Richview =? s $65.00 $

61 Getting Nodal Price Information Nodal prices available on IMO FTP site only (in.csv format) Go to Market Data page: 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_ csv 1 6 RICHVIEW-230.G_SLACKA DSO-RD; Hour Interval Node Energy Operating Reserve 10S/10NS/30 61