1. IMO Market Evolution Program Drew Phillips Market Evolution Program
Nodal Pricing Basics
Drew Phillips
Market Evolution Program 1

2. IMO Market Evolution Program
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. IMO Market Evolution Program
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Each node represents the physical location on the transmission system where energy is injected by generators or withdrawn by loads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?
IMO Market Evolution Program
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
IMO Market Evolution Program
Impedance, Power Flows, Losses and Limits 5

6. Impedance and its effect on power flows
IMO Market Evolution Program
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
IMO Market Evolution Program
Relative Impedance and Power Flow
Gen
Load
Transformer
115 kV
230 kV
Energy will flow preferentially on the 230 kV path:
Higher voltage
More lines in parallel
Fewer transformers 7

8. IMO Market Evolution Program
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. IMO Market Evolution Program
Power Flows
N Load
75 %
25 % N
W Gen W E
E Gen S
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?
IMO Market Evolution Program
What if E Gen supplies N Load?
N Load N
25 %
75 % W 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. IMO Market Evolution Program
Superposition
N Load
W Gen N W S E
E Gen
100 MW
45 MW
15 MW
60 MW
5 MW
(15 – 10)
45 MW
55 MW
( )
( )
40 MW
10 MW
30 MW
60 MW
60 MW
40 MW
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
IMO Market Evolution Program
Loss Comparison for 100 km Lines
180 A
90 MW
89.9 MW
390 A
90 MW
88.5 MW
115 kV
230 kV
500 kV
780 A
90 MW
79.5 MW A
Current (Amps)
Losses are:
proportional to Current2 x Resistance (I2R)
lower on higher voltage lines because resistance is lower and current flow is lower for a given MW flow 12

13. IMO Market Evolution Program
Loss Comparison =
Losses are higher on a line that is heavily loaded for the same increase in current 13

14. IMO Market Evolution Program
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. IMO Market Evolution Program
Nodal Price Examples 15

16. How are nodal prices derived?
IMO Market Evolution Program
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
IMO
Market
Participants
Unconstrained
Calculation
ignores physical
limitations
Schedule
Uniform
Price
Constrained
considers physical
Dispatch
Bids/
Offers
CMSC
Dispatchable
resources
produce or
consume MWs $
Nodal
Prices
Currently calculated for information purposes only 17

18. Nodal Price Calculations
IMO Market Evolution Program
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
IMO Market Evolution Program
No Congestion or Losses 19

20. No Congestion or Losses: Dispatch
IMO Market Evolution Program
No Congestion or Losses: Dispatch
N Load
100 MW
Transmission Limit = 85 MW N
25 MW
75 MW
$30
Offer
$35
Offer
W Gen W E
E Gen
100 MW
Dispatch
0 MW S
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
IMO Market Evolution Program
No Congestion or Losses: Node N Price
N Load
100 MW
+ 1 MW
Transmission Limit = 85 MW N
25.25 MW
75.75 MW
( )
( )
$30
$30
Offer
$35
Offer
W Gen W E
E Gen
0 MW
Dispatch
100 MW
+1 MW S
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
IMO Market Evolution Program
No Congestion or Losses: Node W Price
N Load
100 MW
Transmission Limit = 85 MW N
25 MW
75 MW
$30
Offer
+ 1 MW
$35
Offer
W Gen W
$30 E
E Gen
100 MW
Dispatch
+1 MW
0 MW S
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
IMO Market Evolution Program
No Congestion or Losses: Node E Price
N Load
100 MW
Transmission Limit = 85 MW N
25.5 MW
75.5 MW
24.5 MW
( )
( )
( )
$30
Offer
+ 1 MW
$35
Offer
W Gen W
$30 E
E Gen
100 MW
Dispatch
+1 MW
0 MW S
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
IMO Market Evolution Program
No Congestion or Losses: Node S Price
N Load
100 MW
Transmission Limit = 85 MW N
24.75 MW
75.25 MW
25.75 MW
( )
( )
( )
$30
Offer
$35
Offer
W Gen W E
E Gen
100 MW
Dispatch
+1 MW
0 MW
$30 S
+ 1 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. IMO Market Evolution Program
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. IMO Market Evolution Program
Congestion, No Losses 26

27. Congestion (No Losses): Dispatch
IMO Market Evolution Program
Congestion (No Losses): Dispatch
N Load
100 MW
Transmission Limit = 75.2 MW N
25 MW
75 MW
$30
Offer
$35
Offer
W Gen W E
E Gen
100 MW
Dispatch
0 MW S
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
IMO Market Evolution Program
Congestion (No Losses): Node N Price
N Load
100 MW
+ 1 MW
Transmission Limit = 75.2 MW N
24.7 MW
75.2 MW
25.8 MW
$35.50
$30
Offer
$35
Offer
W Gen W E
E Gen
0 MW
Dispatch
+1.1 MW
100 MW
-.1 MW S
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 $35 – 0.1 X $30) 28

29. Congestion (No Losses): Node E Price
IMO Market Evolution Program
Congestion (No Losses): Node E Price
N Load
100 MW
Transmission Limit = 75.2 MW N
25.2 MW
75.2 MW
24.8 MW
$30
Offer
+ 1 MW
$35
Offer
W Gen W
$33 E
E Gen
100 MW
Dispatch
+.4 MW
0 MW
+.6 MW S
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 (75% 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
IMO Market Evolution Program
Congestion (No Losses): Node S Price
N Load
100 MW
Transmission Limit = 75.2 MW N
24.6 MW
75.2 MW
24.8 MW
25.6 MW
$30
Offer
$35
Offer
W Gen W E
E Gen
0 MW
Dispatch
+.2 MW
100 MW
+.8 MW
$31 S
+ 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 (75% 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 = $31 (0.2 X $ X $30) 30

31. Congestion (No Losses): Node W Price
IMO Market Evolution Program
Congestion (No Losses): Node W Price
N Load
100 MW
Transmission Limit = 75.2 MW N
25 MW
75 MW
$30
Offer
+ 1 MW
$35
Offer
W Gen W
$30 E
E Gen
100 MW
Dispatch
+1 MW
0 MW S
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
IMO Market Evolution Program
Congestion (No Losses): Summary
N Load
100 MW
Transmission Limit = 75.2 MW N
25 MW
75 MW
$35.50
$30
Offer
$35
Offer
W Gen W
$30
$33 E
E Gen
100 MW
Dispatch
0 MW
$31 S
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. IMO Market Evolution Program
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 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 = $3000 33

34. IMO Market Evolution Program
Exercise One
N Load
100 MW N
75 MW
25 MW
$30
Offer
$35
Offer
W Gen W E
E Gen
100 MW
Dispatch
0 MW
25 MW
25 MW S
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
IMO Market Evolution Program
Exercise Answer: Node N Price
N Load
100 MW
+ 1 MW N
25 MW
75.5 MW
25.5 MW
( – .125)
( )
( )
$32.50
$30
Offer
$35
Offer
W Gen W E
E Gen
100 MW
Dispatch
+.5 MW
0 MW S
Transmission Limit = 25 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
IMO Market Evolution Program
Exercise Answer: Node S Price
N Load
100 MW N
24.75 MW
75.25 MW
25.75 MW
( )
( )
( )
$30
Offer
$35
Offer
W Gen W E
E Gen
0 MW
Dispatch
100 MW
+1 MW
$30 S
+ 1 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. IMO Market Evolution Program
Losses, No Congestion 37

38. Losses (No Congestion): Dispatch
IMO Market Evolution Program
Losses (No Congestion): Dispatch
N Load
100 MW N
75 MW
25 MW
$30
Offer
78 MW
$35
Offer
W Gen W E
E Gen
26 MW
104 MW
Dispatch
0 MW S
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
IMO Market Evolution Program
Losses (No Congestion): Node N Price
N Load
101 MW N
75.75 MW
25.25 MW
$31.20
$30
Offer
78.9 MW
$35
Offer
W Gen W E
E Gen
26.3 MW
104 MW
Dispatch
+1.04 MW
0 MW
Dispatch S
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 39

40. IMO Market Evolution Program
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 Dispatch Scheduling Algorithm (DSO) Calculates Nodal Prices
IMO Market Evolution Program
How the Dispatch Scheduling Algorithm (DSO) Calculates Nodal Prices 41

42. Dispatch Scheduling Optimizer (DSO)
IMO Market Evolution Program
Dispatch 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
IMO Market Evolution Program
Calculate Nodal Prices
Nodal Price λn
Cost of losses incurred for the next MW of load at the node
(DFn - 1)* λs λs
System Marginal Cost at Reference Node
Cost of transmission limits incurred for the next MW of load at the node
Σ αnk*μk
Marginal Cost of Generation
Marginal Cost of Losses
Marginal Cost of Transmission Congestion
LMP = + + 43

44. IMO Market Evolution Program
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 (losses)
represent losses between nodes and the reference bus
IMO uses fixed losses for each node based on historical power flows 44

45. IMO Market Evolution Program
Penalty Factors
Load Z
Non-dispatchable
PF = 1.3
= 23% losses
PF = .97
= - 3.1% losses
Gen D
Richview
Gen A
Gen C
Gen B
PF = .9
= % losses
PF = .95
= - 5.3% losses
PF = 1.01
= 1% 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
IMO Market Evolution Program
Nodal Price Calculation in DSO
Bids and Offers
Forecast Load
System Limits
Penalty Factors
Transmission Model
Load Profile
Congestion Impact
Richview Nodal Price
Dispatch Instructions
Richview Nodal Price
Congestion Impact
Penalty Factors
DSO Calculation 1
DSO Calculation 2
All Other Nodal Prices 46

47. Reference Bus Merit Order
IMO Market Evolution Program
Reference Bus Merit Order
Delivery Point
Offer/Bid Stack
Gen C 100 $60
Gen B 100 $70
Gen A 100 $75
Gen D 100 $50
Penalty
Factors
Gen C 100 $57
Gen B 100 $70.7
Gen A 100 $67.5
Gen D 100 $65
Richview Equivalent Offer/Bid Stack
.95
1.01
.90
1.3
Subsequent calculation addresses quantity differences due to the effect of losses 47

48. IMO Market Evolution Program
Effective Price
Delivery Point
Offer/Bid Stack
Penalty
Factors
Richview Equivalent Offer/Bid Stack
Gen D 100 $50
1.3
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
IMO Market Evolution Program
Determine Unconstrained Economic Solution
Richview Equivalent Offer/Bid Stack
Current system demand +/- forecast change in next interval
Gen B 100 $70.7
Gen A 100 $67.5
Gen D 100 $65
Forecast
Demand
Gen C 100 $57 49

50. Introduce Physical Network
IMO Market Evolution Program
Introduce Physical Network
Load Z 4% 3% 2%
Gen D
Gen C
Gen A
Gen B 5% 4% 1% 3%
Richview 6% 2% 5% 4%
10%
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
IMO Market Evolution Program
System Marginal Cost: No Congestion
Gen C 100 $57
Gen B 100 $70.7
Gen A 100 $67.5
Gen D 100 $65
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 (λs) = $65 51

52. Nodal Prices: No Congestion
IMO Market Evolution Program
Nodal Prices: No Congestion
Offer Price
Penalty Factor
Losses Cost
Congestion Cost
Nodal Price
Gen A
$75
0.90
$7.22
$72.22
Gen B
$70
1.01
-$0.64
$64.36
Gen C
$60
0.95
$3.42
$68.42
Gen D
$50
1.30
-$15.00
$50.00
Load Z
N/A
0.97
$2.01
$67.01
Richview = λs
$65.00 52

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

54. IMO Market Evolution Program
Congestion
Binding Transmission Limit
Load Z
Line 1
Gen D
Richview
Gen A
Gen C
Gen B
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
IMO Market Evolution Program
System Marginal Cost: Congestion
Gen B 100 $70.7
Gen A 100 $67.5
Forecast
Demand
Gen D 90 $65
Gen C 100 $57
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 (λs) = $67.5
There is a cost associated with the Line 1 transmission limit 55

56. Line 1 Transmission Limit Cost
IMO Market Evolution Program
Line 1 Transmission Limit Cost
Binding Transmission Limit
Load Z
Line 1
Gen D
Richview
Gen A
Gen C
Gen B
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
IMO Market Evolution Program
Line 1 Transmission Limit Cost
Load Z
23% losses
+1 MW
Gen D
Richview
- 11.2% losses
+.77 MW
Gen A
Gen C
Gen B
-.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 MW
Net cost is $50 x 1 MW - $75 x MW = -$1.92 57

58. Nodal Prices: Congestion
IMO Market Evolution Program
Nodal Prices: Congestion
Offer Price
Penalty Factor
Losses Cost
-1.92
Congestion Cost
$71.05
$66.83
$75.00
$50.00
Nodal 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
Load Z
N/A
0.97
$2.09
$69.59
Richview = λs
$67.50 58

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

60. Nodal Price Comparison
IMO Market Evolution Program
Nodal Price Comparison
Nodal Price
(No Congestion)
Nodal Price
(Congestion)
Gen A
$72.22
$71.05
$66.83
$75.00
$50.00
Gen B
$64.36
Gen C
$68.42
Gen D
$50.00
Load Z
$67.01
$69.59
Richview = λs
$65.00
$67.50 60

61. Getting Nodal Price Information
IMO Market Evolution Program
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
RICHVIEW-230.G_SLACKA DSO-RD;
Operating Reserve
10S/10NS/30
Hour
Interval
Node
Energy 61