Nodal Pricing Basics - IESO

Nodal Pricing Basics
Drew Phillips
Market Evolution Program
1

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

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system where energy is injected by generators or withdrawn by loads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

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

Impedance, Power Flows, Losses and Limits
5

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

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

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

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

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

Superposition
N Load 100 MW
N
(45 + 10) 55 45 MW 45 MW (15 + 30)
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

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

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

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

Nodal Price Examples
15

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

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

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

No Congestion or Losses
19

No Congestion or Losses: Dispatch
Transmission Limit = 85 MW
N Load
N
100 MW
75 MW 25 MW
Offer
125 @ $30
W Gen
W
E
E Gen
Offer
125 @ $35
Dispatch
100 MW
25 MW
S
25 MW
Dispatch
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

Offer
No Congestion or Losses: Node N Price
125 @ $30
Transmission Limit = 85 MW
N Load 100 MW + 1 MW
N
(75 + .75) 75.75 MW
$30
25.25 MW (25 + .25)
W Gen
Dispatch
100 MW
+1 MW
W
25.25 MW
25.25 MW
(25 + .25)
S
(25 + .25)
E
Offer
E Gen 125 @ $35
Dispatch
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

No Congestion or Losses: Node W Price
Transmission Limit = 85 MW
N Load
N
100 MW
75 MW 25 MW
Offer
125 @ $30
+ 1 MW
W Gen W $30
E
E Gen
Offer
125 @ $35
Dispatch
Dispatch
100 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

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)
Offer
125 @ $30
W Gen
W
+ 1 MW
$30 E
E Gen
Offer
125 @ $35
Dispatch
100 MW
+1 MW
25.5 MW
25.5 MW
(25 + .5)
S
(25 + .5)
Dispatch
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

No Congestion or Losses: Node S Price
Transmission Limit = 85 MW
N Load
N
100 MW
(75 + .25)
75.25 MW 24.75 MW
(25 - .25)
Offer
125 @ $30
W Gen
W
E
E Gen
Offer
125 @ $35
Dispatch
100 MW
+1 MW
25.75 MW $30 24.75 MW
(25 + .75)
S
(25 - .25)
+ 1 MW
Dispatch
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

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

Congestion, No Losses
26

Congestion (No Losses): Dispatch
Transmission Limit = 75.2 MW
N Load
N
100 MW
75 MW 25 MW
Offer
125 @ $30
W Gen
W
E
E Gen
Offer
125 @ $35
Dispatch
100 MW
25 MW
S
25 MW
Dispatch
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

Congestion (No Losses): Node N Price
Transmission Limit = 75.2 MW
N Load 100 MW + 1 MW
N
75.2 MW
$35.50
25.8 MW
Offer
125 @ $30 W Gen W
E
Dispatch
100 MW 24.7 MW
24.7 MW
-.1 MW
S
E Gen 125 @ $35
Dispatch
0 MW
+1.1 MW
Offer
• 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

Congestion (No Losses): Node E Price
Transmission Limit = 75.2 MW
N Load
N
100 MW
Offer
125 @ $30
W Gen
Dispatch
100 MW
+.4 MW
W
75.2 MW 24.8 MW
25.2 MW
S
$33
25.2 MW
+ 1 MW
E
E Gen 125 @ $35
Dispatch
0 MW
+.6 MW
Offer
• 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 $35 + 0.4 X $30)
29

Congestion (No Losses): Node S Price
Transmission Limit = 75.2 MW
N Load
N
100 MW
75.2 MW 24.8 MW
Offer
125 @ $30
W Gen
W
E
Offer
E Gen 125 @ $35
Dispatch
100 MW
+.9 MW
25.7 MW $30.50
S
+ 1 MW
24.7 MW
Dispatch
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 $35 + 0.9 X $30)
30

Congestion (No Losses): Node W Price
Transmission Limit = 75.2 MW
N Load
N
100 MW
75 MW 25 MW
Offer
125 @ $30
+ 1 MW
W Gen W $30
E
E Gen
Offer
125 @ $35
Dispatch
Dispatch
100 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

Congestion (No Losses): Summary
Transmission Limit = 75.2 MW
N Load 100 MW
N
75 MW
$35.50
25 MW
Offer
125 @ $30
W Gen
W
$30
$33
E
E Gen
Offer
125 @ $35
Dispatch
100 MW
25 MW
$30.50
S
25 MW
Dispatch
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

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
• $35.5 - $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 = $3000
33

Exercise One
N Load
N
100 MW
75 MW 25 MW
Offer
125 @ $30
W Gen
W
E
E Gen
Offer
125 @ $35
Dispatch
100 MW
25 MW
S
25 MW
Dispatch
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

Exercise Answer: Node N Price
(75 +.375 + .125)
N Load 100 MW + 1 MW
N
75.5 MW $32.50 25.5 MW (25 +.125 + .375)
Offer
125 @ $30
W Gen
W
E
Offer
E Gen 125 @ $35
Dispatch
100 MW
+.5 MW
25 MW
25 MW
(25 +.125 – .125)
S (25 +.125 – .125)
Transmission Limit = 25 MW
Dispatch
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 $35 + 0.5 X $30)
35

Exercise Answer: Node S Price
(75 + .75)
N Load 100 MW
N
75.25 MW 24.75 MW
(25 - .25)
Offer
125 @ $30
W Gen
W
E
Offer
E Gen 125 @ $35
Dispatch
100 MW
+1 MW
25.75 MW $30 24.75 MW
(25 + .75)
S (25 - .25)
+ 1 MW
Dispatch
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

Losses, No Congestion
37

Losses (No Congestion): Dispatch
75 MW
N Load
N
100 MW
25 MW
Offer
125 @ $30
W Gen W
Dispatch
78 MW
26 MW
E
E Gen
Dispatch
Offer
125 @ $35
104 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

Losses (No Congestion): Node N Price
75.75 MW
N Load
N
$31.20
100 MW
25.25 MW
+ 1 MW
Offer
125 @ $30
W Gen
Dispatch
104 MW
+1.04 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
Dispatch
0 MW
Offer
125 @ $35
39

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:
http://www.theimo.com/imoweb.pubs/consult/mep/dam_wg_2003sep16_LMPexamples.pdf
• 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

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

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

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

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

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
= - 11.2% 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

Nodal Price Calculation in DSO
• Penalty Factors
• Bids and Offers
• 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
• Dispatch Instructions
• All Other Nodal Prices
46

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

Effective Price
Delivery Point
Offer/Bid Stack
Penalty
Factors
Richview Equivalent
Offer/Bid Stack
Gen D 100 MW @ $50 1.3
Gen D 100 MW @ $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

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

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

System Marginal Cost: No Congestion
Gen B 100 MW @ $70.7
Gen A 100 MW @ $67.5
Gen D 100 MW @ $65
Gen C 100 MW @ $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

Nodal Prices: No Congestion
Offer
Price
Penalty
Factor
Losses
Cost
Congestion
Cost
Nodal
Price
Gen A
$75
0.90
$7.22
0
$72.22
Gen B
$70
1.01
-$0.64
0
$64.36
Gen C
$60
0.95
$3.42
0
$68.42
Gen D $50 1.30 -$15.00 0 $50.00
Load Z N/A 0.97 $2.01 0 $67.01
Richview = s
$65.00
52

Nodal Prices and Dispatch: 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
Offer prices:
• Gen A $75
• Gen B $70
• Gen C $60
• Gen D $50
Which generators should be dispatched
53

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

System Marginal Cost: Congestion
Gen B 100 MW @ $70.7
Gen A 100 MW @ $67.5
Gen D 90 MW @ $65
Gen C 100 MW @ $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

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

Line 1 Transmission Limit Cost
Load Z
+1 MW 23% losses
Gen D
Gen C
Gen B
Richview
+.77 MW
- 11.2% losses
Gen A
-.69 MW
• Increase Gen D by 1 MW results in +.7692 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 = -$1.92
57

Nodal Prices: Congestion
Offer
Price
Penalty
Factor
Losses
Cost
Congestion
Cost
Nodal
Price
Gen A
$75
0.90
$7.50
0
$75.00
Gen B
$70
1.01
-$0.67
0
$66.83
Gen C
$60
0.95
$3.55
0
$71.05
Gen D
$50
1.30
-$15.58
-1.92
$50.00
Load Z N/A 0.97 $2.09 0 $69.59
Richview = s
$67.50
58

Nodal Prices and Dispatch: 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
Offer prices:
• Gen A $75
• Gen B $70
• Gen C $60
• Gen D $50
Which generators should be dispatched
59

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 $67.50
60

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
Energy
Operating Reserve
10S/10NS/30
61