View
41
Download
0
Category
Preview:
DESCRIPTION
Nodal Pricing Basics. Drew Phillips 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. - PowerPoint PPT Presentation
Citation preview
1
Nodal Pricing Basics
Drew Phillips
Market Evolution Program
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
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system where energy is injected by generators or withdrawn by loads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
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
5
Impedance, Power Flows, Losses and Limits
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
7
Relative Impedance and Power Flow
115 kV
230 kV
Gen Load
Energy will flow preferentially on the 230 kV path:• Higher voltage• More lines in parallel• Fewer transformers
Transformer
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
9
Power Flows
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
N Load
W Gen
N
W
S
E
75 %
25 %
E Gen
10
What if E Gen supplies N Load?
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
N Load
N
W
S
E
25 %
75 %
E Gen
11
40 MW60 MW
Superposition
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
N Load
W Gen
N
W
S
E E Gen
100 MW
40 MW10 MW
30 MW
45 MW
15 MW
60 MW60 MW
5 MW(15 – 10) 5 MW (15 – 10)
45 MW55 MW (15 + 30)(45 + 10)
12
Loss Comparison for 100 km Lines
115 kV
230 kV
500 kV
90 MW
90 MW
90 MW 79.5 MW
88.5 MW
89.9 MW180 A
390 A
780 A
• 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
Current (Amps) A
13
Loss Comparison
Losses are higher on a line that is heavily loaded for the same increase in current
Current (I)
Loss
es (M
W)
=
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
15
Nodal Price Examples
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
= + +
17
Current Pricing Scheme
NodalPrices
Currently calculated for information purposes only
IMOMarket
Participants
UnconstrainedCalculation
• ignores physical limitations
MarketSchedule
UniformPrice
ConstrainedCalculation
• considers physical limitations
DispatchSchedule
Bids/Offers CMSCBids/
Offers
Dispatchableresources
produce or consume MWs
$
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)
19
No Congestion or Losses
20
Transmission Limit = 85 MW
No Congestion or Losses: Dispatch
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?
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
21
Transmission Limit = 85 MW
No Congestion or Losses: Node N Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
$30
+ 1 MW
0 MW
Dispatch
100 MW
Dispatch
+1 MW
25.25 MW
75.75 MW 25.25 MW
25.25 MW
(25 + .25)(75 + .75)
(25 + .25) (25 + .25)
22
Transmission Limit = 85 MW
No Congestion or Losses: Node W Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
+1 MW
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
$30
+ 1 MW
23
Transmission Limit = 85 MW
No Congestion or Losses: Node E Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
+1 MW
0 MW
Dispatch
125 @ $35
Offer$30
+ 1 MW
25.5 MW
75.5 MW 24.5 MW
25.5 MW
(25 - .5)(75 + .5)
(25 + .5) (25 + .5)
24
Transmission Limit = 85 MW
No Congestion or Losses: Node S Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
+1 MW
0 MW
Dispatch
125 @ $35
Offer
$30
+ 1 MW
24.75 MW
75.25 MW 24.75 MW
25.75 MW
(25 - .25)(75 + .25)
(25 + .75) (25 - .25)
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
26
Congestion, No Losses
27
Transmission Limit = 75.2 MW
Congestion (No Losses): Dispatch
Assume the transmission limit is reduced; dispatch can be solved as in the no congestion case, but what is the effect on nodal prices?
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
28
0 MW
Dispatch
+1.1 MW
100 MW
Dispatch
-.1 MW
Transmission Limit = 75.2 MW
Congestion (No Losses): Node N Price
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)
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
24.7 MW
75.2 MW 25.8 MW
24.7 MW
$35.50
+ 1 MW
29
100 MW
Dispatch
+.4 MW
0 MW
Dispatch
+.6 MW
Transmission Limit = 75.2 MW
Congestion (No Losses): Node E Price
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 $35 + 0.4 X $30)
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
25.2 MW
75.2 MW 24.8 MW
25.2 MW
$33
+ 1 MW
30
Transmission Limit = 75.2 MW
Congestion (No Losses): Node S Price
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 $35 + 0.8 X $30)
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
24.6 MW
75.2 MW 24.8 MW
25.6 MW $31
+ 1 MW
0 MW
Dispatch
+.2 MW
100 MW
Dispatch
+.8 MW
31
Transmission Limit = 75.2 MW
Congestion (No Losses): Node W Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
+1 MW
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
$30
+ 1 MW
32
Transmission Limit = 75.2 MW
Congestion (No Losses): Summary
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
$30
$31
$33
$35.50
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• $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
34
Transmission Limit = 25 MW
Exercise One
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?
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
100 MW
Dispatch
0 MW
Dispatch
125 @ $35
Offer
25 MW
75 MW 25 MW
25 MW
35
Transmission Limit = 25 MW
Exercise Answer: Node N Price
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)
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
$32.50
25 MW
75.5 MW 25.5 MW
25 MW
(25 +.125 – .125) (25 +.125 – .125)
(25 +.125 + .375)(75 +.375 + .125)
+ 1 MW
100 MW
Dispatch
+.5 MW
0 MW
Dispatch
+.5 MW
36
Transmission Limit = 25 MW
Exercise Answer: Node S Price
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
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen 125 @ $35
Offer
$30
+ 1 MW
0 MW
Dispatch
100 MW
Dispatch
+1 MW
24.75 MW
75.25 MW 24.75 MW
25.75 MW
(25 + .75) (25 - .25)
(25 - .25)(75 + .75)
37
Losses, No Congestion
38
Losses (No Congestion): Dispatch
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?
N Load
W Gen
N
W
S
E
100 MW
125 @ $30
Offer
E Gen E Gen
104 MW
Dispatch
0 MW
Dispatch
125 @ $35
Offer78 MW
75 MW
26 MW
25 MW
39
104 MW
Dispatch
+1.04 MW
Losses (No Congestion): Node N Price
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
N Load
W Gen
N
W
S
E
101 MW
125 @ $30
Offer
E Gen E Gen
0 MW
Dispatch
125 @ $35
Offer78.9 MW
75.75 MW
26.3 MW
25.25 MW$31.20
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: 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
41
How the Dispatch Scheduling Algorithm (DSO) Calculates Nodal Prices
42
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
43
Marginal Cost of Generationλs
System Marginal Cost at Reference Node
Marginal Cost of Losses
Marginal Cost of
Transmission Congestion
Cost of transmission limits incurred for the next MW of load at the node
Σ αnk*μk
Calculate Nodal Prices
LMP
Nodal Price
λn = + +
Cost of losses incurred for the next MW of load at the node
(DFn - 1)* λs
44
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
45
Penalty Factors
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
Gen D
Gen C
Richview
Gen AGen B
PF = .95
= - 5.3% lossesPF = 1.01
= 1% losses
PF = .9
= - 11.2% losses
PF = 1.3
= 23% losses
Load Z
PF = .97
= - 3.1% losses
Non-dispatchable
46
Nodal Price Calculation in DSO
DSO Calculation 1
• Bids and Offers• Forecast Load• System Limits
• Penalty Factors
• Transmission Model• Load Profile
• Congestion Impact
• Richview Nodal Price
• Dispatch Instructions
DSO Calculation 2
• Richview Nodal Price• Congestion Impact
• Penalty Factors
• All Other Nodal Prices
47
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
48
Effective Price
Delivery Point Offer/Bid Stack
Gen D 100 MW @ $50 1.3
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
49
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 @ $65Forecast Demand
50
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%
3%
10%
2%
4%
4%
5%4%Richview
Gen D
Gen CGen A
Gen B
Load Z
51
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 (λs) = $65
Gen C 100 MW @ $57
Gen B 100 MW @ $70.7
Gen A 100 MW @ $67.5
Gen D 100 MW @ $65Forecast Demand
52
Nodal Prices: No Congestion
Offer Price
Gen C
Gen B
Gen A
$60
$70
$75
0.95
1.01
0.90
$3.42
-$0.64
$7.22
Penalty Factor
Losses Cost
0
0
0
Congestion Cost
$68.42
$64.36
$72.22
Gen D $50 1.30 -$15.00 0 $50.00
Nodal Price
Richview = λs $65.00
Load Z N/A 0.97 $2.01 0 $67.01
53
$68.42
$50.00
Nodal Prices and Dispatch: No Congestion
Offer prices: Gen A $75 Gen B $70 Gen C $60 Gen D $50Which generators should be dispatched?
$65.00Gen D
Gen C
Richview
Gen AGen B $64.36
$72.22
Fully dispatched
Partially dispatched
54
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 AGen B
Binding Transmission Limit
Line 1
Load Z
55
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 (λs) = $67.5 There is a cost associated with the Line 1 transmission
limit
Gen C 100 MW @ $57
Gen B 100 MW @ $70.7
Gen A 100 MW @ $67.5
Gen D 90 MW @ $65 Forecast Demand
56
Line 1 Transmission Limit Cost
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
Binding Transmission Limit
Gen D
Gen C
Richview
Gen AGen B
Line 1
Load Z
57
Line 1 Transmission Limit Cost
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
Gen D
Gen C
Richview
Gen AGen B
- 11.2% losses
+1 MW 23% losses
+.77 MW
-.69 MW
Load Z
58
Nodal Prices: Congestion
Richview = λs
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
Load Z N/A 0.97 $2.09 0 $69.59
59
$71.05
$50.00
Nodal Prices and Dispatch: Congestion
Offer prices: Gen A $75 Gen B $70 Gen C $60 Gen D $50Which generators should be dispatched?
$67.50Gen D
Gen C
Richview
Gen AGen B $66.83
$75.00
Binding Transmission Limit
Line 1
Partially dispatched
Partially dispatchedFully dispatched
60
Nodal Price Comparison
Gen C
Gen B
Gen A
Gen D
$68.42
$64.36
$72.22
$50.00
Nodal Price(No Congestion)
$71.05
$66.83
$75.00
$50.00
Richview = λs $65.00 $67.50
Nodal Price(Congestion)
Load Z $67.01 $69.59
61
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 NodeOperating Reserve
10S/10NS/30Energy
Recommended