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TRANSMISSION PRICING
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Objectives of TransmissionPricing
Suggest key objectives fortransmission pricing should be:
Enabling competition for grid services
where possible Enabling appropriate grid investment to
proceed
Providing incentives for the grid owner(and system operator) to minimise gridcosts
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Objectives of TransmissionPricing
Enabling competition for grid services where possible Generators and loads can compete with grid services, for
new grid investment, by either locational investmentdecisions or operating decisions (load management)
Can achieve this by either pricing or grid investment approvalprocess
If transmission pricing reflects long run marginal cost ofprovision of new transmission, and costs can be avoided byappropriate investments or operations by users, then users
are likely to make efficient investment or operating decisions Examples - locational pricing, peak pricing
Both difficult to get perfect in practice
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Objectives of TransmissionPricing
Enabling appropriate grid investmentto proceed Costs of under investment can be higher than
costs of over investment (if more difficult toquantify)
Grid owner needs process to invest whereappropriate and reasonable assurance of ability
to recover costs of investment May be appropriate to have some degree of risk
sharing on investment decisions with grid users
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Pricing Methodology
Previous sections have dealt with theobjective of transmission pricing
This section deals with how this cost is
recovered from grid users - Pricingmethodology
Common approaches include:
Post stamp pricing
Locational pricing
Peak charges
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Pricing Methodology
Post stamp pricing
All locations on grid pay same charge
Adopted on basis that locational marginal
pricing in energy market providesadequate locational signal and properlocational charges are very difficult tocalculate
But considering development of locationalcharges as future development
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Pricing Methodology
Locational pricing Attempts to signal long run marginal cost of new
transmission investment
Sends appropriate signal to allow load and generation to
compete with transmission investment But difficult to calculate accurately, as grid usage can
change over time
Common practice is to have either regional locationalpricing or limited locational pricing
Australia uses regional locational pricing Bases locational charge on last 12 months historic use of
grid
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Pricing Methodology
Locational pricing Many US jurisdictions, that dont have locational
marginal pricing in energy market, use locationalpricing in transmission pricing
Alternative is to have limited locational pricing
That is where one primary beneficiary to a set ofassets (connection assets) can be identified thencharge those assets to beneficiary and postagestamp price rest.
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Pricing Methodology
Peak charges Attempts to signal capacity value of grid
Grid users contract for maximum guaranteed capacity
Usage also includes charge for highest annual peak (or
average of several peaks) Peak charges may be offset by contracted capacity
Issues with whether peaks should be locational or systemwide
As non-coincident peaks contribute differently to over all
system capacity
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Nodal price determinationexamples
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Shadow Price, nodal price, LMP
Shadow price of a constraint is the change in theoptimum value for the objective function when theconstraint is relaxed by 1 MWh (increase load by 1MW)
3 Steps
Optimise the objective function
Re-optimizing the objective function with relaxedconstraint
The difference between the two objective functionvalues is the shadow price of the constraint
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Case 1: one node market,energy price
110
0
G1:Energy
$50/MW
Dispatch G1 100MW energy. G2 100MW reserve
Shadow price calculation
Step 1: Total cost: 100 x $50 + 100 x $10 = $6000
Step 2: increase load by 1 MW and total cost becomes 101 x $50 +
101 x $10 = $6060 Step 3: LMP (energy) = $6060 $6000 = $60
0
110
Energy (MW)
Reserve (MW)
Load =100
G1 G2
G2: Reserve$10/MW
Assuming N-1 security
requirement
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Case 2: one node market,reserve price
120
0
G1: Energy
$50/MW
Dispatch G1 100MW energy. G2 100MW reserve
Shadow price calculation
Step 1: Total cost: 100 x $50 + 100 x $10 = $6000
Step 2: relax reserve requirement by 1 MW and total cost becomes100 x $50 + 99 x $10 = $5990
Step 3: LMP (reserve) = $6000 $5990 = $10
0
120
Energy (MW)
Reserve (MW)
Load =100
G1 G2
G2: Reserve
$10/MW
Assuming N-1 securityrequirement
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2 Node Models Assumptions
Two nodes, A and B
Load is 80MW at Node B
Generation is available as follows:
A1 offers 50MW @ $50/MWh
A2 offers 60MW @ $100/MWh B1 offers 50MW @ $150/MWh
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Case 3: 2 Nodes, No Losses, NoConstraints
A BA1: 50MW
@ $50/MWh
A2: 60MW
@ $100/MWh
B1: 50MW
@ $150/MWh
Load =
80MW
Dispatch A1: 50MW, A2: 30MW
Nodal prices A: $100/MWh, B: $100/MWh
Generators Paid - $8,000
Purchasers Pay - $ 8,000
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Case 4: 2 Nodes, Losses, NoConstraints
A B
A1: 50MW @$50/MWh
A2: 60MW @$100/MWh
B1: 50MW @$150/MWh
Load = 80MW
Average loss = 5%, marginal loss = 10%
Dispatch A1: 50MW, A2: 34MW
Nodal prices A: $100/MWh, B: $110/MWh
Generators Paid: $8400 ($100 x 84)
Buyers Pay: $ 8,800 ($110 x 80) Loss Rental: $ 400
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Case 5: 2 Nodes, No Losses,Constraints
A B
A1: 50MW
@ $50/MWh
A2: 60MW
@ $100/MWh
B1: 50MW
@ $150/MWh
Load = 80MW
Dispatch A1: 50MW, A2: 10MW, B1: 20MW
Nodal prices A: $100/MWh, B: $150/MWh
Generators Paid: $9,000 ($100 x 60 + $150 x 20)
Purchasers Pay: $12,000 ($150 x 80)
Constraint Excess: $3,000 (or $50/MWh x 60MWh) Try the same exercise, if B1 offers $200/MWh
Limit 60MW
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Case 6: 2 Nodes, Shadow Price ofConstraint
A B
A1: 50MW
@ $50/MWh
A2: 60MW @$100/MWh
B1: 50MW @$150/MWh
Load =
100MW Relax constraint by 1MW Dispatch A1: 50MW, A2: 11MW, B1: 39MW
Nodal prices A: $100/MWh, B: $150/MWh
Pay generators now - $11,950
Previously paid to generators $ 12,000
Shadow price of constraint = $50 (What is the relationship with theprevious example?)
Limit 60MW
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Case 7: 2 Nodes, Losses andConstraints
A B
A1: 50MW @$50/MWh
A2: 60MW
@ $100/MWh
B1: 50MW
@ $150/MWh
Load = 80MW
Average loss = 5%, marginal loss = 10%
Dispatch A1: 50MW, A2: 13MW, B1: 20MW
Nodal prices A: $100/MWh, B: $150/MWh
Generators Paid - $9,300 ($100 x 63 + $150 x 20)
Purchasers Pay - $12,000 ($150 x 80)
Constraint Excess - $2,700 (can we separate the loss from congestionrentals?)
Limit 60MW
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Case 8: 2 Nodes, Co-optimisation
Assume that reserves are available at $10/MW fromthird parties
N-1 reserve requirement
Generator B1 now offers 50MW @ $101/MW/h(instead of $150 as in previous examples)
If not co-optimised SO will dispatch A1 for 50MWand A2 for 30MW, nodal price is $100 at both A andB, as previously shown
Generators paid $8,000, reserve providers paid$500, total cost $8,500
Co-optimisation changes dispatch
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Co-optimisation
A B
A1: 50MW
@ $50/MWh
A2: 60MW
@ $100/MWh
B1: 50MW
@ $101/MWh
Load = 80MW
Dispatch A1: 27MW, A2: 27MW, B1: 26MW
Nodal prices A: $101/MWh, B: $101/MWh
Generators Paid - $8,080
Reserve payment - $270
Total cost - $8,350
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Case 9: Reserves DeterminingDispatch
Station Reserve OfferMW $ MW $
H1 300 10 250 20
HMC1 250 11 150 16
C1 200 11 100 10D 100 15 100 5E 100 25 100 3
Assumption: Load 200 MW and all other stations small and won't set riskTotal Cost of Energy and Reserve To Meet 200MW
Energy Reserve Total
H1 200*10 = 2,000 100*3+100*5 = 800 2,800
HMC1+H1 100*10+100*11 =2,100
=100*3 = 300 2,400
Dispatch stations HMC1 and C1 ahead of H1 as lower overall cost
Energy and reserve offers
Energy Offer
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Case 10: 3 Nodes Example 1
LMP Example Base Case No Congestion:
Load = 50
MWh
Capacity60MW
G1 offersEnergy -
10MW @$10/MWh
Reserve -40 MW @$10/MWh
Capacity60MW
G2 offersEnergy -
60MW @$250 /MWh
Reserve -10 MW @$250/MWh
G1 LOAD
G3
G2
Capacity60MW
G3 offersEnergy -
60MW @600/MWh
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3 Nodes Example 1 LMPbase case, no congestion
The least cost dispatch schedule for meeting 50MWh load is$10,500, with the following dispatch schedule
Energy: 10 MWh from G1 at $10/MWh and 40MWh from G2 at$250/MWh
Reserve: 40 MWh from G1 at $10/MWh.
The least cost dispatch schedule for meeting 51 MWh load is$11,000, with the following dispatch schedule.
Energy: 10 MWh from G1 at $10/MWh and 41MWh from G2 at $250/MWh
Reserve: 40 MWh from G1 at $10/MWh and 1 MWh at $250/MWh
The energy price for the 50 MWh load is $500 /MWh, calculated asthe difference between the total delivered cost for 51 MWh and thatfor 50 MWh. The price compromises the marginal generation cost of$250 /MWh and marginal reserve cost of $250/MWh.
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Case 11: 3 Nodes Example 2:with congestion
Capacity60MW
G1 offersEnergy -
10MW @$10 /MWReserve -
40 MW @$10 /MW
Capacityde-rated to40MW
G2 offersEnergy -
60MW @$250 /MWhReserve -
10 MW @$250 /MW
G1 LOAD
G3
G2
Capacity60MW
G3 offersEnergy -
60MW @$600 /MW
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3 Nodes Example 2 - continued
The least cost dispatch schedule for meeting the 50MWh loadremains at $10,500, with the following dispatch schedule
Energy: 10 MWh from G1 at $10/MWh and 40MWh from G2 at$250/MWh
Reserve: 40 MWh from G1 at $10 /MWh.
However, to meet the 51 MWh load, G3 will be required togenerate 1 MW to meet the 51st MW, because the transmissioncapacity for G2-Load is fully utilised and constrained. The leastcost dispatch schedule for meeting 51 MWh load is $11,100,with the following dispatch schedule.
Energy: 10 MWh from G1 at $10/MWh, 40MWh from G2, and 1
MWh from G3 at $600 /MWh Reserve: 40 MWh from G1 at $10/MWh
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3 Nodes Example 2 - continued
The energy price for 50 MWh load is $600/MWh, calculated asthe difference between the total delivered cost for 51 MWh andthat for 50 MWh. The price reflects marginal generation cost of$600 /MWh.
Note that marginal reserve price is $0 /MWh as no change in
reserve cost for dispatch of 51st
MWh.
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Agenda
Case 1 Physical Withholding Capacity Case 2 Economic Withholding Case 3 - Congestion - Islanded Load Case 4 - Controlling Congestion
Case 5 - Market Power in Voltage Support Case 6 - Market Power in Frequency Keeping Case 7 - Controlling Dispatch via Reserve Pricing Case 8 Strategies Used by Traders in California
Case 9 Regulation in Singapore
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Case 1 Physical withholding
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Case 1 Physical withholdingcapacity continued (IPP D
withholds capacity)unit MW
offeredOfferprice
Dispatched MW
Revenue
IPP A G1 100 0 100 $50,000
IPP B G2 300 10 300 $150,000
IPP C G3 300 25 300 $150,000
IPP D G4 200 30 200 $100,000
IPP D G5 90 40 90 $45,000
IPP D G6 200 500 10 $5,000
Clearing price 500 1000
IPP Ds revenue = $150,000
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Case 1 Physical withholdingCapacity Contd
Winners and Losers Analysis Winners
All generators
Dont need to collude if all have same incentive
Losers
Purchasers
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Case 3 - Congestion and PriceIslanded Load
Consider situation below where congestionmeans only one generator able to supplymarginal load
Load -
100MW Line Capacity 90 MW
Rest ofSystem
Clearing
Price $30
Gen A
50MW@
$900
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Case 3 - Congestion and PriceIslanded Load Contd
islanded load needs local generator to meet marginaldemand
If demand elasticity unable to relieve congestion then localgenerator assured of dispatch regardless of price
Local generator Gen A has local market power
Load -
100MW Line Capacity 90 MW
Rest of
System
Clearing
Price $30
Gen A
50MW
@
$900
Case 3 - Congestion and Price
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Case 3 - Congestion and PriceIslanded Load Contd (elastic
demand )
MW Price (US$) Dispatched Q $ amount
Inelastic demand 90 $5,000 90
Elastic demand 5 $100 0
Elastic demand 5 $10 0
Gen A offer 50 $500 0
Rest offer 90 $30 90 $2,700
Load -100MW Line Capacity 90 MW
Rest of System
Clearing Price
$30
Gen A
50MW @
$900
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C 3 C
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Case 3 - Congestion and PriceIslanded Load Contd
Conclusions Contd If nodal price then local load exposed completely to Generator
A market power
If nodal pricing then all generators in price islanded region
benefit so limited incentive to compete for dispatch (specialcase of with holding capacity)
Nodal price sends strong investment signal for newtransmission or competing generation
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C 4 C t lli C ti
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Case 4 - Controlling CongestionContd
Consider configuration below, where the samecompany owns generators A and B For an n-1 security criteria the SO would rate the lines A, B and C and 600
MW.
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C 4 C t lli
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Case 4 - ControllingCongestion Contd
Assumption: Ignoring losses and ignoring flows bus C A - B
Gen A offers 200 MW @ $5 and 200MW@ $15
Gen B offers 300 MW @ $100
Line flows and dispatched amounts and cleared prices (Assuming Nodal
Pricing) would be approximately as below Line C is operating at its constraint limit
Case 4 Controlling Congestion
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Case 4 - Controlling CongestionContd
Load - 1000MW @
$10
Generator A
200 MW @
$10
Rest of
System - 800
MW @ $10Generator B
0 MW
@$10Line C 600 MW
Line A 400 MW
Line B 400
MW
Bus
C
Bus BBus A
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Case 4 Controlling Congestion
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Case 4 - Controlling CongestionContd
Load - 1000MW @
$100
Generator A
300 MW @
$10
Rest of
System - 700
MW @ $10Generator B
100 MW
@$100Line C 600 MW
Line A 300 MW
Line B 300
MW
Bus
C
Bus BBus A
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C 4 C t lli
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Case 4 - ControllingCongestion
Conclusions The owner of Generators A and B can structure offers on
Generator A so as to maximise total returns by forcing line C intoconstraint.
They are thus able to control a Price Islanded Load situation.
The generator financial gain is largely independent of pricingsystem adopted, i.e. Nodal, System Marginal Price, or Pay asyou bid. (Slightly higher if generator constrained on to manage
congestion sets SMP).
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Case 4 Controlling Congestion
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Case 4 - Controlling CongestionReal Life Examples
N Z - Tokaanu - Whakamaru Constraint
Genesis own both generator able to controlconstraint (Tokaanu) and generator that benefits
most from constraint binding (Huntly)
Cases 5 and 6 Market Power in
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Cases 5 and 6 - Market Power inAncillary Services
The previous examples have been of situations where generatorscan create a degree of Market Power in energy
This relied on demand inelasticity to price, could be due tocongestion or, in some cases a portfolio generators ability to controlcongestion
Ancillary Services Market Power is an extension of the samesituation
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Case 5 Voltage Support Market
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Case 5 - Voltage Support MarketPower
Voltage support requirements tend to be fairly localisedas losses very high
Voltage support market thus very regionalised withlimited competition within region
Not a problem is vertically integrated transmission andgeneration companies as internal supply was cost based
Becomes an issue for price based markets if supplierhas market power in region
Case 5 Voltage Support Market
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Case 5 - Voltage Support MarketPower
Conclusions Voltage support requirements are fixed by security criteria
(System Operator has little or no ability to respond to price)
High VAR losses can create regions of Market Power for voltagesupport providers
Generators can exploit by offering very high prices for voltagesupport
Restrained only by new investment costs and time frames
Voltage support investment usually relatively low cost and shortlead time so opportunity limited
System Operator may have limited ability (or incentive) to controlcosts if security standards prescriptive and costs passed through
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Case 6 - Frequency Keeping
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Case 6 - Frequency KeepingMarket Power - Conclusions
Frequency keeping issue unique to NZ but equivalentswill exist in other jurisdictions where resources requiredfor secure system operation split off into competitivegeneration assets
Frequency keeping requirement set by securitystandards, hence one sided market
Owner of frequency keeping asset has natural monopolyand price only limited by legislation or fear of legislation
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Case 6 - Frequency Keeping
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q y p gMarket Power Real Life
Examples Mighty River Power
Annual frequency keeping costs went from $9M to $24M over 3years (1999 - 2001).
System Operator able to control to some extent by betterdispatch matching of load and generation in real time
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Case 8: strategies used by traders
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Case 8: strategies used by tradersin California continued
Inc-ing Load Artificially increase the load on the schedule submitted to ISO
(generation and load must balance)
In real time, Enron sends the generation it scheduled, but does not takeas much load as scheduled
Say, it was scheduled to generate 1000MW, but only took 500MW.Enron made a net contribution to the grid of 500 MW
ISO pays Enron 500 x the DEC price
Case 8: strategies used by traders
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Case 8: strategies used by tradersin California continued
Duke Energy Made $10 million in 1 week by
creating congestion in path 26,and subsequently paid to relievethe congestion (at the time, withinthe Southern zone, no intra-zonalcongestion charge)
ISO subsequently created Path26, and the zone is subject tozonal price difference, thuseliminating this gaming
opportunity