Transmission Pricing

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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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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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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


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


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


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%



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



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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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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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 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

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Transmission Pricing