Transmission Pricing

1
Transmission Pricing Congestion Management in a
Competitive Power Market

• Janusz W Bialek
• University of Edinburgh, Scotland

2
Literature

• R. Green Electricity transmission pricing an
  international comparison Utilities Policy, Vol.
  6, No. 3, 1997
• R.D. Christie, B. F. Wollenberg, I. Wangestein
  Transmission management in the deregulated
  environment Proc. IEEE, Vol. 88, No. 2, Feb.
  2000
• D. S. Kirschen, G. Strbac Fundamentals of power
  system economics Wiley 2004

3
Outline

• Historical perspective
• Components of transmission costs
• 6 principles of transmission pricing
• Short-run transmission prices
• Transmission pricing in the UK
• Transmission pricing in interconnected networks
• Conclusions

4
Historical perspective

• Until 1990 vertically-integrated utilities
  everywhere
• Short-term optimisation of combined generation
  and transmission
• Tariffs included implicitly the cost of
  transmission
• No need for unbundling

5
Liberalisation (deregulation)

• Breaking up the traditionally vertically-integrate
  d utility
• Universal model generation separate from
  transmission
• Competition in generation
• Regulated monopoly in transmission
• Need to unbundle the tariffs
• energy price determined by market forces
• Regulated transmission price
• Uplift (ancillary services)
• How much should a generator/load pay for using
  the transmission network?

6
Components of transmission costs

• Fixed costs
• Return and depreciation of capital equipment
• Operation and maintenance
• Variable cost components (depend on utilisation)
• Transmission (heating) losses due to flow of
  current I2R
• Opportunity cost of system constraintscost of
  not being able to use cheaper generation due to
  transmission constraints
• Optimal transmission price should be equal to
  short-run marginal cost
• Complications
• Network externalities actions of one user may
  affect all other users
• Parallel flows (loop flows) in a meshed network
  energy from A to B flows through all parallel
  path in a meshed network
• Real and reactive power flows

7
Two main functions of prices

• Signal of relative costs
• location in A costs twice that of B
• transmission may be an alternative to a new
  generation
• Distribution determine how many resources are
  transferred when a transaction takes place
• Lowered generators profits and increased loads
  costs
• Incentive to distort prices
• Society welfare is maximised when prices are
  equal to marginal costs cost of increasing
  output by 1 unit
• Marginal price is multiplied by the whole
  production to get the total revenue
• Generally marginal prices are higher than average
  prices

8
6 principles of transmission pricing

• Promote the efficient day-to-day operation of the
  bulk power market
• Signal locational advantages for investment in
  generation and demand
• Signal the need to for investment in the
  transmission system
• Compensate the owners of the existing
  transmission assets
• Be simple and transparent
• Be politically implementable
• Signalling in red, distribution in blue
• First two short-term efficiency, 2-4 long-term
  efficiency, 5-6 implementation
• 7th principle no solution can satisfy all 6
  principles

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Principle 1 promoting day-to-day operation of
the bulk power market

• all generators must be coordinated
• economic dispatch must take into account the
  marginal cost of transmission
• Two components of short-run transmission costs
• Actual cost of transmission losses
• Opportunity cost of transmission constraints
• Relative importance is system specific
• Marginal costs of losses and constraints should
  be added to generators operating costs when
  deciding which stations to run

10
Locational Marginal Prices (LMPs)

• Generators submit bids (theoretically marginal
  generation costs)
• System Operator (SO) runs OPF to determine
  optimal dispatch and resulting LMPs

• pk price at bus k, p - price at the reference
  bus, dk demand at node k, µi Lagrange
  multiplier (shadow price) of constraint at line
  i, zi power flow at line i
• Marginal price reference price cost of
  increased losses due increasing nodal demand by
  1MW cost of incresased constraints due to
  increasing nodal demand by 1 MW
• If losses and constraints are neglected, prices
  are the same everywhere and equal to the marginal
  cost of the most expensive plant(s) running

11
Transmission losses
neglecting constraints

• The derivative can be greater or less than zero
  so transmission cost due to the losses may be
  negative
• Losses are I2R so marginal cost (derivative) is
  twice the average cost
• Charging the marginal cost leaves money on the
  table merchandise (or network) surplus1 cost
  of losses

12
Congestion
neglecting losses

• pk depends on congestion anywhere in the network
  so even a single constraint may cause all nodal
  prices to differ in a meshed network
• A constraint may bind for the last few MW of
  generation, so that absolute saving from
  releasing constraint is small
• But marginal price is charged for all MWs so
  marginal cost is large
• The difference merchandise (or network) surplus2
  congestion rents S (constrained flow zi ) x
  (shadow cost of constraint µi)

13
Merchandise (network) surplus

• MS cost of losses congestion rents
• It is money left on the table after generators
  have been paid
• It cant be kept by SO as it would create inverse
  incentives (the higher losses and congestion, the
  higher MS)
• It can be used towards paying the fixed costs of
  transmission (i.e. paying for the transmission
  network itself)
• Experience shows that merchandise surplus covers
  only 20-40 of fixed network costs need to have
  a top-up
• Discussed later

14
LMPs

• LMP is the same for generation and demand located
  at the same node
• Bidding generators are paid for their whole
  production at their LMP while loads are charged
  for their whole consumption at their LMP
• A bilateral contract A-B is charged a
  transmission (wheeling) price LMP(B) LMP(A)
• A transmission price (wheeling rate) may be
  negative when a contract A-B reduces losses
  and/or reduces congestion
• Sometimes difficult to stomach by utilities

15
LMPs

• Transmission prices (i.e. differences between
  nodal prices) can be very volatile due to
  constraints
• Hedging use merchandise surplus to fix
  transmission prices for contracts
• LMPs are used in New Zealand, and widely in USA
  (PJM, NYISO etc)
• Behind the Standard Market Design proposed by
  FERC in USA
• Violently opposed by many as not-transparent,
  complicated and too centralised

16
Simplifications of LMP

• Zonal, as opposed to nodal, prices to simplify
  trading
• Prices within a zone are assumed to be the same
• Valid only in radial connections of zones
• Even a single constraint may make all the LMPs to
  differ in a meshed network
• Arbitraging - used in California with disastrous
  effect

17

• Zones would result in a few clusters with similar
  prices and standard deviations
• No clusters in any of the months

W. Hogan GETTING THE PRICES RIGHT IN PJM A
Summary April 1998 through September 1999
18
Modifications of LMP

• LMPs for generators (because they may respond to
  prices)
• Lower average prices for the loads (because they
  cannot respond in real time)
• Again arbitraging

19
Other approaches to charging for short-run
transmission costs

• Charge uniformly, i.e. everyone pays equal share
  (UK)
• Simple so good for trading
• Inefficient as charges do not reflect costs
• Acceptable if the costs are relatively small (has
  worked for 15 years in the UK)
• LMPs are volatile so publish a-priori
  transmission prices which generators will have to
  take into account when submitting their bids
• Good for trading as transm. prices are known
  a-priori
• May be used for losses but very difficult for
  constraints
• Scandinavia seasonal locational loss factors
• Locational loss factors blocked by northern users
  in the UK

20
Principle 2 Signalling locational advantages for
investment in generation and demand

• Important for new investment you cant move the
  current plants
• LMPs send correct signals but only for small
  projects
• Large projects can change power flows (and costs)
  considerably so transmission prices will change
  (see hedging)
• UK locational transmission prices, published
  apriori, based on MW-km approach (discussed later)

21
Principle 3 Signalling the need for investment
in the transmission system

• Transmission investment is often an alternative
  to a power plant
• Prices will only be useful if are based on
  marginal costs
• Large LMP differences signal a weak transmission
  link in need of upgrading
• Three problems with using high price
  differentials to guide investment in transmission
  system
• Most investment are lumpy and will lead to
  significant change in flows and prices so it is
  difficult to lock in to ex ante prices
• When transm. ownership is divided, any investment
  may cause significant externalities
• Most utilities do not use transmission prices to
  guide investment (except Australia and New
  Zealand)

22
Principle 4 Compensating the owners of existing
transmission assets

• It is essential as otherwise companies would not
  invest in the future
• Due to lumpy investments, economies of scale and
  loop flow effect in meshed networks, marginal
  pricing methods (like LMPs) recover only 20-40
  of fixed costs
• Additional residual charge needed often much
  higher than the main signal
• Transmission revenues are usually capped to
  prevent perverse incentives
• Some attempts of merchant transmission projects
  in Australia

23
Principle 5 Simplicity and transparency

• Essential for traders
• But marginal prices are complex and not easy to
  understand
• Usually some compromise required, e.g. zones

24
Principle 6 Political implementation

• Any pricing systems produces winners and losers
  but losers tend to shout louder
• No good to have an optimal methodology if it
  cannot be implemented
• Most utilities tend to understate price
  differentials to make them more acceptable

25
MW-km methodology

• Used in two cases
• residual charge merchandise surplus due to LMPs
  covers only about 20-40 of fixed network costs
  so need to recover the rest
• UK no LMPs so need to charge generators and
  loads for fixed cost of transmission
• Principle determine a usage of a network due
  to each generator/load in terms of (power flow)
  x (distance)
• Definition of usage is unique for a transaction
  (generator-load pair) but not for a nodal
  injection
• Many different approaches

26
Transmission Network Use of System (TNUoS)
charges in the UK

• Hot topic in UK with direct involvement of JB and
  KN
• NETA almost pure bilateral market balancing
  mechanism
• Cost of losses and congestion recovered uniformly
• TNUoS is a fixed annual price charged per kW of
  installed capacity to recover fixed network costs

27
TNUoS

• Methodology
• increase demand at a node by 1 MW balanced by the
  slack node (dc load flow)
• calculate the resulting increase in line flows
• sum up all the increased flows multiplied by the
  distance
• Multiply by expansion constant (approx. 10/MW.km
  for 400 kV lines)
• Average charges within zones
• Add a uniform shift to achieve a required
  generationdemand split of payments
• Distinct north-south pattern of flows in the UK
  resulting in pronounced north-south differentials

28

• But even those high differentials recover only
  16 of fixed costs

• Reason lumpy investments and loop flows
• Lumpy investments the network is overdesigned
• Loop flows some lines are loaded more (wrt
  limits) than the others and you cant load more
  underutilised lines without overloading other
  lines

29

• 1 GW plant in North of Scotland would pay 20M
  annually
• 1 GW plant in Cornwall would get paid 10.5M
• Danger for renewable projects in Scotland
• Huge protests in Scotland ignored by Ofgem
• Approved for implementation but Scottish Power
  launched Judicial Review
• Well see

30
Assessment of TNUoS charging

• Promote the efficient day-to-day operation of the
  bulk power market no as TNUoS prices are fixed
• Signal locational advantages for investment in
  generation and demand very good main reason for
  using TNUoS
• Signal the need for investment in the
  transmission system no
• Compensate the owners of the existing
  transmission assets yes
• Be simple and transparent simple but not
  necessarily transparent
• Be politically implementable no because of high
  geographic differentials

31
Transmission pricing in interconnected networks

• Europe (countries), USA (utilities), India (5
  regions)
• Practically almost every country has a different
  transmission pricing regime
• Nightmare to arrange a cross-border trade
• Pancaking
• Early solutions contract path, i.e. an arbitrary
  decided transmission path linking two countries
  (utilities)

32
Example of parallel flows trade from northern
France to Italy
Source H-J Haubrich, W. Fritz
33
Unexpected flows in bottlenecks
Source P. Bonnard, 2003 IEEE Trans. Distr. Conf
34

• Contracts paths must not be used for operation
  (congestion management) and should not be used
  for transmission pricing
• Less of a problem if dc links used
• USA moves by FERC towards Standard Market Design
  (LMPs), Regional Transmission Organisations and
  seamless trading
• Europe annual payments between countries to
  compensate for the effects of cross-border trades
  (redispatch, losses and use-of-system)
• How to decide who pays how much?
• Marginal MW-km (like UK TNUoS) cannot be used as
  prices would depend on the choice of European
  balancing (slack) node
• Number of alternatives proposed, e.g. tracing

35
Conclusions

• Despite 15 years of experience, transmission
  pricing remains a hotly disputed topic
• Contradicting goals simplicity vs
  cost-reflectiveness
• Almost every country has a different regime
• I hope youll get it right!