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Experience with FTRs and Related Concepts in Australia and New Zealand

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Financial Transmission Rights

Part of the book series: Lecture Notes in Energy ((LNEN,volume 7))

Abstract

As one of the first Full Nodal Pricing (FNP) electricity markets, New Zealand was also one of the first places where FTR concepts were developed and considered for implementation, actually as early as 1989. Ironically, though, it is only now, after more than two decades of discussion, that a limited FTR market seems likely to be actually implemented. This long delay may be partly attributed to failures in the regulatory process, but it also reflects the special circumstances facing the small hydro-dominated New Zealand market, in which a relatively small group of vertically integrated participants compete over a fairly sparse network, in which losses and reserve support requirements play a more important role than line transfer limits, per se. Thus there has been considerable debate over whether classical FTR concepts are really suitable. We discuss several variant proposals, one of which is moving toward implementation by 2012.

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Notes

  1. 1.

    This lack of congestion is partly an illusion. In a small market, a few major users can effectively prevent a line reaching its upper flow limit, and without FTRs they are motivated to do so.

  2. 2.

    The residual market settlement surplus must be all loss rents, and the residual nodal price differences must be loss-induced. Since the piece-wise linearization represents an underlying quadratic loss function, these two components are approximately equal, so the remaining surplus should cover about half the loss-induced price differences.

  3. 3.

    If the local price is P n , the effective price is just P n  − (P n   − GWAP) = GWAP as in the IDMA representation of a zonal market, discussed in Sect. 13.6 below.

  4. 4.

    Efficient signalling is still compromised to the extent that increasing consumption in one period increases rental allocations in future periods, though. Consideration was given to excluding periods in which congestion occurred from the historical load calculation, but this makes little difference if congestion is infrequent. Distortion of pervasive loss-induced differentials is more difficult to deal with, and some versions of this proposal excluded them entirely.

  5. 5.

    Read also notes that these dynamic signals are of limited relevance to small users, who do not actually face spot prices, and argues that LRA actually improves on the status quo for large loads. With no locational hedging available, they face a disproportionate second order signal to avoid causing congestion, since the resultant high local prices would apply to their entire load. They are thus incentivised to reduce consumption in favour of smaller loads which, being oblivious of the second order considerations, effectively see the nodal price as a pure SRMC signal.

  6. 6.

    By way of contrast, if participants have to purchase FTRs they effectively pay the average locational price differentials, in the FTR purchase price.

  7. 7.

    By construction (in a lossless system), the intra-island rents are just sufficient to hedge between GWAP and the Load Weighted Average Price (LWAP), and hence to hedge all loads to GWAP.

  8. 8.

    Note that alternatives, such as covering only congestion costs, or loss rents but not loss costs, would require us to calculate what those components actually were. But this could be done, as for the LRA proposal.

  9. 9.

    The high inter-island differentials shown in Fig. 13.1 are partly due to this facility being unavailable, with one pole out of service. Commissioning of a replacement will restore that facility, but also greatly increase capacity. So, while inter-island flow limits will occur less often, the proportion caused by congestion will most likely fall too.

  10. 10.

    This situation differs from that for losses, where rents implied by the piece-wise linear “loss requirement curve” remain in the market settlement surplus.

  11. 11.

    By way of contrast, the classic revenue adequacy result rests on the assumption that price differentials only arise when a constraint binds, at which time it will generate enough rent to cover any FTR up to the binding limit.

  12. 12.

    Binding line limits and (on a much smaller scale) loss tranche limits both generate similar pricing effects, inducing (positive or negative) rents to be collected on all lines in all loops in which that line is involved. But what matters, for revenue adequacy of the inter-island FTR, is to partition rents according to flows on lines where rent is generated, not where it is collected.

  13. 13.

    This is an important issue in a small market, where fragmentation of trading platforms increases the difficulty of achieving desirable liquidity on any one platform. Conversely, Fig. 13.1 suggests that accurate modeling of possible congestion limits probably has less practical impact on revenue adequacy than dealing with the loss and reserve costs issues. Read and Miller (2011) point out that, for a small number of hubs, the FTR feasible region could be represented as the set of all possible convex combinations of the extreme inter-hub flow patterns used to determine the rents available for FTR support. (For the initial two hubs, this only involves the maximum forward/reverse flows between them). Given a set of extreme flows determined by the System Operator, the FTR manager could actually clear the FTR market without any direct knowledge of the transmission system at all.

  14. 14.

    Possibly via an integrated auction somewhat similar to that proposed by O’Neill et al. (2002).

  15. 15.

    One major exception relates to the Snowy Mountains hydro-electric development, which lies in New South Wales, but close to the Victorian border, and which until recently formed a region of its own (SNY).

  16. 16.

    South Australia, Victoria, New South Wales and Queensland form a chain, with the island of Tasmania linked to Victoria.

  17. 17.

    Thus zero cross-border flow does not generally imply minimum losses, or zero marginal loss.

  18. 18.

    NEMDE is now the NEM market clearing engine, replacing a version of SPD.

  19. 19.

    We have expressed that RHS constant as a linear combination of terms, and multiplied by −1, so as to facilitate discussion of a general pricing/hedging framework in Sect. 13.6.

  20. 20.

    In brief, this means that the participation factors referred to above must correspond to the increase in the constraint LHS (e.g. the flow over a constrained line) if a notional 1 MW flow were sent from the generator in question to the regional reference node. For simple line flow limits, these CPFs are just PTDF’s using the regional reference node as “swing bus”.

  21. 21.

    This can be done by using regional energy balance equation(s) to substitute out for injection at the regional reference node(s).

  22. 22.

    Initially known as “Inter-Regional Settlements Surplus” (IRSS), but later changed to “Inter-Regional Settlements Residue” (IRSR) because it is not always positive.

  23. 23.

    The SRA auction makes no provision for inclusion of MNSP rentals in the auction process.

  24. 24.

    In extreme cases power may actually flow across a border in a direction opposite to the price difference, causing the IRSR to be negative. Originally, negative residues were offset against positive residues within the same weekly sub-period, so SRA units could have negative values. Recently this has been changed so that SRA units always have positive payouts, with any revenue shortfall due to counter-price flow being effectively subtracted from the auction proceeds passed through to TNSPs.

  25. 25.

    The proceeds of these auctions are deemed to belong to the parties providing the underlying network capacity. However, the regulatory regime operates in such a way that those parties effectively have no financial interest in the auction or IRSR outcomes, and are not therefore incentivized to either provide, or withhold, capacity. Read (2008) suggests a regime that would partially expose transmission providers to the outcome, with the aim of incentivizing maximum economic capacity availability, but that suggestion has not been pursued further.

  26. 26.

    In theory, there is provision to carry unsold units forward to the following auction, but this does not happen because units have unambiguously positive value, and always sell. Since the auction process makes no provision for resale of units, the quantity available in each auction is constant for each interconnector/direction.

  27. 27.

    Linked bids that are accepted are charged the sum of the individual component prices that comprise the bid. But we understand this facility is seldom, if ever, used.

  28. 28.

    Queensland was added in 2001, shortly after the scheme commenced, and the Snowy region incorporated into New South Wales in 2008.

  29. 29.

    Even if the transmission system was 100 % firm, rents should only cover half the (loss-induced) inter-regional differential in periods with no congestion.

  30. 30.

    Better fits could be obtained for lines that did not pass through the origin. But such lines do not represent the hedging available from an auction of proportional rental shares.

  31. 31.

    Quadratic losses imply that rents will only cover half the (loss-induced) inter-regional differentials on the actual flow, when flow is unconstrained. This may not matter much because differentials are typically low in such situations. Unlike the congested situation, though, flow volume in such periods is essentially what participants, in aggregate, have decided they want it to be. Thus the ratio reported here will be under-stated because true “hedging requirements” may be significantly less than nominal interconnector capacity, and maybe close to actual flows.

  32. 32.

    In reality, other terms, such as the inertia of generating units assumed or observed to be running, may affect the RHS, but that complication will be ignored.

  33. 33.

    We have also defined them in fixed MW capacity terms, but assume that revenue adequacy is dealt with by scaling, thus creating a problem with “firmness”.

  34. 34.

    Which can be very important in some of these constrained situations where a single generator may act as a “gatekeeper” determining effective interconnector flow capacity.

  35. 35.

    CSCs held with respect to various constraints might imply different preferred generation levels, and conflicting second order incentives, if those constraints bind simultaneously. But participants are free to target a dispatch level that makes an appropriate trade-off, given the relative prices involved on any occasion.

  36. 36.

    In an appendix, CRA also argues that there are conceptual errors in the Biggar paper, and in its critique of earlier work by CRA.

  37. 37.

    The constraints involve a trade-off between generation in the SNY region and both VIC-SNY, SNY-NSW interconnector flows. Initially, the trial did not involve the VIC-SNY interconnector, so CSP/CSC transfers were only made between SNY generation and the SNY-NSW interconnector, within an aggregate rental pool that was less firm than the transmission capacity. This was subsequently modified to eliminate negative residues on the VIC-SNY interconnector.

  38. 38.

    This may be seen as a very limited application of the CSP/CRR framework, in which the transmission system provider, who ultimately receives the SRA proceeds, effectively guarantees that the net interconnector capacity available to support flows in each direction will at least be non-negative.

  39. 39.

    All URLs accessed 1 Oct 2011. “NZEA website” is http://www.ea.govt.nz/our-work/programmes/priority-projects/locational-hedges/, but will be archived in future. “MCE website” is http://www.mce.gov.au/emr/elec_trans/archive.html. “AEMC website” is http://www.aemc.gov.au/Market-Reviews/Completed/Congestion-Management-Review.html. Older reports available on request from the corresponding author.

References

All URLs accessed 1 Oct 2011. “NZEA website” is http://www.ea.govt.nz/our-work/programmes/priority-projects/locational-hedges/, but will be archived in future. “MCE website” is http://www.mce.gov.au/emr/elec_trans/archive.html. “AEMC website” is http://www.aemc.gov.au/Market-Reviews/Completed/Congestion-Management-Review.html. Older reports available on request from the corresponding author.

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Acknowledgement

The authors wish to thank the EA (New Zealand) and AEMO (Australia) for provision of data, and permission to publish.

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Authors and Affiliations

  1. University of Canterbury, 4800, Christchurch, 8140, New Zealand

    E. Grant Read & Peter R. Jackson

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  1. E. Grant Read
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  2. Peter R. Jackson
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Correspondence to E. Grant Read .

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Editors and Affiliations

  1. Económicas (CIDE), Department of Economics, Centro de Investigación y Docencia, Carretera Mexico-Toluca 3655, Mexico, 06400, Mexico

    Juan Rosellón

  2. Åsegårdsvegen 65, Ålesund, 6017, Norway

    Tarjei Kristiansen

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Read, E.G., Jackson, P.R. (2013). Experience with FTRs and Related Concepts in Australia and New Zealand. In: Rosellón, J., Kristiansen, T. (eds) Financial Transmission Rights. Lecture Notes in Energy, vol 7. Springer, London. https://doi.org/10.1007/978-1-4471-4787-9_13

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  • DOI: https://doi.org/10.1007/978-1-4471-4787-9_13

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  • Print ISBN: 978-1-4471-4786-2

  • Online ISBN: 978-1-4471-4787-9

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