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Transmission pricing in New Zealand
UtilitiesPolicy,Vol. 6, No. 3, pp. 227-235, 1997 Pergamon PIh S0957-1787(97)00021-0
© 1997 ElsevierScience Ltd. All rights reserved Printed in Great Britain 0957-1787/97 $17.00+0.00
Transmission pricing in New Zealand E. G. Read
Although the pace o f reform has been variable, New Zealand was among the first countries to attempt development, from first principles, o f a comprehensive framework for transmission pricing. That framework consisted o f nodal spot pricing to provide signals for short term efficiency, a market approach to new investment, and a 'fixed charge' approach to historical cost recovery. We discuss the motivations behind that regime, and the compromises that have been made in order to achieve a politically and commercially acceptable outcome. © 1997 Elsevier Science Ltd. All rights reserved. Keywords:Electricity;Transmission;Pricing Introduction Transmission pricing has attracted considerable international attention, and some controversy, as new electricity market forms are developed around the world. A variety of 'solutions' has emerged in international practice, but it seems fair to say that none is universally regarded as ideal. After a brief introduction to the New Zealand electricity sector, this paper summarises the transmission pricing approach adopted there. It also comments on the motivation behind, and performance of, this approach with reference to the 6 key criteria suggested by the transmission working group of EMF 15, namely that transmission prices should: 1. promote the efficient day-to-day operation of the bulk power market; 2. signal locational advantages for investment in generation and demand; 3. signal the need for investment in the transmission system; 4. compensate the owners of existing transmission assets; 5. be simple and transparent; and 6. be politically implementable. * This author is with the Energy Modelling Research Group, Department of Management, University of Canterbury, Christchurch, New Zealand.
The New Zealand electricity sector
The electricity system The New Zealand electricity system is discussed by Culy et al. (1996), from which this summary is drawn. It consists of 2 AC subsystems, for the North and South Islands, connected by a 1200 MW submarine HVDC link. The South Island system is entirely hydro, with moderate sized reservoirs allowing storage of spring/ summer flows to meet winter peaks, but relatively small interannual carryover. On average, this meets South Island requirements and allows export to the North, where there is a mixed hydro/thermal system. On average, 75% of requirements are met from hydro, 7% from geothermal, and the remainder from a variety of thermal plant, mainly burning gas. From a transmission point of view, it is worth noting that the network is relatively sparse, covering an area the size of the UK, but serving only 3.5 m people, with an annual load of around 30,000 GWh. As a result, transmission accounts for a relatively large proportion of the cost of delivered energy, especially because the major hydro resources are in the south of the South Island, while the population is concentrated in the north of the North Island. This also means that the backbone of the network is basically linear, although there are some significant loops in the North Island. On the other hand, 'the national grid', having been constructed to deliver power to a large number of small local distribution companies, has a relatively high number of nodes, when all transformers etc are included. In such a small system, spinning reserve is also a major issue, particularly because it is necessary to guard against the failure of at least 1 of the 2 HVDC poles. On occasion, this criterion has required that the receiving Island hold more generation capacity on spinning reserve duty than on generation duty.
The reform process The history and structure of the New Zealand electricity sector are discussed by Culy et al. (1996). Historically, generation and transmission were the responsibility of a 227
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single Government Department, while local distribution and retailing were the responsibility of a large number of locally elected 'Electricity Supply Authorities (ESAs)'. Since 1984 there has been a series of reforms. Generation and transmission were deregulated first but, given the surpluses at that time, there was no significant entry. Major changes started with the corporatisation of the government's generation assets into a state-owned enterprise (SOE) known as the Electricity Corporation of New Zealand (ECNZ) with the transmission assets in a subsidiary, Trans Power. SOEs are expected to operate in a fully commercial way, and ECNZ made considerable progress in terms of reducing electricity prices while substantially increasing retums to its owner, the Government. A pseudo market was also established in which ECNZ announced SRMC based spot prices, and issued contracts in the form of hedges against those prices. However this was never intended to be the end point of the process, and a task force was set up in 1988 to investigate further options in terms of developing market structures, breaking up ECNZ, and privatising where possible. The major problem facing the task force was to balance the further gains which might be made from greater competition in the sector against the efficiency losses which might be incurred by breaking up ECNZ. Breakup decisions were deferred, to be studied again by the Wholesale Electricity Market Study (1992), and the Wholesale Electricity Market Development Group (1994), with the current structure being derived from the recommendations of the latter. It was decided, though, that Trans Power should become a fully independent SOE, a goal achieved in 1992. In the meantime, a parallel process had deregulated the distribution/retail sector, and allowed local power companies to be established under a variety of ownership arrangements, ranging from sale to independent investors, through share giveaways and ownership by community trusts, to continuation of local body ownership. Finally, after 10 years of debate, a partial breakup of ECNZ was implemented in early 1996, with new market structures becoming fully operational in October 1996. Current organisation
Apart from the continued entry of new generators, the amalgamation of existing local power companies, and the long term possibility of further breakup or selldown of state assets, there are no plans to change the current structure of the sector, which is: • a single state-owned utility, Trans Power, is responsible for transmission and grid operation, including purchase of ancillary services, although it does not have a statutory monopoly; • there are 2 major generating companies, both still state-owned and owning a spatially dispersed set of 228
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hydro and thermal plant, plus a growing fringe of smaller competitors; there is no explicit regulation of the sector. Apart from some surveillance by the Ministry of Commerce, the parties have been left to form and maintain satisfactory sectoral arrangements, with all parties being free to appeal to the courts and/or the Commerce Commission; some large industrial consumers are connected directly to the national grid; local distribution is controlled by a relatively large number of local power companies under a variety of ownership structures. There are no guaranteed franchise areas, although there is not (yet) any significant competition in distribution; retailing is handled by companies who, while 'ring fenced', are very closely associated with the local distribution companies; retail competition is possible at all levels, but each local power company can set its own access conditions, and no competition has yet materialised at the domestic level; there is a non-compulsory, but widely supported, national market operated by the Electricity Market Company (EMCO) which operates a spot market, with full nodal spot pricing, and markets for trading financial contracts based on spot prices; there are several brokers, or buying groups, active in the wholesale market on behalf of groups of retailers; in the spot market, parties buy and sell power at their local connection nodes, and may form a variety of financial contracts, typically hedging against prices at the relevant island's reference node; and hedging between those reference nodes and local nodes is covered by financial contracts issued by Trans Power.
Generator offers, and load bids, are used to perform a day-ahead (indicative) market clearing to produce a preschedule and forecast prices. Offers and bids may be freely changed up to 4 hours before real time and the market is recleared on a regular basis. Real time dispatch must meet actual loads, but is determined, as far as possible, by resolution of the market clearing model using the latest generator offers. Final prices are determined ex post by resolution of the market clearing model to meet the actual metered load using the generator offers, and grid state, for the beginning of each half-hourly trading period. All market clearing is performed using a full nodal model, but with a DC power flow approximation which uses piecewise linear losses. Reserve is integrated into the market clearing process at all times, so that joint energy/reserve offers are used to form a joint energy/reserve schedule in a single LP (see Drayton and Read, 1996), with prices being produced for
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energy at every node, and for 2 classes of reserve in each island. The energy prices are used by EMCO as the basis for trading in the energy market, and for settlement of energy contracts. The reserve prices are used by the reserve manager in settling a variety of contracts with reserve providers.
Transmission pricing framework As noted previously, the task force was concerned to balance the gains which might be made from greater competition in the sector against the efficiency losses which might be incurred by breaking up ECNZ. It was considered highly desirable, though, that transmission should be separated away from generation, so as to provide a more credible 'open access regime' for third parties, who were already legally entitled to enter at that time. It was recognised that, although this was expected to improve long term dynamic (investment) efficiency, it would almost inevitably lead to some loss in the (productive) efficiency of short term coordination. Turner (1989) contains 5 papers summarising an investigation, conducted in association with Arthur Young, which set out to design, from first principles, a transmission pricing regime which would allow the formation of a separate transmission utility without compromising the efficiency of existing dispatch arrangements while, preferably, providing improved incentives for the optimal operation and development of the transmission grid itself. According to Read and Sell (1988), the key issues were: • • • • • •
efficient utilisation of existing assets; financing and planning expansion; price signals for new users; equity between users; asset valuation; and recovery of overheads.
Read and Maxwell (1989) state that "the primary objective...was...economic efficiency, with considerations of equity and cost recovery secondary. The strategy was to develop a theoretical understanding, then decide the extent to which it could be made practical" (p. 3). These priorities were determined by the priorities of economic restructuring at that time, and were directly reflected in the way in which the study was conducted, and the shape of the final conclusions. Specifically, it was concluded that, although there was no perfect solution: • the first goal, efficient utilisation of existing assets, should be the prime focus of short run electricity pricing, and that this could be best achieved by adopting the nodal pricing framework then being advocated by Schweppe et al. (1988), but supplemented by a system of 'line shareholdings' (or
'capacity rights') similar to those later advocated by Hogan (1990) (see Read and Sell, 1988); the second 2 goals, financing and planning expansion, and price signals for new users, could best be achieved by adopting a policy that expansion should occur if, and only if, there was a group of participants ready to pay for it, with transmission hedges being issued to those financing expansion (see Read, 1988); the remaining goals, equity between users, asset valuation (for existing assets) and recovery of overheads (including sunk costs of existing assets), were clearly important, if not critical, preconditions to gaining political acceptance for any practical proposal. Still, they were considered to be matters of lesser analytical interest, with the one major proviso being that any charges levied to recover such costs should be 'fixed' in the sense that it should not depend on any present, or future, actions of the parties involved (see Read, 1988). This basic structure, and philosophy, has guided the formation of transmission pricing policy to the present day, although with significant modifications in some areas. Rather than discuss the rationale behind the original proposals here, it seems more appropriate to do so in the context of a discussion of later developments in each of the 3 areas.
Short term signalling Rationale
At a first order level of analysis, the rationale for using SRMC based spot prices seems clear, in that there is no other set of prices which could be consistent with an optimal dispatch, and so achieve the first goal of efficient utilisation of existing resources. It was recognised that second order effects could arise where a particular market participant accounted for a sufficiently large proportion of the 'usage' in some part of the network that its behaviour impacted significantly on loss and/or constraint differentials in that region. On the other hand it was suggested that, in a small isolated system, this distortion was relatively minor compared with the distortions which might arise from 'gaming' on the reference energy price (see Scott and Read, 1996), while Read (1988) showed that these effects could be greatly reduced if users held line 'shareholdings' approximately corresponding to their expected 'usage'. These were later termed 'capacity rights', and were conceptually very similar to those proposed independently by Hogan
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Transmission pricing in New Zealand (1990), except that they included compensation for loss rentals, and were to be defined on a line-by-line basis. Experience Since the original report, based on the MIT analysis, there have been significant theoretical and practical developments in nodal pricing. Ring and Read (1995) and Hogan et al. (1996) describe the generalisation of Hogan's earlier work into a Dispatch Based Pricing framework, and the implementation of that theory in a nodal pricing model for Trans Power. If desired, that model can produce nodal prices for voltage, as well as for active and reactive power, and also for other commodities such as reserve, when appropriate constraints are included. It was used, for some years, to produce nodal prices based on actual AC power flows, but these prices did not account for constraint effects, and were averaged over a year. A market based on full nodal AC pricing is still under consideration but, since October 1996, a market has been operated using a DC flow approximation with piecewise linear losses. That model produces prices for approximately 600 nodes in the physical network, and active power prices are published for some 150 points at which power is bought and sold. Those prices take account of line limits and (a piecewise linear approximation to) losses, along with reserve constraints, and fairly general security constraints, if required. The particular piecewise linear DC approximation employed has some limitations, but this regime is fairly close to the ideal recommended by many advocates of nodal spot pricing. Theoretically, it differs from the 'dispatch based pricing' approach advocated by Ring and Read in that prices are driven by the constraints which are binding in a rerun of the primal dispatch model, rather than by those which were identified as physically binding during the dispatch period. In practice, though, the parameter values are adjusted so as to approximate the dispatch based approach. Perhaps surprisingly, this nodal pricing system has been politically acceptable, because, at least in some quarters, it is seen as being 'simple and transparent'. Most participants need only be concerned about prices at their own local nodes and, although prices are derived from a relatively complex model, there is little extra complexity in extracting the prices as well as the quantities from that model, and this provides an exact, and auditable, match between the prices and the dispatch. This perception is not universal, however, and the regime has its critics, particularly among direct consumers, who are now exposed to much greater local price volatility than previously, and remote consumers who experience higher prices. Trans Power does offer some internodal price hedging instruments, though, to protect users against undue volatility in nodal prices. This market is
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still in its infancy, and it remains to be seen which type of instrument will prove most effective in providing the kind of protection required by users, at a reasonable cost.
Long term signalling Rationale Read (1988) showed, though, that SRMC based prices would not, and could not be expected to, recover more than about 30% of the cost of new or existing lines. This conclusion was based on an analysis of the optimality conditions for line expansion, assuming significant scale economies in line construction. It was not based on the belief that the existing system had significant excess capacity, either because such capacity was required to meet contingency requirements not covered by the nodal energy spot prices, or because it had been 'over built', relative to the true requirements. Nor was it based on the observation that spot price differentials would fall as soon as a new line was built, and might stay low for many years. These effects are all relevant, though, and studies suggested that a realistic recovery for the existing system would probably be no more than 10%, especially when it is recognised that in many situations generators can, and should, adjust output so as to (just) avoid forcing lines into constraint. Naturally, this conclusion also implies that charging SRMC prices alone will not give the correct incentives for expansion in either the generation or transmission systems. A major expansion of the interisland HVDC link at that time made this clear. Without the expansion, the existing link would have been operating at capacity most of the time, and projected SRMC price differentials made it clear that such an expansion was warranted. But who would invest in such an expansion, knowing that the differentials, and hence rents, would immediately fall and that, if the expansion was optimally planned, the NPV of future rents would only equal the marginal cost of link capacity at the time of expansion, falling significantly below the full cost of such a project? It was concluded that the proper signals could only be given in an environment where expansions were not financed on the basis of SRMC prices alone, but where this pricing was supplemented by the requirement that users who expected to benefit from an expansion were expected to enter into a 'take-or-pay' contract to cover the 'fixed cost component' of the project, ie the projected NPV rental shortfall. Note that, in this environment, SRMC prices do 'give the correct signals and incentives' for expansion, but only indirectly. Expansion should occur when the difference between prices projected with, and without, the expansion equal the 'fixed cost component'. In principle, there should be a coalition of parties prepared
Transmission pricing in New Zealand to pay for expansion at this point. In practice, identifying, forming and disciplining such a coalition may be a formidable task. Not all (possible future) beneficiaries can be identified, particularly in a meshed network where the 'benefits' of an expansion may be widely dispersed. All have incentives to stay out of the coalition, but then 'use' the line later, paying SRMC charges alone. Although it was shown that, if the 'shareholdings' discussed above were assigned to those investing in expansion, the rentals would protect the holders from any erosion of their position wrt transmission costs/rentals due to variations in the behaviour of other parties, this was recognised as giving insufficient protection against the impact which such later entrants might have on the competitive position of shareholders in the energy market ~. Similar problems occur in other markets, and patent or copyright periods are often used to ensure adequate incentives for those contributing the cost of developing a new product. An analogous 'exclusive access' period was proposed, but was never made operational, partly because of the problems of defining line 'usage' by any particular party. On the other hand, it was shown that second order effects could significantly magnify the incentives for those parties who benefited from network expansion, with an equal and opposite impact in the form of incentives for other parties to oppose the expansion, and may be able to maintain disequilibrium between regional energy markets by doing so. It was concluded that an expansion project should proceed if, and only if, a coalition was prepared to pay for it. It was suggested that this would provide a realistic discipline on regional energy price differentials, while avoiding the twin problems of overexpansion by a transmission utility which was able to pass costs on to captive users, or underexpansion by a transmission utility which was able to exert market power by delaying expansion to force rents up. Still, it was recognised that the transmission authority itself might have to take an active role in establishing coalitions, and/or partially financing at least some expansions, on behalf of dispersed stakeholders, particularly where the expansion was considered necessary for general network security reasons, for example. Experience Despite the unresolved tensions in the above proposals, it was felt that a basic framework had been established which at least made those tensions clear, and within which they could be resolved. This regime has now been in place for some years during which time it has been applied to a number of projects. A major expansion of the interisland HVDC link was completed just as the policy was implemented, leading to debate as to whether it should be treated as a new investment, or included under the historical cost recovery regime. Since that time the
cost has been shared, in accord with the principles of that policy, between the 2 groups principally benefiting from the expansion, South Island generators and North Island consumers, although Trans Power (1996) now proposes to change that arrangement. The policy itself is generally accepted in the industry, though, and, according to Trans Power (1996), no fundamental change (is) proposed. However, that document does herald the formalisation of the way in which Trans Power expects to conduct itself with regard to those cases in which it perceives the necessity to undertake investments for the 'common good'. In particular, it now intends that the cost of such investments should be recovered by way of additions to the 'transport' and 'access' charges by which sunk costs are currently recovered, as discussed below. Historical cost recovery
Rationale The lack of emphasis on historical cost recovery in the initial framework may seem naive, but needs to be considered against a specific social and organisational background. First, all assets in the sector were, at that time, owned by central government (generation and transmission) or local (distribution). Thus, for example, a higher valuation of existing transmission assets involved, to a first order of approximation, the New Zealand populace, as electricity consumers, paying more to the New Zealand populace, as taxpayers. Second, under public ownership, there had been no formal regulation and, except for some very large users, no formal contracting, and price manipulation to achieve revenue or social goals had been common. For example, a previous government had increased wholesale electricity prices by 60% and then again by 40% in a single year, implying wealth transfers far greater than any anticipated in revaluation of transmission assets. Third, it was widely expected, at that time, that privatisation would involve large scale share giveaways to consumers, thus greatly reducing any potential wealth transfer effects. Finally, the equity debate was seen as very confused, and more suited to political resolution than to analysis. The one analytical conclusion which did seem clear was that, however these charges were to be allocated initially, that allocation should then remain fixed, most likely through some form of take-or-pay contract. It was argued that a regime based largely on long term contracts would have been the expected outcome if the sector had been developed in a fully commercial deregulated environment such as that planned under the new investment regime. But the major rationale for this approach was simply that, if the recovery of sunk costs were allowed to depend on the future generation or load of particular parties, those parties would have incentives
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Transmission pricing in New Zealand to distort their operational and investment decisions away from the optimal response to the short and long run pricing signals provided by the rest of the regime, towards solutions which provided a commercial advantage to themselves, but an overall loss to the sector as a whole. Given that the sunk cost recovery charges are much greater than the short run signals, any significant degree o f variability in the former could easily swamp the latter. In particular it would tend to give false signals that new generation capacity near loads was more economic than was, in fact, the case. Experience Although, this philosophy was accepted in principle, all attempts to apply it have been controversial. Analytically, the argument is solely about the form o f the cost recovery charge; whether it should match the form o f the cost involved, which is now fixed and unchangeable, or whether it should be allowed to vary in proportion to some measure o f 'usage', and hence give signals to reduce that usage. It is not, or should not be, about: • who should pay for transmission costs incurred as a result of 'transporting energy' on an already existing network, or o f any future actions by the parties, since all agree that those should be borne, in the first instance, by those who cause the cost to be incurred; • who should pay the costs o f 'stranded transmission assets' which appear, in retrospect, to have been surplus to requirements at the time o f the transition, since those have supposedly been dealt with by revaluing the network using an 'optimised deprival value' methodology, and provision has also been made for regular reviews, using that methodology, and for specific writedowns where economic bypass options become apparent in future; • the ultimate allocation o f costs between generators and consumers since, in the long run, the former will not, and should not, enter the market until the latter are prepared to pay the full cost o f entry, either directly or indirectly; • the allocation o f cost recovery charges between consumers, because allocation on a uniform per capita basis would have been quite acceptable from a theoretical perspective; and • the overall level o f cost recovery, either, since a cost recovery charge o f zero is a particularly good example o f a 'fixed charge '2. In reality, there has been strong pressure in favour o f a greater degree o f variability, particularly from local power companies which naturally wish to avoid charges, if possible, and are keen to encourage new local generation options. Unfortunately, the debate has been particularly confused, with little apparent understanding o f such basic analytic concepts as fixed and variable
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costs, and certainly no consensus emerging on the analytics. Arguments which have been used to support a greater reliance on variable charging include: • a desire to reduce the overall level of the government's cost recovery via Trans Power; • a desire to strengthen signals for conservation, by raising delivered energy charges above marginal costs; • conflicting desires to have charges allocated more directly to users via the retailers, rather than distributors, or to have them allocated to the generators; • a desire to increase 'competition' by boosting the number of new entrants into generation; • a belief that, in a competitive environment, local power companies are too unsure o f their customer base to be able to enter into such long term contracts; • a desire that the electricity sector be 'more commercial' in its arrangements, and a belief that this implies the need for a high reliance on variable charges for cost recovery; • the realisation that poor customers, in particular, are unwilling to accept any significant fixed charge component at the retail level; • a perception that it would be 'unfair' for customers to pay for lines built to serve them, but which they subsequently decide not to utilise fully; • an apparently widespread misunderstanding that these charges were, or should be, in themselves, designed to provide 'locational signals'; and (perhaps) • the more sophisticated notion that a centralised plan to establish a level playing field for competition could, in itself, be regarded as reducing competition in the 'market' for institutional structures. There is not space, here, to go into these arguments in any detail. All have some degree o f validity, although some are of, at best, dubious relevance. For example, by making it more difficult to deal with distant suppliers, variable charges will undoubtedly encourage more local suppliers, but it is debateable whether this really increases 'competition' in any useful sense, or just reinforces local monopolies. How many would accept the analogous argument that higher marginal road user or telecommunication charges, by making it more difficult to deal with distant suppliers, will increase the overall level o f 'competition' in the economy because they encourage more local firms? More fundamentally, the debate appears to have obscured, or ignored, the critical fact that this is simply not a normal commercial situation in at least 4 major respects: • first, although Trans Power is required to act, in most respects, as a normal commercial enterprise, it has been retained in public ownership precisely because it was believed that there were aspects of the situation which required consideration o f factors other than
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those which might be taken into account by a normal commercial operator in such an unregulated monopoly role; • second, Trans Power (1993) list specific goals including provision of a transmission system which promotes efficient use of resources within the electricity industry, and facilitation of competitive forces in the electricity industry so that all existing and potential customers have open access to the transmission system, subject only to physical and economic constraints. Thus the argument should be about provision of a 'level playing field' for competition in the generation and retailing sectors, not, as some appear to believe, about competition in the transmission sector; • third, the 'normal commercial arrangements' required to resolve these problems in other sectors would most likely not be any form of 'variable' charging, but by vertical integration via outright ownership, the ultimate form of 'fixed charging'. Other, perhaps less 'normal', vertical integration mechanisms have only been proposed here because of the 'common use' nature of the network, and the desire to create a uniform access regime at this level; • finally, the situation is abnormal, in that Trans Power has inherited a network which was constructed without any clear agreement as to who was to pay for it. Such a situation would not have occurred under a normal, unregulated, commercial development, and, given that it is illegal for Trans Power to use its monopoly power to impose a solution, there is no reason to suppose that mutually acceptable commercial outcomes can be reached while simultaneously meeting Trans Power's stated goals. Although compromises must obviously be made, it is still the author's view that efficiency will generally be enhanced if price structures are allowed to reflect the underlying cost structures of the sector, that one should be very cautious about distorting transmission pricing for other reasons, and that the impediments to practical implementation are actually much lower than has often been suggested. Realistically, given that it has already committed its capacity to the market, and that the government is sensitive to lobbying and unwilling to legislate, Trans Power has not been in a position to insist on the kind of long term contracting arrangements which a fully commercial independent transmission utility might require before entering, and has been forced to compromise significantly. Until recently, it operated a 'rolling average' regime under which: • local connection costs, which were clearly attributable to a user, were paid for by that user, either a generator or consumer/distributor; • each year, a simplistic load flow was used to trace nett flows back through the network, from each delivery
point and for a large number (25%) of 'peak' hours, to determine the proportion of each line's capacity 'used' to serve that point, and hence the cost which could be attributed to that point via locational 'network' charges; • each year, an allocation of non-locational 'capacity' and 'demand' charges was determined on the basis of extreme peak load requirements; • the actual charge in each year was then based on the average of these cost allocations over the preceding 10 years; and • charges were capped for some small and remote users for whom these calculations implied extreme price levels. This regime, which was effectively about halfway between a purely fixed and purely variable charge, was maintained for a number of years. But, as might be expected, it was challenged by many parties as being either too fixed, or too variable, while its 'backward looking' philosophy was considered inappropriate for the new commercial environment. Thus Trans Power (1996) describes a new regime under which there are 3 categories of charges for cost recovery: • connection charges for services "which provide a user with physical connection to the grid through user specific assets". These are much as before, but now include 'deeper' connection charges for generators; • access charges for services "whereby the interconnection of generators and consumers creates the potential to reduce the costs of reserves, frequency and voltage support, black start capability and fault level". These are similar to the previous demand charges, and are based on the highest anytime peak demand during the contract term; and • transport charges for services "which allow geographically separated generators and consumers to trade electrical energy" These are similar to the old 'network' charges, and are calculated using a similar cost allocation methodology. However, South Island generators are now being asked to cover the full cost of HVDC link ($81 m pa), apparently on the grounds that they are now deemed to be the sole beneficiaries. As noted earlier, there is now provision to recover the cost of future investment undertaken by Trans Power for the 'common good', under this category. In principle, these changes were not intended to represent a fundamental departure from the earlier philosophy, and a distinction was made between 'future avoidable' and 'unavoidable (including sunk) costs', with it being noted that "The way in which unavoidable costs are passed on should not distort investment signals...(and that) if (they) could be avoided, then new generation would not be built in order of least cost, but according to how much of the fixed charge can be avoided." On the other hand, the real
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effect depends crucially on the actual form of the charges, and on the assignment of costs to the particular charging categories. According to Trans Power (1996), $87 m pa is expected from connection charges, and $427 m from access and transport charges combined. This compares with around $26 m for dispatch and ancillary services, and only $20 m from spot rentals, in the previous year. However the latter result was achieved under an earlier spot pricing regime which only recognised losses, plus the HVDC capacity limit. Extrapolating data from the first 7 months of the new market suggests annual spot rentals of around $64 m. Still it is clear that the historic cost recovery regime dominates transmission pricing. With regard to the form of charges, the major change is that, rather than face rolling average charges, users are now to pay for access and transport charges on the basis of negotiated 1-5 year contracts for blocks of delivered capacity, and may either agree to an 'incremental reset' option to cope with growing demand, or face penalty charges if they actually use more than the contracted amount. In principle, this seems desirable, in that it moves the sector closer to a normal commercial situation, and provides better alignment between the new investment and historical cost recovery regimes. At this stage, though, there is some debate as to whether the penalty charges are being set high enough to achieve the stated goal of discouraging avoidance. The assignment of a greater proportion of the costs to generators is also significant in this respect because they can only recover those costs, if at all, by raising energy prices, which are variable.
Key issues It should be clear, from the above, that considerable attention was paid to economic efficiency objectives, at least initially. Perhaps too little has been paid to the requirement for simplicity and transparency, but the primary difficulty has been in the area of political implementability. At an early stage, both government and the industry adopted the position that it should be possible, and was highly desirable, for the industry to sort out its own structures, including a transmission pricing regime, on a commercial basis, and without any government interference or regulation. This was driven in part by a very 'pure' economic philosophy, in the spirit of the very broad market oriented reforms then sweeping the country, partly by the realisation that the direct costs of maintaining an explicit regulatory structure for such a small country would be proportionately large, and partly by the fear of inefficiency due to 'creeping regulation' in the longer term. These were, and are, very real considerations, and by and large, the original goals have
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now been achieved. It should also be said, though, that it has not been easy to reach agreement, or implement, such reforms in the absence of any regulatory authority to oversee the reform process, to arbitrate, or to make agreements binding on the large number of parties involved. With regard to transmission pricing, the lack of such an authority has made it very difficult to structure any debate, and almost certainly added to the general level of confusion by allowing all parties to advance arguments, and lobby, with no real requirement to reconcile their assertions with basic theory, or come to grips with opposing positions. On the other hand, it should be recognised that the transmission pricing proposals advanced in 1989 were quite different from anything which the local industry had been familiar with, and had very limited international precedents at that time. Many parties tended to look to US practice, for example, without too much critical assessment. More active involvement by Government, or the creation of a regulatory authority, would not, of itself, have instantly increased the general level of expertise in the industry, and may well have lead to more decisive, but not necessarily better advised, decision making. With regard to particular issues, the form of charges to recover historic costs, while of limited theoretical interest, has been by far the most controversial. This is not surprising, given the relative magnitude of these charges, which imply the potential for significant distortions to economic efficiency, but also very significant gains or losses to particular parties. Our experience suggests that this issue has the potential to derail the whole reform process and, if not handled well, to significantly diminish any potential gains by distorting locational signals for investment, and that the outcome will be determined at least as much by politics as by economics. It is probably not appropriate, here, to speculate as to the motivations of particular parties in this case. Naturally, most advanced arguments which aligned strongly with their commercial interests. Domestic consumers, on the other hand, supported, or at least acquiesced in, arguments which economic analysis might have suggested were against their apparent economic interests given that, as taxpayers, they might be thought to hold a beneficial interest in the companies still owned by the central government, and none in the newly privatised local power companies. This is probably a reflection on their recent historical experience of retail tariffs based almost exclusively on c/kwh charges, and a strong tradition of supporting their local power companies in disputes with central government. The author has acted individually or in association with Arthur Young, Ernst and Young Management Sciences, CORE Management Systems and Putnam Hayes and Bartlett, as a
Transmission pricing in New Zealand consultant for Trans Power New Zealand, the Electricity Corporation of New Zealand, and the Electricity Market Company on various aspects of the material covered here. The views expressed here, though, are attributable to the author alone, and should not be interpreted as representing the position of any other party. tTheoretically, this weakness can be overcome by using long term energy contracts but, in practice, consumers are not ready to have the bulk of their requirements met under such contracts, partly because they, too, would expect to benefit from the later entry of lower priced 'free riders'. 2Indeed, it would probably be optimal, if not for the fact that it implies the need to raise taxes and hence distort the economy elsewhere, and that it may discriminate unacceptably between incumbents and new entrants. References Culy, J. G., Read, E. G. and Wright, B. (1996) Structure and regulation of the New Zealand electricity sector. In International Comparison of Electricity Regulation, eds R. Gilbert and E. Kahn, pp. 312-365. Cambridge University Press. Drayton, G. R. and Read, E. G. (1996) Using LP to form a market for spinning reserve. Proceedings of the Operational Research Society of New Zealand, Christchurch, New Zealand, pp. 119-124. Hogan, W. W. (1990) Contract networks for electricity power transmission. Harvard University, Energy and Environmental Policy Centre Discussion Paper E-90-17. Hogan, W. W., Ring, B. J. and Read, E. G. (1996) Using
mathematical programming for electricity spot pricing.
International Transactions in Operations Research 3(3-4), 243-253. Read, E. G. (1988) Pricing and operation of transmission services: long run aspects. Report to Trans Power, reprinted in Principles for Pricing Electricity Transmission, ed. A. Turner. Read, E. G. and Maxwell, N. (1989) A framework for transmission pricing. Arthur Young report to Trans Power, in Principles for Pricing Electricity Transmission, ed. A. Turner. Read, E. G. and Sell, D. P. M. (1988) Pricing and operation of transmission services: short run aspects. Arthur Young report to Trans Power, reprinted in Principles for Pricing Electricity Transmission, ed. A. Turner. Ring, B. J. and Read, E. G. (1995) A dispatch based pricing model for the New Zealand electricity market. In Transmission Pricing andAccess, eds R. Siddiqi and M. Einhorn, pp. 183-206. Kluwer, Boston. Schweppe, F. C., Caramanis, M. C., Tabors, R. D. and Bohn, R. E. (1988)Spot Pricing for Electricity. Kluwer, Boston. Scott, T. J. and Read, E. G. (1996) Modelling hydro reservoir operation in a deregulated electricity sector. International Transactions in Operations Research 3(3-4), 209-221. Trans Power (1993)Annual Report. Trans Power, Wellington, New Zealand. Trans Power (1996) Pricing for Transmission Services: Intro-
duction to the Pricing Methodology to be Applied from 1 October 1996. Trans Power, Wellington, New Zealand. Turner, A. J. (1989) Principles for Pricing Electricity Transmission. Trans Power, Wellington, New Zealand.
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© 1997 ElsevierScience Ltd. All rights reserved Printed in Great Britain 0957-1787/97 $17.00+0.00
Transmission pricing in New Zealand E. G. Read
Although the pace o f reform has been variable, New Zealand was among the first countries to attempt development, from first principles, o f a comprehensive framework for transmission pricing. That framework consisted o f nodal spot pricing to provide signals for short term efficiency, a market approach to new investment, and a 'fixed charge' approach to historical cost recovery. We discuss the motivations behind that regime, and the compromises that have been made in order to achieve a politically and commercially acceptable outcome. © 1997 Elsevier Science Ltd. All rights reserved. Keywords:Electricity;Transmission;Pricing Introduction Transmission pricing has attracted considerable international attention, and some controversy, as new electricity market forms are developed around the world. A variety of 'solutions' has emerged in international practice, but it seems fair to say that none is universally regarded as ideal. After a brief introduction to the New Zealand electricity sector, this paper summarises the transmission pricing approach adopted there. It also comments on the motivation behind, and performance of, this approach with reference to the 6 key criteria suggested by the transmission working group of EMF 15, namely that transmission prices should: 1. promote the efficient day-to-day operation of the bulk power market; 2. signal locational advantages for investment in generation and demand; 3. signal the need for investment in the transmission system; 4. compensate the owners of existing transmission assets; 5. be simple and transparent; and 6. be politically implementable. * This author is with the Energy Modelling Research Group, Department of Management, University of Canterbury, Christchurch, New Zealand.
The New Zealand electricity sector
The electricity system The New Zealand electricity system is discussed by Culy et al. (1996), from which this summary is drawn. It consists of 2 AC subsystems, for the North and South Islands, connected by a 1200 MW submarine HVDC link. The South Island system is entirely hydro, with moderate sized reservoirs allowing storage of spring/ summer flows to meet winter peaks, but relatively small interannual carryover. On average, this meets South Island requirements and allows export to the North, where there is a mixed hydro/thermal system. On average, 75% of requirements are met from hydro, 7% from geothermal, and the remainder from a variety of thermal plant, mainly burning gas. From a transmission point of view, it is worth noting that the network is relatively sparse, covering an area the size of the UK, but serving only 3.5 m people, with an annual load of around 30,000 GWh. As a result, transmission accounts for a relatively large proportion of the cost of delivered energy, especially because the major hydro resources are in the south of the South Island, while the population is concentrated in the north of the North Island. This also means that the backbone of the network is basically linear, although there are some significant loops in the North Island. On the other hand, 'the national grid', having been constructed to deliver power to a large number of small local distribution companies, has a relatively high number of nodes, when all transformers etc are included. In such a small system, spinning reserve is also a major issue, particularly because it is necessary to guard against the failure of at least 1 of the 2 HVDC poles. On occasion, this criterion has required that the receiving Island hold more generation capacity on spinning reserve duty than on generation duty.
The reform process The history and structure of the New Zealand electricity sector are discussed by Culy et al. (1996). Historically, generation and transmission were the responsibility of a 227
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single Government Department, while local distribution and retailing were the responsibility of a large number of locally elected 'Electricity Supply Authorities (ESAs)'. Since 1984 there has been a series of reforms. Generation and transmission were deregulated first but, given the surpluses at that time, there was no significant entry. Major changes started with the corporatisation of the government's generation assets into a state-owned enterprise (SOE) known as the Electricity Corporation of New Zealand (ECNZ) with the transmission assets in a subsidiary, Trans Power. SOEs are expected to operate in a fully commercial way, and ECNZ made considerable progress in terms of reducing electricity prices while substantially increasing retums to its owner, the Government. A pseudo market was also established in which ECNZ announced SRMC based spot prices, and issued contracts in the form of hedges against those prices. However this was never intended to be the end point of the process, and a task force was set up in 1988 to investigate further options in terms of developing market structures, breaking up ECNZ, and privatising where possible. The major problem facing the task force was to balance the further gains which might be made from greater competition in the sector against the efficiency losses which might be incurred by breaking up ECNZ. Breakup decisions were deferred, to be studied again by the Wholesale Electricity Market Study (1992), and the Wholesale Electricity Market Development Group (1994), with the current structure being derived from the recommendations of the latter. It was decided, though, that Trans Power should become a fully independent SOE, a goal achieved in 1992. In the meantime, a parallel process had deregulated the distribution/retail sector, and allowed local power companies to be established under a variety of ownership arrangements, ranging from sale to independent investors, through share giveaways and ownership by community trusts, to continuation of local body ownership. Finally, after 10 years of debate, a partial breakup of ECNZ was implemented in early 1996, with new market structures becoming fully operational in October 1996. Current organisation
Apart from the continued entry of new generators, the amalgamation of existing local power companies, and the long term possibility of further breakup or selldown of state assets, there are no plans to change the current structure of the sector, which is: • a single state-owned utility, Trans Power, is responsible for transmission and grid operation, including purchase of ancillary services, although it does not have a statutory monopoly; • there are 2 major generating companies, both still state-owned and owning a spatially dispersed set of 228
•
• •
•
•
•
• •
•
hydro and thermal plant, plus a growing fringe of smaller competitors; there is no explicit regulation of the sector. Apart from some surveillance by the Ministry of Commerce, the parties have been left to form and maintain satisfactory sectoral arrangements, with all parties being free to appeal to the courts and/or the Commerce Commission; some large industrial consumers are connected directly to the national grid; local distribution is controlled by a relatively large number of local power companies under a variety of ownership structures. There are no guaranteed franchise areas, although there is not (yet) any significant competition in distribution; retailing is handled by companies who, while 'ring fenced', are very closely associated with the local distribution companies; retail competition is possible at all levels, but each local power company can set its own access conditions, and no competition has yet materialised at the domestic level; there is a non-compulsory, but widely supported, national market operated by the Electricity Market Company (EMCO) which operates a spot market, with full nodal spot pricing, and markets for trading financial contracts based on spot prices; there are several brokers, or buying groups, active in the wholesale market on behalf of groups of retailers; in the spot market, parties buy and sell power at their local connection nodes, and may form a variety of financial contracts, typically hedging against prices at the relevant island's reference node; and hedging between those reference nodes and local nodes is covered by financial contracts issued by Trans Power.
Generator offers, and load bids, are used to perform a day-ahead (indicative) market clearing to produce a preschedule and forecast prices. Offers and bids may be freely changed up to 4 hours before real time and the market is recleared on a regular basis. Real time dispatch must meet actual loads, but is determined, as far as possible, by resolution of the market clearing model using the latest generator offers. Final prices are determined ex post by resolution of the market clearing model to meet the actual metered load using the generator offers, and grid state, for the beginning of each half-hourly trading period. All market clearing is performed using a full nodal model, but with a DC power flow approximation which uses piecewise linear losses. Reserve is integrated into the market clearing process at all times, so that joint energy/reserve offers are used to form a joint energy/reserve schedule in a single LP (see Drayton and Read, 1996), with prices being produced for
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energy at every node, and for 2 classes of reserve in each island. The energy prices are used by EMCO as the basis for trading in the energy market, and for settlement of energy contracts. The reserve prices are used by the reserve manager in settling a variety of contracts with reserve providers.
Transmission pricing framework As noted previously, the task force was concerned to balance the gains which might be made from greater competition in the sector against the efficiency losses which might be incurred by breaking up ECNZ. It was considered highly desirable, though, that transmission should be separated away from generation, so as to provide a more credible 'open access regime' for third parties, who were already legally entitled to enter at that time. It was recognised that, although this was expected to improve long term dynamic (investment) efficiency, it would almost inevitably lead to some loss in the (productive) efficiency of short term coordination. Turner (1989) contains 5 papers summarising an investigation, conducted in association with Arthur Young, which set out to design, from first principles, a transmission pricing regime which would allow the formation of a separate transmission utility without compromising the efficiency of existing dispatch arrangements while, preferably, providing improved incentives for the optimal operation and development of the transmission grid itself. According to Read and Sell (1988), the key issues were: • • • • • •
efficient utilisation of existing assets; financing and planning expansion; price signals for new users; equity between users; asset valuation; and recovery of overheads.
Read and Maxwell (1989) state that "the primary objective...was...economic efficiency, with considerations of equity and cost recovery secondary. The strategy was to develop a theoretical understanding, then decide the extent to which it could be made practical" (p. 3). These priorities were determined by the priorities of economic restructuring at that time, and were directly reflected in the way in which the study was conducted, and the shape of the final conclusions. Specifically, it was concluded that, although there was no perfect solution: • the first goal, efficient utilisation of existing assets, should be the prime focus of short run electricity pricing, and that this could be best achieved by adopting the nodal pricing framework then being advocated by Schweppe et al. (1988), but supplemented by a system of 'line shareholdings' (or
'capacity rights') similar to those later advocated by Hogan (1990) (see Read and Sell, 1988); the second 2 goals, financing and planning expansion, and price signals for new users, could best be achieved by adopting a policy that expansion should occur if, and only if, there was a group of participants ready to pay for it, with transmission hedges being issued to those financing expansion (see Read, 1988); the remaining goals, equity between users, asset valuation (for existing assets) and recovery of overheads (including sunk costs of existing assets), were clearly important, if not critical, preconditions to gaining political acceptance for any practical proposal. Still, they were considered to be matters of lesser analytical interest, with the one major proviso being that any charges levied to recover such costs should be 'fixed' in the sense that it should not depend on any present, or future, actions of the parties involved (see Read, 1988). This basic structure, and philosophy, has guided the formation of transmission pricing policy to the present day, although with significant modifications in some areas. Rather than discuss the rationale behind the original proposals here, it seems more appropriate to do so in the context of a discussion of later developments in each of the 3 areas.
Short term signalling Rationale
At a first order level of analysis, the rationale for using SRMC based spot prices seems clear, in that there is no other set of prices which could be consistent with an optimal dispatch, and so achieve the first goal of efficient utilisation of existing resources. It was recognised that second order effects could arise where a particular market participant accounted for a sufficiently large proportion of the 'usage' in some part of the network that its behaviour impacted significantly on loss and/or constraint differentials in that region. On the other hand it was suggested that, in a small isolated system, this distortion was relatively minor compared with the distortions which might arise from 'gaming' on the reference energy price (see Scott and Read, 1996), while Read (1988) showed that these effects could be greatly reduced if users held line 'shareholdings' approximately corresponding to their expected 'usage'. These were later termed 'capacity rights', and were conceptually very similar to those proposed independently by Hogan
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Transmission pricing in New Zealand (1990), except that they included compensation for loss rentals, and were to be defined on a line-by-line basis. Experience Since the original report, based on the MIT analysis, there have been significant theoretical and practical developments in nodal pricing. Ring and Read (1995) and Hogan et al. (1996) describe the generalisation of Hogan's earlier work into a Dispatch Based Pricing framework, and the implementation of that theory in a nodal pricing model for Trans Power. If desired, that model can produce nodal prices for voltage, as well as for active and reactive power, and also for other commodities such as reserve, when appropriate constraints are included. It was used, for some years, to produce nodal prices based on actual AC power flows, but these prices did not account for constraint effects, and were averaged over a year. A market based on full nodal AC pricing is still under consideration but, since October 1996, a market has been operated using a DC flow approximation with piecewise linear losses. That model produces prices for approximately 600 nodes in the physical network, and active power prices are published for some 150 points at which power is bought and sold. Those prices take account of line limits and (a piecewise linear approximation to) losses, along with reserve constraints, and fairly general security constraints, if required. The particular piecewise linear DC approximation employed has some limitations, but this regime is fairly close to the ideal recommended by many advocates of nodal spot pricing. Theoretically, it differs from the 'dispatch based pricing' approach advocated by Ring and Read in that prices are driven by the constraints which are binding in a rerun of the primal dispatch model, rather than by those which were identified as physically binding during the dispatch period. In practice, though, the parameter values are adjusted so as to approximate the dispatch based approach. Perhaps surprisingly, this nodal pricing system has been politically acceptable, because, at least in some quarters, it is seen as being 'simple and transparent'. Most participants need only be concerned about prices at their own local nodes and, although prices are derived from a relatively complex model, there is little extra complexity in extracting the prices as well as the quantities from that model, and this provides an exact, and auditable, match between the prices and the dispatch. This perception is not universal, however, and the regime has its critics, particularly among direct consumers, who are now exposed to much greater local price volatility than previously, and remote consumers who experience higher prices. Trans Power does offer some internodal price hedging instruments, though, to protect users against undue volatility in nodal prices. This market is
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still in its infancy, and it remains to be seen which type of instrument will prove most effective in providing the kind of protection required by users, at a reasonable cost.
Long term signalling Rationale Read (1988) showed, though, that SRMC based prices would not, and could not be expected to, recover more than about 30% of the cost of new or existing lines. This conclusion was based on an analysis of the optimality conditions for line expansion, assuming significant scale economies in line construction. It was not based on the belief that the existing system had significant excess capacity, either because such capacity was required to meet contingency requirements not covered by the nodal energy spot prices, or because it had been 'over built', relative to the true requirements. Nor was it based on the observation that spot price differentials would fall as soon as a new line was built, and might stay low for many years. These effects are all relevant, though, and studies suggested that a realistic recovery for the existing system would probably be no more than 10%, especially when it is recognised that in many situations generators can, and should, adjust output so as to (just) avoid forcing lines into constraint. Naturally, this conclusion also implies that charging SRMC prices alone will not give the correct incentives for expansion in either the generation or transmission systems. A major expansion of the interisland HVDC link at that time made this clear. Without the expansion, the existing link would have been operating at capacity most of the time, and projected SRMC price differentials made it clear that such an expansion was warranted. But who would invest in such an expansion, knowing that the differentials, and hence rents, would immediately fall and that, if the expansion was optimally planned, the NPV of future rents would only equal the marginal cost of link capacity at the time of expansion, falling significantly below the full cost of such a project? It was concluded that the proper signals could only be given in an environment where expansions were not financed on the basis of SRMC prices alone, but where this pricing was supplemented by the requirement that users who expected to benefit from an expansion were expected to enter into a 'take-or-pay' contract to cover the 'fixed cost component' of the project, ie the projected NPV rental shortfall. Note that, in this environment, SRMC prices do 'give the correct signals and incentives' for expansion, but only indirectly. Expansion should occur when the difference between prices projected with, and without, the expansion equal the 'fixed cost component'. In principle, there should be a coalition of parties prepared
Transmission pricing in New Zealand to pay for expansion at this point. In practice, identifying, forming and disciplining such a coalition may be a formidable task. Not all (possible future) beneficiaries can be identified, particularly in a meshed network where the 'benefits' of an expansion may be widely dispersed. All have incentives to stay out of the coalition, but then 'use' the line later, paying SRMC charges alone. Although it was shown that, if the 'shareholdings' discussed above were assigned to those investing in expansion, the rentals would protect the holders from any erosion of their position wrt transmission costs/rentals due to variations in the behaviour of other parties, this was recognised as giving insufficient protection against the impact which such later entrants might have on the competitive position of shareholders in the energy market ~. Similar problems occur in other markets, and patent or copyright periods are often used to ensure adequate incentives for those contributing the cost of developing a new product. An analogous 'exclusive access' period was proposed, but was never made operational, partly because of the problems of defining line 'usage' by any particular party. On the other hand, it was shown that second order effects could significantly magnify the incentives for those parties who benefited from network expansion, with an equal and opposite impact in the form of incentives for other parties to oppose the expansion, and may be able to maintain disequilibrium between regional energy markets by doing so. It was concluded that an expansion project should proceed if, and only if, a coalition was prepared to pay for it. It was suggested that this would provide a realistic discipline on regional energy price differentials, while avoiding the twin problems of overexpansion by a transmission utility which was able to pass costs on to captive users, or underexpansion by a transmission utility which was able to exert market power by delaying expansion to force rents up. Still, it was recognised that the transmission authority itself might have to take an active role in establishing coalitions, and/or partially financing at least some expansions, on behalf of dispersed stakeholders, particularly where the expansion was considered necessary for general network security reasons, for example. Experience Despite the unresolved tensions in the above proposals, it was felt that a basic framework had been established which at least made those tensions clear, and within which they could be resolved. This regime has now been in place for some years during which time it has been applied to a number of projects. A major expansion of the interisland HVDC link was completed just as the policy was implemented, leading to debate as to whether it should be treated as a new investment, or included under the historical cost recovery regime. Since that time the
cost has been shared, in accord with the principles of that policy, between the 2 groups principally benefiting from the expansion, South Island generators and North Island consumers, although Trans Power (1996) now proposes to change that arrangement. The policy itself is generally accepted in the industry, though, and, according to Trans Power (1996), no fundamental change (is) proposed. However, that document does herald the formalisation of the way in which Trans Power expects to conduct itself with regard to those cases in which it perceives the necessity to undertake investments for the 'common good'. In particular, it now intends that the cost of such investments should be recovered by way of additions to the 'transport' and 'access' charges by which sunk costs are currently recovered, as discussed below. Historical cost recovery
Rationale The lack of emphasis on historical cost recovery in the initial framework may seem naive, but needs to be considered against a specific social and organisational background. First, all assets in the sector were, at that time, owned by central government (generation and transmission) or local (distribution). Thus, for example, a higher valuation of existing transmission assets involved, to a first order of approximation, the New Zealand populace, as electricity consumers, paying more to the New Zealand populace, as taxpayers. Second, under public ownership, there had been no formal regulation and, except for some very large users, no formal contracting, and price manipulation to achieve revenue or social goals had been common. For example, a previous government had increased wholesale electricity prices by 60% and then again by 40% in a single year, implying wealth transfers far greater than any anticipated in revaluation of transmission assets. Third, it was widely expected, at that time, that privatisation would involve large scale share giveaways to consumers, thus greatly reducing any potential wealth transfer effects. Finally, the equity debate was seen as very confused, and more suited to political resolution than to analysis. The one analytical conclusion which did seem clear was that, however these charges were to be allocated initially, that allocation should then remain fixed, most likely through some form of take-or-pay contract. It was argued that a regime based largely on long term contracts would have been the expected outcome if the sector had been developed in a fully commercial deregulated environment such as that planned under the new investment regime. But the major rationale for this approach was simply that, if the recovery of sunk costs were allowed to depend on the future generation or load of particular parties, those parties would have incentives
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Transmission pricing in New Zealand to distort their operational and investment decisions away from the optimal response to the short and long run pricing signals provided by the rest of the regime, towards solutions which provided a commercial advantage to themselves, but an overall loss to the sector as a whole. Given that the sunk cost recovery charges are much greater than the short run signals, any significant degree o f variability in the former could easily swamp the latter. In particular it would tend to give false signals that new generation capacity near loads was more economic than was, in fact, the case. Experience Although, this philosophy was accepted in principle, all attempts to apply it have been controversial. Analytically, the argument is solely about the form o f the cost recovery charge; whether it should match the form o f the cost involved, which is now fixed and unchangeable, or whether it should be allowed to vary in proportion to some measure o f 'usage', and hence give signals to reduce that usage. It is not, or should not be, about: • who should pay for transmission costs incurred as a result of 'transporting energy' on an already existing network, or o f any future actions by the parties, since all agree that those should be borne, in the first instance, by those who cause the cost to be incurred; • who should pay the costs o f 'stranded transmission assets' which appear, in retrospect, to have been surplus to requirements at the time o f the transition, since those have supposedly been dealt with by revaluing the network using an 'optimised deprival value' methodology, and provision has also been made for regular reviews, using that methodology, and for specific writedowns where economic bypass options become apparent in future; • the ultimate allocation o f costs between generators and consumers since, in the long run, the former will not, and should not, enter the market until the latter are prepared to pay the full cost o f entry, either directly or indirectly; • the allocation o f cost recovery charges between consumers, because allocation on a uniform per capita basis would have been quite acceptable from a theoretical perspective; and • the overall level o f cost recovery, either, since a cost recovery charge o f zero is a particularly good example o f a 'fixed charge '2. In reality, there has been strong pressure in favour o f a greater degree o f variability, particularly from local power companies which naturally wish to avoid charges, if possible, and are keen to encourage new local generation options. Unfortunately, the debate has been particularly confused, with little apparent understanding o f such basic analytic concepts as fixed and variable
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costs, and certainly no consensus emerging on the analytics. Arguments which have been used to support a greater reliance on variable charging include: • a desire to reduce the overall level of the government's cost recovery via Trans Power; • a desire to strengthen signals for conservation, by raising delivered energy charges above marginal costs; • conflicting desires to have charges allocated more directly to users via the retailers, rather than distributors, or to have them allocated to the generators; • a desire to increase 'competition' by boosting the number of new entrants into generation; • a belief that, in a competitive environment, local power companies are too unsure o f their customer base to be able to enter into such long term contracts; • a desire that the electricity sector be 'more commercial' in its arrangements, and a belief that this implies the need for a high reliance on variable charges for cost recovery; • the realisation that poor customers, in particular, are unwilling to accept any significant fixed charge component at the retail level; • a perception that it would be 'unfair' for customers to pay for lines built to serve them, but which they subsequently decide not to utilise fully; • an apparently widespread misunderstanding that these charges were, or should be, in themselves, designed to provide 'locational signals'; and (perhaps) • the more sophisticated notion that a centralised plan to establish a level playing field for competition could, in itself, be regarded as reducing competition in the 'market' for institutional structures. There is not space, here, to go into these arguments in any detail. All have some degree o f validity, although some are of, at best, dubious relevance. For example, by making it more difficult to deal with distant suppliers, variable charges will undoubtedly encourage more local suppliers, but it is debateable whether this really increases 'competition' in any useful sense, or just reinforces local monopolies. How many would accept the analogous argument that higher marginal road user or telecommunication charges, by making it more difficult to deal with distant suppliers, will increase the overall level o f 'competition' in the economy because they encourage more local firms? More fundamentally, the debate appears to have obscured, or ignored, the critical fact that this is simply not a normal commercial situation in at least 4 major respects: • first, although Trans Power is required to act, in most respects, as a normal commercial enterprise, it has been retained in public ownership precisely because it was believed that there were aspects of the situation which required consideration o f factors other than
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those which might be taken into account by a normal commercial operator in such an unregulated monopoly role; • second, Trans Power (1993) list specific goals including provision of a transmission system which promotes efficient use of resources within the electricity industry, and facilitation of competitive forces in the electricity industry so that all existing and potential customers have open access to the transmission system, subject only to physical and economic constraints. Thus the argument should be about provision of a 'level playing field' for competition in the generation and retailing sectors, not, as some appear to believe, about competition in the transmission sector; • third, the 'normal commercial arrangements' required to resolve these problems in other sectors would most likely not be any form of 'variable' charging, but by vertical integration via outright ownership, the ultimate form of 'fixed charging'. Other, perhaps less 'normal', vertical integration mechanisms have only been proposed here because of the 'common use' nature of the network, and the desire to create a uniform access regime at this level; • finally, the situation is abnormal, in that Trans Power has inherited a network which was constructed without any clear agreement as to who was to pay for it. Such a situation would not have occurred under a normal, unregulated, commercial development, and, given that it is illegal for Trans Power to use its monopoly power to impose a solution, there is no reason to suppose that mutually acceptable commercial outcomes can be reached while simultaneously meeting Trans Power's stated goals. Although compromises must obviously be made, it is still the author's view that efficiency will generally be enhanced if price structures are allowed to reflect the underlying cost structures of the sector, that one should be very cautious about distorting transmission pricing for other reasons, and that the impediments to practical implementation are actually much lower than has often been suggested. Realistically, given that it has already committed its capacity to the market, and that the government is sensitive to lobbying and unwilling to legislate, Trans Power has not been in a position to insist on the kind of long term contracting arrangements which a fully commercial independent transmission utility might require before entering, and has been forced to compromise significantly. Until recently, it operated a 'rolling average' regime under which: • local connection costs, which were clearly attributable to a user, were paid for by that user, either a generator or consumer/distributor; • each year, a simplistic load flow was used to trace nett flows back through the network, from each delivery
point and for a large number (25%) of 'peak' hours, to determine the proportion of each line's capacity 'used' to serve that point, and hence the cost which could be attributed to that point via locational 'network' charges; • each year, an allocation of non-locational 'capacity' and 'demand' charges was determined on the basis of extreme peak load requirements; • the actual charge in each year was then based on the average of these cost allocations over the preceding 10 years; and • charges were capped for some small and remote users for whom these calculations implied extreme price levels. This regime, which was effectively about halfway between a purely fixed and purely variable charge, was maintained for a number of years. But, as might be expected, it was challenged by many parties as being either too fixed, or too variable, while its 'backward looking' philosophy was considered inappropriate for the new commercial environment. Thus Trans Power (1996) describes a new regime under which there are 3 categories of charges for cost recovery: • connection charges for services "which provide a user with physical connection to the grid through user specific assets". These are much as before, but now include 'deeper' connection charges for generators; • access charges for services "whereby the interconnection of generators and consumers creates the potential to reduce the costs of reserves, frequency and voltage support, black start capability and fault level". These are similar to the previous demand charges, and are based on the highest anytime peak demand during the contract term; and • transport charges for services "which allow geographically separated generators and consumers to trade electrical energy" These are similar to the old 'network' charges, and are calculated using a similar cost allocation methodology. However, South Island generators are now being asked to cover the full cost of HVDC link ($81 m pa), apparently on the grounds that they are now deemed to be the sole beneficiaries. As noted earlier, there is now provision to recover the cost of future investment undertaken by Trans Power for the 'common good', under this category. In principle, these changes were not intended to represent a fundamental departure from the earlier philosophy, and a distinction was made between 'future avoidable' and 'unavoidable (including sunk) costs', with it being noted that "The way in which unavoidable costs are passed on should not distort investment signals...(and that) if (they) could be avoided, then new generation would not be built in order of least cost, but according to how much of the fixed charge can be avoided." On the other hand, the real
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effect depends crucially on the actual form of the charges, and on the assignment of costs to the particular charging categories. According to Trans Power (1996), $87 m pa is expected from connection charges, and $427 m from access and transport charges combined. This compares with around $26 m for dispatch and ancillary services, and only $20 m from spot rentals, in the previous year. However the latter result was achieved under an earlier spot pricing regime which only recognised losses, plus the HVDC capacity limit. Extrapolating data from the first 7 months of the new market suggests annual spot rentals of around $64 m. Still it is clear that the historic cost recovery regime dominates transmission pricing. With regard to the form of charges, the major change is that, rather than face rolling average charges, users are now to pay for access and transport charges on the basis of negotiated 1-5 year contracts for blocks of delivered capacity, and may either agree to an 'incremental reset' option to cope with growing demand, or face penalty charges if they actually use more than the contracted amount. In principle, this seems desirable, in that it moves the sector closer to a normal commercial situation, and provides better alignment between the new investment and historical cost recovery regimes. At this stage, though, there is some debate as to whether the penalty charges are being set high enough to achieve the stated goal of discouraging avoidance. The assignment of a greater proportion of the costs to generators is also significant in this respect because they can only recover those costs, if at all, by raising energy prices, which are variable.
Key issues It should be clear, from the above, that considerable attention was paid to economic efficiency objectives, at least initially. Perhaps too little has been paid to the requirement for simplicity and transparency, but the primary difficulty has been in the area of political implementability. At an early stage, both government and the industry adopted the position that it should be possible, and was highly desirable, for the industry to sort out its own structures, including a transmission pricing regime, on a commercial basis, and without any government interference or regulation. This was driven in part by a very 'pure' economic philosophy, in the spirit of the very broad market oriented reforms then sweeping the country, partly by the realisation that the direct costs of maintaining an explicit regulatory structure for such a small country would be proportionately large, and partly by the fear of inefficiency due to 'creeping regulation' in the longer term. These were, and are, very real considerations, and by and large, the original goals have
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now been achieved. It should also be said, though, that it has not been easy to reach agreement, or implement, such reforms in the absence of any regulatory authority to oversee the reform process, to arbitrate, or to make agreements binding on the large number of parties involved. With regard to transmission pricing, the lack of such an authority has made it very difficult to structure any debate, and almost certainly added to the general level of confusion by allowing all parties to advance arguments, and lobby, with no real requirement to reconcile their assertions with basic theory, or come to grips with opposing positions. On the other hand, it should be recognised that the transmission pricing proposals advanced in 1989 were quite different from anything which the local industry had been familiar with, and had very limited international precedents at that time. Many parties tended to look to US practice, for example, without too much critical assessment. More active involvement by Government, or the creation of a regulatory authority, would not, of itself, have instantly increased the general level of expertise in the industry, and may well have lead to more decisive, but not necessarily better advised, decision making. With regard to particular issues, the form of charges to recover historic costs, while of limited theoretical interest, has been by far the most controversial. This is not surprising, given the relative magnitude of these charges, which imply the potential for significant distortions to economic efficiency, but also very significant gains or losses to particular parties. Our experience suggests that this issue has the potential to derail the whole reform process and, if not handled well, to significantly diminish any potential gains by distorting locational signals for investment, and that the outcome will be determined at least as much by politics as by economics. It is probably not appropriate, here, to speculate as to the motivations of particular parties in this case. Naturally, most advanced arguments which aligned strongly with their commercial interests. Domestic consumers, on the other hand, supported, or at least acquiesced in, arguments which economic analysis might have suggested were against their apparent economic interests given that, as taxpayers, they might be thought to hold a beneficial interest in the companies still owned by the central government, and none in the newly privatised local power companies. This is probably a reflection on their recent historical experience of retail tariffs based almost exclusively on c/kwh charges, and a strong tradition of supporting their local power companies in disputes with central government. The author has acted individually or in association with Arthur Young, Ernst and Young Management Sciences, CORE Management Systems and Putnam Hayes and Bartlett, as a
Transmission pricing in New Zealand consultant for Trans Power New Zealand, the Electricity Corporation of New Zealand, and the Electricity Market Company on various aspects of the material covered here. The views expressed here, though, are attributable to the author alone, and should not be interpreted as representing the position of any other party. tTheoretically, this weakness can be overcome by using long term energy contracts but, in practice, consumers are not ready to have the bulk of their requirements met under such contracts, partly because they, too, would expect to benefit from the later entry of lower priced 'free riders'. 2Indeed, it would probably be optimal, if not for the fact that it implies the need to raise taxes and hence distort the economy elsewhere, and that it may discriminate unacceptably between incumbents and new entrants. References Culy, J. G., Read, E. G. and Wright, B. (1996) Structure and regulation of the New Zealand electricity sector. In International Comparison of Electricity Regulation, eds R. Gilbert and E. Kahn, pp. 312-365. Cambridge University Press. Drayton, G. R. and Read, E. G. (1996) Using LP to form a market for spinning reserve. Proceedings of the Operational Research Society of New Zealand, Christchurch, New Zealand, pp. 119-124. Hogan, W. W. (1990) Contract networks for electricity power transmission. Harvard University, Energy and Environmental Policy Centre Discussion Paper E-90-17. Hogan, W. W., Ring, B. J. and Read, E. G. (1996) Using
mathematical programming for electricity spot pricing.
International Transactions in Operations Research 3(3-4), 243-253. Read, E. G. (1988) Pricing and operation of transmission services: long run aspects. Report to Trans Power, reprinted in Principles for Pricing Electricity Transmission, ed. A. Turner. Read, E. G. and Maxwell, N. (1989) A framework for transmission pricing. Arthur Young report to Trans Power, in Principles for Pricing Electricity Transmission, ed. A. Turner. Read, E. G. and Sell, D. P. M. (1988) Pricing and operation of transmission services: short run aspects. Arthur Young report to Trans Power, reprinted in Principles for Pricing Electricity Transmission, ed. A. Turner. Ring, B. J. and Read, E. G. (1995) A dispatch based pricing model for the New Zealand electricity market. In Transmission Pricing andAccess, eds R. Siddiqi and M. Einhorn, pp. 183-206. Kluwer, Boston. Schweppe, F. C., Caramanis, M. C., Tabors, R. D. and Bohn, R. E. (1988)Spot Pricing for Electricity. Kluwer, Boston. Scott, T. J. and Read, E. G. (1996) Modelling hydro reservoir operation in a deregulated electricity sector. International Transactions in Operations Research 3(3-4), 209-221. Trans Power (1993)Annual Report. Trans Power, Wellington, New Zealand. Trans Power (1996) Pricing for Transmission Services: Intro-
duction to the Pricing Methodology to be Applied from 1 October 1996. Trans Power, Wellington, New Zealand. Turner, A. J. (1989) Principles for Pricing Electricity Transmission. Trans Power, Wellington, New Zealand.
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