HVDC Sunk Cost Recovery. Pricing Methodology

Transcription

1 HVDC Sunk Cost Recovery Pricing Methodology 19 April 1999 EXECUTIVE SUMMARY 2 1 INTRODUCTION 3 2 ECONOMIC EFFICIENCY CRITERIA Unavoidable Fixed Non-distortionary Subsidy free Price stability Economic value Summary 9 3 POSSIBLE ALLOCATIONS Allocating to generators Allocating to offtake Comparison of alternative allocations 13 4 ALTERNATIVE VIEWS AND SUBSIDIARY CRITERIA Equity Linking sunk cost recovery to nodal prices Connection or network asset? 17 5 CONCLUSIONS 16 This document is prepared solely for the purposes of information. It does not (nor is it intended to) constitute an offer or invitation to contract with Transpower. No liability or responsibility for accuracy or completeness of this document is accepted by Transpower. Transpower reserves the right to alter the contents of this document and will not be bound in any way until all formal definitive contracts are entered into. Pricing Group, Transpower New Zealand Ltd, PO Box 1021, Wellington, New Zealand

2 19 APRIL 1999 HVDC SUNK COST RECOVERY PAGE 2 of 18 EXECUTIVE SUMMARY This paper outlines the rationale for Transpower s methodology of recovering all HVDC sunk costs from South Island generators. This is a pricing allocation methodology. The separate but related issue of the determination of the level of sunk costs to be recovered is an issue of valuation and revenue requirement, and is not discussed here. A separate report on the Optimised Deprival Value of Transpower s Fixed Assets is produced annually. The issues relevant to HVDC sunk cost recovery are complex. A fuller summary than this is provided in the paper s conclusions on page 16, and table 1 on page 12 provides a summary comparison of alternative allocations. In a contractual environment, HVDC sunk costs cannot in practice be recovered from parties that do not benefit from it, and so must be allocated to customers that benefit from it, being: South Island generators, who through the HVDC link enjoy both a higher clearing price, usually set by North Island stations, and increased production; and North Island offtake, who obtain a clearing price lower than it would be if the North Island grid was not connected to the South Island grid. For sunk cost allocation, it is the long term benefit that is relevant: the occasional small benefits of the HVDC link to North Island generators and South Island offtake are far outweighed by the longer term disadvantages to them: lower average prices and decreased production for the former, and higher average prices for the latter. Transpower is required by its SCI, and through it the Government s statement pursuant to section 26 of the Commerce Act, to recover its sunk costs in an economically efficient manner. To achieve this, sunk costs charges should be fixed. This minimises any opportunities for the charge to be variablised (i.e. passed to consumers as a c/kwh rate), which if it occurred would create incentives for customers to change behaviour on account of sunk costs, and so create economic distortions. Charging the HVDC sunk costs to South Island generators prevents variablisation. This is because, with competition, it does not change their incentives to offer generation at their short-run marginal cost (SRMC), and so acts as a fixed charge. Nor, being a fixed charge, does it change their SRMCs. Economic value analysis shows that, being low-srmc hydro stations enjoying higher prices and increased production, the South Island generators surplus is significantly greater than the HVDC sunk cost. The only alternative, of charging North Island offtake, would be likely to lead to variablisation through retailers, who can be expected to recover their costs as c/kwh charges to consumers, or through variablised line charges. As well as being economically inefficient, charging North Island offtake would increase prices to North Island consumers by about 0.4 c/kwh. There have been a number of alternative allocation methodologies proposed, based not on economic efficiency criteria, but rather on alternative views or subsidiary criteria. For example: charging a proportion to each of South Island generators and North Island offtake could only be justified on perceived equity rather than economic efficiency grounds; and Transpower trading off rental rights against sunk cost charges (as currently done with Contact Energy) is economically inefficient and commercially risky. C:\Documents\Homework\ OCTOBER\HVDC-SCR-19APR99.DOC

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4 19 April 1999 HVDC Sunk Cost Recovery Page 4 of 18 1 INTRODUCTION This paper 1 outlines the rationale for Transpower s methodology of recovering all HVDC sunk costs from South Island generators. HVDC sunk costs are determined using the ODV methodology 2. Those costs are first allocated to customer groups (in this case, South Island generators), then to individual customers within each group. The first allocation, to customer groups, is the focus of this paper. Transpower s allocation to customers within a group is in proportion to a measure of each customer s peak capacity requirement: this second allocation is only discussed here where it is relevant to the rationale for the first. HVDC maintenance and operating costs are currently allocated in the same way as the sunk costs (they are relatively small, around 10% of the total). 2 ECONOMIC EFFICIENCY CRITERIA As a state owned enterprise, Transpower has a Statement of Corporate Intent (SCI) agreed with the shareholder. The principal objective of Transpower as a State Owned Enterprise is to operate as a successful business. To this end Transpower is to be as profitable and efficient as comparable businesses that are not owned by the Crown. To achieve this, Transpower must recover the sunk costs of its transmission assets. The SCI stipulates also that Transpower s revenue will be recovered from its customers having regard to the principles outlined in the Government s statement pursuant to section 26 of the Commerce Act 3. The section 26 statement requires that the sunk costs of the transmission grid should be allocated in a way that minimises distortions in investment decision making by grid users, in other words in a manner that promotes dynamic efficiency. The Grid Services Working Group 4 concluded also that, as a key transmission pricing principle, the facilitation of economic efficiency, and especially of dynamic efficiency, is of prime importance. 2.1 Unavoidable For economic efficiency, sunk costs should be allocated in a manner that does not distort new investment decision making: future actions should be unaffected by the recovery of sunk costs, because they have no effect on those sunk costs. The economically most efficient sunk cost allocation methodology is to recover the full sunk costs over the lifetime of the assets through fixed 5 and unavoidable (i.e. mandatory) charges to incumbents This version of the paper supersedes the previous versions of 8 December 1998 and 17 March The ODV methodology is outlined in the Ministry of Commerce s Handbook for the Optimised Deprival Valuation of Transpower, 7 July See also Transpower s annual Report of the Optimised Deprival Valuation of Transpower s Fixed Assets. The applicable section 26 statement is Statement to the Commerce Commission of the Economic Policy of the Government: Electricity Transmission, issued pursuant to Section 26 of the Commerce Act 1986 by Philip Burden, Minister of Commerce, 20 December The Ministry of Commerce has suggested revising the section 26 statement, but the only suggested revision to the statement on economic efficiency is to reinforce the concept of short-run marginal cost pricing. See Francis M, Ministry of Commerce, Letter to Ross C, Transpower, 17 March The Grid Services Working Group (GSWG) was convened by Transpower in 1995 to recommend an appropriate long-term pricing regime for the services provided by its transmission assets, consistent with the New Zealand wholesale electricity market development. The GSWG included representatives from a cross-section of the industry, participating as individuals, and an independent chairman. See the Report of the Grid Services Working Group, submitted to Trans Power New Zealand Limited 30 May Fixed charges in this context means that the level of the charges is not dependent on the actions of the customer charged. The fixed charge might vary over time in a defined manner, perhaps linked to measures that the customer does not control, such as transmission asset ODV or CPI. C:\Documents\Homework\ OCTOBER\HVDC-SCR-19APR99.DOC

5 19 April 1999 HVDC Sunk Cost Recovery Page 5 of 18 New investments (or other actions) by incumbents would not change their charge, and new entrants would not be charged. In New Zealand s deregulated electricity sector, characterised by commercial contractual relationships, it is not realistic to expect all relevant incumbents to commit contractually to paying long term fixed charges for the recovery of the sunk costs of transmission assets. Rather, if a customer has a long term change in its demand for transmission services, then its charges need to be adjusted to reflect it. This approach is in any case explicitly required by the section 26 statement 6. Given that the charges cannot be fixed over the long term, charging incumbents only rather than also new entrants would be inefficient. There would be perverse incentives on incumbents to claim capacity increases as new investment to avoid charges, while enjoying the reduced charges inherent in any capacity decreases, or to shift capacity to new entrants. This would create commercial transaction costs and lead to under-recovery of sunk costs. Although not an issue of economic efficiency, there would also be equity issues raised, with new entrants and game-playing incumbents being seen to free-ride the transmission system. In summary it is most economically efficient to charge only incumbents rather than also new entrants the sunk costs, fixed and unavoidable for the duration of the asset life. However, regulation to enforce this is not considered realistic in New Zealand, nor is it considered realistic to expect all relevant incumbents to commit contractually to it. The possibility of sunk cost recovery through fixed charges that are truly unavoidable is therefore dismissed. 2.2 Fixed For the reasons outlined above, in New Zealand s deregulated electricity sector, sunk cost charges cannot be fixed over the long term. Nevertheless, the more fixed the charges are, the greater the degree of economic efficiency. Sunk cost charges should therefore be fixed over as long a time frame as is possible in a contractual environment. Then - at least over that timeframe - the allocation of sunk costs does not change behaviour. As noted above, if a customer has a long term change in its demand for transmission services, then its charges need to be adjusted to reflect it. Over the long term, if a customer ceases to demand transmission services, its charges have to stop. Conversely, a new entrant demanding transmission services needs to be charged. Similarly, if a customer s demand for transmission services halves or doubles then, over the long term, its charge has to halve or double. In practice, therefore, sunk costs need to be allocated according to a measure of each customer s demand for transmission services. Some form of charging rate is therefore required, and the issue becomes what measure of customer demand should be used as the denominator to this rate. The two potential measures of customer demand are by peak capacity (kw) 7 and by use (kwh). Given that charges cannot be fixed over the long term, economic efficiency is maximised by a measure that is as fixed as possible over the short to medium term. A peak capacity measure is less variable than is a use measure. For generators, it reflects their actual capacity, unless they only ever inject at a lower level. For offtake customers, it reflects their requirement at peak demand, and is insensitive to customer behaviour at all other times. A use measure, on the other hand, variablises sunk costs as a c/kwh charge, giving customers an incentive to alter their behaviour in the short and medium term on account of sunk costs, or to pass 6 7 The section 26 statement notes that assets may become redundant where grid users capacity requirements are permanently reduced, in which the redundant assets are to be written down under the ODV methodology, and the level of Transpower s charge to recover sunk costs should be correspondingly reduced. There are of course various ways in which peak capacity could be measured. Transpower uses measures of the form average of the x highest injection/offtakes in the last y months, to reflect observed capacity requirements. Y is set at at least twelve to net off seasonal effects, which do not affect long term requirements for transmission assets. Capacity measures that do not reflect annual peak capacity, such as average observed capacity requirements over a period, or peak capacities over short terms, are effectively a by use measure.

6 19 April 1999 HVDC Sunk Cost Recovery Page 6 of 18 those charges on to end consumers, with a similarly inefficient outcome. Thus, charging for sunk cost recovery by peak capacity is more economically efficient than charging by use. A peak capacity-based measure is also more reflective of the connection and interconnection service that Transpower provides than is a use-based measure: it is peak capacity requirements that drive transmission asset requirements. However, this is a supporting equity reason rather than a primary economic efficiency reason for it. 2.3 Non-distortionary The section 26 statement requires recognition in transmission pricing that the sunk costs of the transmission grid should be allocated in a way that minimises distortions in investment decision making by grid users. The variable costs of transmission are accurately reflected in the marginal loss and constraint components of the nodal prices, at every node on the grid, for every half hour 8. Thus (once connection costs have been netted off 9 ), they provide the correct timing and locations signals for new investment, whether in generation, offtake or demand side management (or, indeed, in transmission assets). The section 26 statement requires explicitly that variable transmission prices to grid users should reflect variable costs incurred in the transmission of electricity (including costs that arise when parts of the transmission grid are constrained), thus providing incentives to minimise those costs. The allocation of HVDC sunk costs therefore needs to minimise distortion of the nodal pricing signals, whether that distortion is to the nodal prices themselves (e.g. by affecting generators offer behaviour), or due to additional timing or locational signals generated through some other mechanism (e.g. by introducing an inter-island charge differential). 2.4 Subsidy free Another test that an economically efficient sunk cost allocation methodology should pass is that of no cross-subsidy. The accepted test for cross-subsidies is that no service or set of services should be charged more than the stand alone cost of the service, or less than the incremental cost 10. The formula for the calculation of the HVDC sunk cost recovery charge is: Total HVDC charge = ODV WACC + Costs where: ODV = the minimum of the HVDC s ODRC 11 and economic value WACC = the weighted average cost of capital agreed with the shareholder through the SCI Nodal prices as currently determined are not perfect, in that they do not allow for reactive power effects and can be incorrect when there is a significant quantity of negative offers (due to technical limitations in the DC economic dispatch model SPD ). The issue is that correcting these relatively small distortions should be done through development of nodal pricing, rather than through other mechanisms such as sunk cost recovery. See also section The cost of connection to the national grid presents a valid locational signal to invest close to the grid. For this reason connection costs can be netted out of consideration of economically efficient HVDC sunk cost allocation. See for example Baumol and Sidak, Transmission Pricing and Stranded Costs in the Electric Power Industry, page 52. Their conclusions have been supported in the New Zealand legal context by Kerrin Vautier (see letter Transpower and Cross-Subsidisation of 2 April 1998). Optimised depreciated replacement cost, which as defined by the ODV methodology cannot exceed the stand-alone cost. See the annual Transpower valuation report and Handbook for Optimised Deprival Valuation of Trans Power, Ministry of Commerce, 7 July 1994.

7 19 April 1999 HVDC Sunk Cost Recovery Page 7 of 18 Costs = the HVDC maintenance and operating costs and overheads

8 19 April 1999 HVDC Sunk Cost Recovery Page 8 of 18 The stand-alone cost of an asset is the cost that would be incurred by an efficient entrant to produce the same level of service. Determining the HVDC sunk cost using the ODV methodology ensures that the sunk cost charged is no greater than the ODRC, which reflects the capital component of the standalone cost. Transpower adds to the HVDC sunk cost the direct HVDC maintenance and operating costs. These are relatively small, are largely tendered out, and Transpower has economies of scale in transmission asset ownership that a new entrant would find difficult to match. This ensures that the total HVDC sunk cost charged is no greater than its stand-alone cost. As this total charge is then allocated on a per peak capacity basis between customers, no customer or group of customers is charged more than the stand alone cost of the HVDC service. The incremental cost of the HVDC is the decrease in Transpower s cost that would ensue if the HVDC were removed from service. As the capital component is sunk, this would simply be the direct HVDC maintenance and operating costs, which are only some 10% of the HVDC sunk costs. As the total charge is allocated on a per peak capacity basis between customers, no customer or group of customers is charged less than the incremental cost of the HVDC service. Thus the ODV methodology, and allocation on a common basis to all customers in the charged group, ensures that cross-subsidies are not an issue with respect to the allocation of HVDC sunk costs. 2.5 Price stability The SCI requires that Transpower price its services having regard to price stability and predictability for its customers 12. From the customer s perspective, prices that are stable and predictable within a year, and from year to year, facilitate effective business planning, including of new investment. From Transpower s perspective such pricing is consistent with the long term nature of the transmission asset business. 2.6 Economic value It is clearly not practicable to charge customers more for a service than the value to them of that service: it would then not be economic for them to take the service. Thus, the allocation of HVDC sunk costs to customer groups is bounded by the economic value of the HVDC service to them. Supporting this, the SCI requires that Transpower price its services having regard to the benefits flowing to customers from those services. In the short term, the benefit of the HVDC link to different customer groups can vary by the half hour, as generator offers, demand and transmission outages change, and hence so to do HVDC flows and clearing prices. However, for the purposes of recovering sunk costs of transmission assets, which have lifetimes measured in decades, it is the net benefit to customer groups over such time scales - the medium to long term - that is relevant. Over the medium to long term, South Island generators and North Island offtake benefit considerably from the link. The South Island hydro generators are able to obtain the double benefit of increasing their production by exporting electricity to the North Island, and of a clearing price which is often set by a North Island thermal station. The North Island offtake are able to enjoy lower prices, as the import of hydro power from the South Island will allow the marginal North Island station to be further down the national merit order. 12 The HVDC sunk cost allocation methodology allocates the ODV of the HVDC. If the ODV changes, then prices will change with it. The section 26 statement notes that assets may become redundant where grid users capacity requirements are permanently reduced, in which the redundant assets are to be written down under the ODV methodology, and the level of Transpower s charge to recover sunk costs should be correspondingly reduced (as noted in footnote 6). For the purposes of a pricing methodology, therefore, the requirement for stable and predictable prices it taken to mean a stable and predictable pricing methodology. See also footnote 5. Price stability is not strictly an economic efficiency criteria, but as it is explicitly required by the SCI and has commercial advantages for both Transpower and customers, it is included in this section.

9 19 April 1999 HVDC Sunk Cost Recovery Page 9 of 18 Conversely the South Island offtake and North Island generators are, over the medium to long term, disadvantaged by the link. The South Island offtake have to accept the higher North Island-set prices, and the North Island generators have to produce less for a lower price 13. There are occasions, especially in dry years, when the HVDC flow is reversed and opposite benefits and costs accrue, but these are short and infrequent 14. Also, there are quality of supply issues that offset some costs. Nevertheless, over the medium to long term, the net benefit is clearly and unambiguously positive for the South Island generators and North Island offtake, and negative for the South Island offtake and North Island generators 15. For this reason, South Island offtake and North Island generators cannot be charged for the recovery of HVDC sunk costs, and the allocation must be to South Island generators and/or to North Island offtake. 2.7 Summary Transpower is required by its SCI and the Government s section 26 statement to recover its sunk costs in an economically efficient manner. Ideally, sunk cost recovery should be made unavoidable, but this is not possible in New Zealand s deregulated energy sector. The ODV methodology and the HVDC link s central place in Transpower s network ensure that HVDC sunk cost recovery is subsidy-free. Therefore, to achieve Transpower s objectives as specified by the shareholder, HVDC sunk costs should be allocated to meet the remaining economic efficiency criteria of: Fixed, for the maximum duration possible, to minimise opportunities for variablisation; Non-distortionary, to minimise distortion to nodal prices; Price stability and predictability in a year and between years; and Economic value, to avoid charges that exceed the economic value of the service to the customer charged for it The South Island offtake and North Island generators could be advantaged by the link over the medium to long term if they controlled access, so that the link could only be used when it was to their advantage. However, the link in common with all transmission assets is operated on an open access basis for overall national benefit. As the table below indicates, energy flow through the HVDC link is predominantly south to north. Even in 1992, which was the driest year since records began in 1931, only some 14% of the flow was southwards (and then of a low total flow). The HVDC therefore provides minimal quantity benefits over the medium to long term to North Island generators and South Island load. HVDC Use by energy flow in GWh, for calendar years Northwards 100.0% 97.3% 86.1% 99.5% 99.9% 99.8% 99.7% 97.4% 99.7% Southwards 0.0% 2.7% 13.9% 0.5% 0.1% 0.2% 0.3% 2.6% 0.3% 15 The 1998 Transpower valuation report includes a detailed economic analysis of the HVDC link, under a variety of scenarios. All these scenarios identify surpluses as gained by South Island generators and lost by North Island generators, and welfare effects as gains to North Island offtake and losses to South Island offtake. That analysis demonstrates further that even the net welfare gain of the HVDC link across all customer groups is greater than the ODRC of the link: in that analysis the surplus to South Island generators from higher South Island prices was netted off as a welfare transfer from South Island consumers. Thus, the economic value of the HVDC link to the South Island generators as a customer group is greater by that amount than the value indicated in the valuation report. This conclusion was also reached by Ernst and Young in 1996 (see footnote 27). The Government has confirmed the financial viability of Meridian (and the achievability of its separation from ECNZ) under, amongst other factors, the allocation of HVDC sunk costs to South Island generators. This indicates shareholder acceptance that the economic value of the HVDC link to Meridian exceeds its cost. Contact Energy s South Island stations have similar SRMC, LRAC and allocation and thus are similarly affected.

10 19 April 1999 HVDC Sunk Cost Recovery Page 10 of 18 3 POSSIBLE ALLOCATIONS This section weighs possible allocations of HVDC sunk cost recovery charges to customer groups against the economic efficiency criteria outlined in the preceding section. 3.1 Allocating to generators In a competitive environment, generators have the economic incentive to offer their power for dispatch at their SRMC 16. If they offer lower, they may be dispatched to run at a loss. If they offer higher, they may not be dispatched when it would be profitable for them to run, in the sense that they would cover their SRMC and contribute to paying LRAC 17. If, over the long run, the average clearing price that a generator obtains does not reach its LRAC, then it is running at a loss. However such a generator still has no incentive to increase its offer above its SRMC: to do so would simply risk missing some opportunities for running at a short term profit and chipping away at its long term loss. In the long term the generator may be forced to exit or re-value, but still without any incentive to change its offer behaviour in the interim. This accords with the fact that, by definition, marginal decisions are unaffected by fixed costs unless they induce exit. The only occasions when a generator has the economic incentive to bid other than its SRMC is when it has some confidence in being the marginal generator and hence setting a higher clearing price 18. South Island hydro generation capacities, South Island demand and the HVDC link capacity are such that no South Island generator can have this confidence when all assets are available. The HVDC link is usually unconstrained. When it is constrained it is because the South Island generators offered in at low enough prices to achieve maximum dispatch through the national merit order, in which case the South Island generators do not receive the North Island clearing price. Rather, they receive the price of the highest South Island offer that is dispatched. This would be lower than the North Island price, set by the highest-offering North Island generator that is dispatched. Generators whose LRAC is below the average clearing price will make a surplus, as illustrated in figure A: Figure A - Generators' surplus The market clearing price is set where the demand curve crosses the national merit order represented by the generator SRMC offers. Price Demand Clearing price LRAC SRMC Over the long run, the generators' surplus is the area (price times quantity) between their LRAC and the average clearing price. Generators' surplus Quantity For the reasons outlined in section 2.2, charges should be allocated by peak capacity (kw) rather than by use (kwh). Sunk costs allocated to generators by peak capacity will increase their LRAC but will Short run marginal cost, which for generators is the per kwh opportunity cost of fuel plus any variable operating costs. Long run average cost, which includes all other costs, such as the cost of capital. The marginal generator sets the clearing price. If there is a transmission constraint, then there will be more than one marginal generator.

11 19 April 1999 HVDC Sunk Cost Recovery Page 11 of 18 not affect their SRMC. As explained above, generators have the incentive to offer at their SRMC, whatever their LRAC. Thus, charging generators within the generators surplus would impact on their profitability, but would not affect their offer behaviour. Nodal prices would be unchanged, and generators would have no opportunity to variablise the charge as c/kwh and pass it on to consumers. The negative economic value of the HVDC link to the North Island generators over the medium to long term precludes charging them. The economic value of the HVDC link to South Island generators is bounded by the differences between the national clearing price with the link, and the lower South Island clearing price that would occur if there was no HVDC link, as well as by LRAC, as figure B illustrates: Figure B - EV of HVDC to SI generators The economic value (EV) of the HVDC link has a ceiling of the national clearing price and a floor of either what the South Island clearing price would be if there was no link, or the LRAC if higher. This illustration, with South Island (SI) generators on the left, reflects the current situation of SI generators that are all low-srmc, low-lrac hydro. The same effect would apply if there were other SI generation, such as thermal, although the illustration would be more complex. Price Demand National clearing price EV of HVDC link to SI gen Quantity LRAC SRMC SI clearing price if no HVDC link For these reasons (as comparison of figures A and B illustrates) the economic value of the HVDC link to the South Island generators is no greater than the amount that their economic surplus would be if they were not charged for it. Thus, South Island generators could be charged for the HVDC sunk costs up to this economic value. While charging HVDC sunk costs to South Island generators would not affect the nodal prices, such an allocation can send an additional and therefore distorting signal for those considering generation investment in the South Island to avoid the charge by investing in the North Island, when on nodal price signals alone the South Island would have been more economic. Any charging of HVDC sunk costs to the South Island generators has to satisfy not only collective economic value but also the economic value test for each customer. Currently, the individual allocation of total costs based on a measure of capacity requirement achieves this, because all the South Island generators are hydro with similar SRMCs and LRACs to each other. However, in the (albeit unlikely 19 ) case of a new investment in high LRAC South Island generation, such as a thermal plant, the individual allocation rule may need to be adjusted to ensure it does not exceed the economic value of the HVDC link to that customer. 19 Even if the HVDC link were not charged to South Island generators, new investment in South Island generation is considered unlikely. South Island demand is 12.2 TWh (estimate for the year ending March 1999) growing at an estimated less than 0.2 TWh per annum. South Island hydro generation capacity has historically averaged 18.0 TWh, a level that South Island demand will not reach for about thirty years. A one-in-twenty dry year has 85% of this, or 15.3 TWh, which demand will not reach for well over a decade. The driest year on record allowed 13.3 TWh of generation, well in excess of current demand. (Generation figures based on actual 1931 to 1989 inflows, adjusted for Clyde but not for the Manapouri upgrade.)

12 19 April 1999 HVDC Sunk Cost Recovery Page 12 of Allocating to offtake If offtake were charged, then the economic value limit would preclude charging South Island offtake, which over the medium to long term do not obtain a net benefit from the link. Costs would therefore have to be allocated to North Island offtake. Such an allocation would result in a price differential between the islands beyond that provided by the variable transmission (loss and constraint) components of the nodal prices: it would thus distort those price signals. This would send additional signals for more offtake to locate in the South Island, and for more North Island demand side management, than would be economic if the sunk costs were truly sunk. The North Island offtake grid users are mostly line businesses and/or retailers. There are a few directconnect major users, who could be included in either category for the purposes of pricing without affecting the conclusions of this section Allocating to North Island retailers If HVDC charges were allocated to North Island retailers, then they could be expected to variablise the charge by increasing their c/kwh price. National retailers may in addition be able to pass on costs to South Island as well as North Island endusers which (while it could alleviate some of the locational distortion) would contravene the economic efficiency criterion of economic value. An exception to the variablisation argument against charging North Island retailers is if HVDC charges were allocated only to incumbent North Island retailers. Then, competition from other retailers (or the threat of new entrant retailers) would prevent them from passing on the charge. They would have to absorb the cost of the charge, which would be economically efficient if they could not avoid the charge. However, unavoidable charges to incumbents only can be dismissed as impractical in New Zealand s deregulated electricity sector, for the reasons explained in section 2.1. The issue of providing a mechanism whereby retailers could pay charges direct to Transpower from 1 April 1999 was considered at length by Transpower. Customer feedback on a proposal of this nature indicated there was still some way to go in developing this and that there would be difficulties in putting it into place for 1 April On that basis Transpower determined that while consideration would continue, that product would not be available for 1 April Allocating the HVDC charge to North Island retailers would thus not in any case be an option until a satisfactory mechanism is developed Allocating to North Island line businesses Line businesses could claim that the medium to long term benefits of the HVDC link do not accrue to them, on the basis that its principal benefits are in terms of energy price, and hence accrue to energy traders (South Island generators and North Island retailers). Line businesses would need to pass on any sunk cost charges, either to local retailers, or to the end use customer. Passing costs to retailers would have the disadvantages outlined in the previous subsection, with the added distortion that not all line businesses can be expected to do this in the same manner. Some line business will not know their end use customers usage, in which case they could not variablise the charge in this way. However, where a line business did know their end use customers usage, they would be able to variablise the charge as a c/kwh rate. The economically most efficient sunk cost allocation methodology is through mandatory, fixed charges to incumbents. However, as discussed in section 2.1, this effectively requires regulation, which is not considered realistic in New Zealand s deregulated electricity sector. Line businesses are however one possible exception to this, as components of the electricity reforms include information disclosure and the threat of price control on the natural monopoly line businesses. A possibility is

13 19 April 1999 HVDC Sunk Cost Recovery Page 13 of 18 that price control regulation on line businesses could be introduced, that could implicitly prevent or hinder them passing on variablised transmission charges. Various models of rate-of-return based price control could achieve this, depending on their detailed design. However, the Government s intention is explicitly not to introduce such an approach, but instead to set performance thresholds for line businesses to identify poor performers for explicit price control 20. The proposed regime specifically nets transmission charges off the performance measures on line businesses. The regime is designed to be durable over the long term. Regulation that prevents or hinders line businesses from passing on the sunk costs of transmission assets is thus considered most unlikely in the foreseeable future. 3.3 Comparison of alternative allocations Allocating HVDC sunk costs to South Island offtake or North Island generators has been ruled out on an economic value basis. To determine how HVDC sunk costs should be allocated between South Island generators and North Island offtake, the alternatives need to be compared against the economic efficiency criteria of fixed, non-distortionary, price stability and economic value. While both alternatives would send locational signals that distort the correct signals inherent in nodal pricing, the former sends distorting signals to those considering new investment in South Island generation, while the latter sends distorting signals to those considering new investment in North Island offtake or demand side management. Given the current supply and demand configuration and demographic trends (including current and foreseeable oversupply in the South Island 21 ), the practical effect of the former is less significant, as commercial consideration of new investment in South Island generation is less credible than that in North Island offtake or demand side management. In other words, HVDC costs cannot be allocated nationally to a particular customer group, as the medium to long term benefits of the HVDC link to a particular customer group occur in only one island. Some locational, inter-island distortion of nodal prices is inevitable. The charge should be allocated where the resultant distortion is least harmful in practice, which is to South Island generators. Allocating sunk costs to North Island offtake allows those costs to be variablised and passed on to consumers, thus allowing behaviour to be influenced by sunk costs. Retailers could be expected to variablise it directly as a c/kwh charge, and line businesses could either pass costs to retailers or, if they know consumers usage, variablise it to them. Allocating to South Island generators prevents this, as the generators have no incentive to change their offer behaviour. On balance, therefore, allocating to South Island generators is more economically efficient than allocating to North Island offtake, and is possible because the economic value of the HVDC link to the South Island generators exceeds the sunk cost charge 22. As it is the current methodology (and has been since the start of the Wholesale Electricity Market in October 1996), retaining it also provides the benefits of stable and predictable prices Hon Max Bradford, Electricity Consumers Get A Better deal, media release, 16 December 1998, and Ministry of Commerce, Electricity Industry Reform: Discussion Paper on the Operation of the Specific Thresholds for Price Control for Electricity Line Businesses, December 1998, and Proposal for the Operation of the Specific Thresholds for Price Control for Electricity Line Businesses, 25 February See footnote 19. See section 2.6 on economic value. If, in future, it was ascertained that the economic value of the HVDC link to the South Island generators was less than the sunk cost charge, then the HVDC sunk costs should be allocated to the South Island generators up to the economic value to them, and the residual costs allocated to the economically second best alterative of the North Island offtake.

14 19 April 1999 HVDC Sunk Cost Recovery Page 14 of 18 The financial rather than economic effects of allocating HVDC sunk costs to South Island generators will be to reduce the profits of the South Island generators 23. The financial effect of the alternative allocation to North Island offtake would be, ultimately, to increase the price of electricity delivered to North Island consumers (by an average of about 0.4 c/kwh if variablised, 24 ) The comparison of alternative allocations is summarised in table 1 below. Table 1: Comparison of alternative allocations Allocation of HVDC Sunk Costs to 25 South Island generators North Island retailers North Island line businesses Economic efficiency criteria Fixed for the maximum duration possible, to minimise opportunities for variablisation Yes No Retailers likely to variablise the sunk costs as c/kwh and pass on to end-use consumers Possibly No Variablisation possible through passing charges on to retailers, or where the line business has access to end-use customers usage data Non-distortionary to minimise distortion to nodal prices Price stability and predictability in a year and between years No (weaker) Distortionary signal to those considering investment in South Island generation Yes No (stronger) Distortionary signal to those considering investment in North Island offtake or demand side management No Significant change to transmission prices to South Island generators and to North Island offtake. Economic value to avoid charges that exceed the economic value of the service to the customer charged for it Yes Yes Probably No Most of the benefits of the HVDC link accrue to energy traders (generators and retailers) Financial consequences Who ultimately pays? South Island generators through decreased profits North Island consumers through increased prices Relative to the alternative of the sunk cost of the HVDC link being unrecovered, or recovered from other parties. Based on an HVDC sunk cost of $M 92.3 (revenue requirement for the year ending March 2000) and a North Island demand of 23.0 TWh (estimate for the year ending March 2000). Of the total HVAC sunk cost of $M 417.2, $M is allocated to North Island offtake, so allocating HVDC sunk cost to North Island offtake would result in a 35% increase in total transmission charges to North Island customers. See the text for rationale for dismissing possibility of allocating HVDC sunk costs to South Island offtake or North Island generation (economic value - section 2.6), or to incumbents only (sections 2.1 and 3.2).

15 19 April 1999 HVDC Sunk Cost Recovery Page 15 of 18 4 ALTERNATIVE VIEWS AND SUBSIDIARY CRITERIA Thus for economic efficiency HVDC sunk costs should be allocated to South Island generators. Economic efficiency as defined above must drive the choice of method: any alternative would be inefficient. If a range of different allocation methodologies could be shown to be equally efficient economically, then there might be a role for some alternative views or subsidiary criteria in deciding between them. However, as any allocation to North Island offtake is demonstrably less economically efficient than allocation to South Island generators, that does not apply here. Other views than economic efficiency have in the past been suggested to justify methodologies for allocating the HVDC sunk costs. Some such methodologies have suggested that all charges should be borne by South Island generators, and thus reinforce economic efficiency arguments, others have not and do not. Some alternative views and subsidiary criteria are discussed below. 4.1 Equity Some have suggested that equity considerations be used as a basis for allocation. There is nothing wrong with equity per se, of course, but equity should not be confused with economic efficiency Economic value as an allocator Economic value or benefit to customers limits the amount that they can be charged for a service 26. However, it has been proposed by some as a basis for allocating, rather than as a limit on charges to particular customer groups. For example, Ernst and Young in considered HVDC cost allocation from the perspective of Who would have the strongest economic incentive to build the HVDC link if it did not exist? Ernst and Young estimated that the relative benefits of the link to South Island generators and North Island loads was in the range of 70:30 to 77:23. Ernst and Young concluded from this that by far the strongest incentives for the link to be built or replaced or expanded lie with South Island generators, and so they should be charged for it. In 1996 also the Officials Committee on Energy Policy (OCEP) proposed 28 that South Island generators and North Island offtake be charged their share of the benefits of the link: in other words, that the relative economic value between customer groups should be used as a basis for proportional allocation between them. While intuitively attractive on equity grounds, these arguments use subsidiary criteria in place of economic efficiency criteria Historical justification An example of an historical justification for HVDC sunk cost allocation is the 47:53 allocation in Transpower s pre-1996 methodology between South Island generators and North Island offtake. This was based on North Island offtake customers paying the costs of the original 600 MW link and the South Island generators paying the cost of the upgrade of the link to 1240 MW 29. Relying on historical justification suffers from the subjectivity imposed by different perspectives on what the historical justification actually was. More importantly, it would be pure chance if any allocation based on past justification met current, forward-looking economic efficiency objectives See section 2.6 and footnote 22. A Transmission Cost Recovery and Pricing Framework, prepared by Ernst and Young for Transpower, Final Version, August See the first Section and Appendix 1. The report was commissioned by Transpower to provide an economic review of its pricing methodology. See note M R Lear to R W Thomson, 9 September Historically, the New Zealand electricity system developed as two independent power systems. The HVDC link was built in 1965 and expanded in 1989 to create a single interconnected national grid.

16 19 April 1999 HVDC Sunk Cost Recovery Page 16 of Linking sunk cost recovery to nodal prices Another set of alternative views and subsidiary criteria have been based on misunderstandings of the relationship between sunk costs on the one hand, and nodal prices and the resultant rentals on the other. Broadly, sunk costs relate to the long term average costs of capital. Nodal prices and rentals on the other hand relate to the short term marginal costs of energy. Not only are sunk costs and nodal prices/rentals conceptually quite different 30, but they even act in opposite directions: increasing transmission capital would typically decrease the loss and constraint components of the nodal price Locational signalling One argument that has been put forward is that the sunk cost allocation methodology should be used to deliberately send economically efficient, non-zero locational signals. For example, Ernst and Young in 1996 concluded that charging South Island generators for the link would send appropriate locational signals for new investment, as it would encourage investment in the North Island. This conclusion was endorsed by Putnam, Hayes and Bartlett in , as reinforcing the spot market signal that new entrant generators should not locate in the South Island. The conclusion however is incorrect: any additional locational signal beyond that provided by nodal pricing (once connection costs have been netted off 32 ) is a distortion, whether it is reinforcing or not, and should be minimised. The only time that locational signalling could be valid would be to correct a recognised deficiency in the nodal pricing signals, by sending an equal and opposite signal. There are few recognised deficiencies in the nodal pricing signals 33. In any case, sending an equal and opposite signal to deficiencies in half-hourly marginal energy prices through fixed, stable and predictable sunk cost charges would be analytically intractable Reduced charges in return for rentals Transpower s HVDC sunk cost recovery methodology has since 1996 been to allocate HVDC costs to South Island generators. The methodology for HVDC rentals has been to return them to the South Island generators. Since 1996, in order to broker contracts for HVDC sunk cost recovery with ECNZ and Contact Energy, Transpower essentially bought back the HVDC rental streams in return for a reduced HVDC charge 34. Rentals amounts are highly variable, and the section 26 statement requires that risks should be allocated where they are most efficiently and effectively managed. It is the electricity market that is best able to manage constructively the HVDC rentals, with virtually all the management potential currently lying with the generators. With the break-up of ECNZ, Contact Energy will be the only generator with major stations both sides of the HVDC link, but will not be dominant at either end, so opportunities for gaming of the HVDC constraints have been considerably reduced. If Transpower retained rentals to recover part of its sunk costs, and those rentals were tracking below the income required of them, Transpower would have the incentive to perversely manage them back on track through increasing HVDC outages, or accept under-recovery of sunk costs. If on the other Nodal prices are often referred to as having a energy, transmission loss and transmission constraint components. This terminology can be misleading. When there is a constraint, the energy component is the low marginal energy price on the downside of the constraint, and the total nodal price is the high marginal energy price on the upside of the constraint (adjusted for local losses). The transmission constraint component thus reflects an offered energy price. It is only indirectly (and then inversely) related to the sunk costs of transmission assets. Analysis of Transpower s Transmission Pricing Regime, Draft Report for Transpower New Zealand Limited, 5 November 1997, Putnam, Hayes and Bartlett - Asia Pacific Ltd (see especially sections and 6.4.2). The report was commissioned by Transpower to review its transmission pricing regime relative to the requirements of the SCI and the Government s section 26 statement. The cost of connection to the national grid presents a valid locational signal to invest close to the grid. For this reason connection costs can be netted out of consideration of economically efficient HVDC sunk cost allocation. See footnote 8 and section 2.3. The memorandum of understanding with ECNZ to this effect expired on 31 March 1999, but the contract with Contact Energy is until 30 September 2002.