Transmission pricing mechanism in New Zealand: An analysis of the Electricity Authority s proposed options * by Marcelo A. Schoeters Pablo T. Spiller 11 August 2015 * This paper was commissioned by Vector Limited. The opinions expressed here are exclusively those of the authors, and do not reflect the opinions of Vector Limited, Compass Lexecon or the University of California, Berkeley.
TABLE OF CONTENTS I. INTRODUCTION AND EXECUTIVE SUMMARY... 4 II. CREDENTIALS... 7 II.1 PABLO T. SPILLER... 7 II.2 MARCELO SCHOETERS... 8 III. GENERAL POLICY FRAMEWORK... 10 III.1 THE ELECTRICITY AUTHORITY S POLICY OBJECTIVES... 10 III.2 BASIC TRANSMISSION PRICING PRINCIPLES... 12 III.3 FUNDAMENTALS OF SUNK COST RECOVERY... 14 IV. NEW ZEALAND S CURRENT TRANSMISSION PRICING MECHANISM... 17 IV.1 THE DIFFERENT COMPONENTS OF THE TRANSMISSION PRICING MECHANISM IN NEW ZEALAND... 17 IV.1.1 Nodal pricing system... 17 IV.1.2 Transpower s charges for cost recovery... 18 IV.2 EA S CONCERNS WITH THE CURRENT SYSTEM... 19 V. THE EA S PROPOSED CHANGES IN TRANSMISSION PRICING... 21 V.1 MAIN CHARACTERISTICS OF THE PROPOSAL... 21 V.1.1 Alternative applications of the new charges... 22 VI. ANALYSIS OF THE EA S PROPOSED TPM CHANGES... 24 VI.1 SUNK COST RECOVERY... 24 VI.1.1 Use of the beneficiaries-pay principle for sunk cost recovery... 24 VI.1.2 Nodal prices give sufficient signals for location decisions... 28 VI.1.3 Generators are users and should contribute to sunk cost recovery... 29 VI.1.3.a A postage stamp charge would not be disadvantageous for low profitability generators... 31 VI.1.3.b Generators would not pass-through postage stamp charges to customers... 31 VI.2 IMPACT OF THE EA S PROPOSAL ON CURRENT RETAIL PRICES... 32 VI.3 FUNDING OF NEW INVESTMENTS IN TRANSMISSION... 34 VII. AN ALTERNATIVE PROPOSAL BASED ON THE MINIMUM DISTORTION PRINCIPLE... 38 APPENDIX A INTERNATIONAL EVIDENCE... 41 A.1 ENERGY MARKET STRUCTURE... 41 A.2 TRANSMISSION CHARGES AND SUNK COST RECOVERY... 42 A.3 INVESTMENTS IN TRANSMISSION... 44 2 11 August 2015
APPENDIX B EFFECT OF A CHANGE TO A MINIMUM DISTORTION TPM ON RETAIL PRICES... 48 INDEX OF TABLES Table I. Difference between annual transmission charges by user: EA s proposal vs status quo Forecasted 2017-2019... 33 Table II. Impact of the EA s proposal on retail prices... 34 Table III. Transpower revenue requirement by charge under current TPM... 49 Table IV. Transpower revenue requirement by charge under minimum distortion TPM49 Table V. Difference in charge paid by load and generation under current and minimum distortion TPMs... 50 Table VI. Reduction in electricity prices under minimum distortion TPM 2014... 51 INDEX OF FIGURES Figure I. Transmission charges under EA s proposal (Base option) vs status quo Excluding LCE and connection charges (in $ million)... 27 3 11 August 2015
I. INTRODUCTION AND EXECUTIVE SUMMARY 1. The Electricity Authority (hereafter, EA ) has raised several concerns about the current Transmission Pricing Mechanism (hereafter TPM ). These are fundamentally related to the EA s view that, under the current TPM, the substantial increase in Transpower s revenue requirement arising from the transmission investments of the last decade gives rise to distortions and inefficiencies because transmission costs are not related to the benefits grid users receive from these investments. 2. According to the EA the current problems with transmission pricing are: a. An unequal sharing of the burden of past investments between the Upper North Island and other regions of New Zealand. b. The allocation of the HVDC charges. c. An inefficient use and expansion of the grid. 3. As a consequence, the EA is now consulting on a proposal to modify the TPM, mostly based on the idea that the beneficiaries of the investments should be those paying for them. 2 The EA s proposal includes three main components: a. A new deeper connection charge, which would be applied to connection assets that are used by a small number of parties and are not included in the connection charge. This charge would be paid by all parties involved, whether loads or generators. 2 See Electricity Authority, Transmission Pricing Methodology Review TPM options, Working paper, 16 June 2015, hereafter Transmission Pricing Mechanism Review. 4 11 August 2015
b. A new Area of Benefit charge to recover the costs of assets not covered by the connection and deeper connection charges. This charge would be applied to beneficiaries of the investments, whether loads or generators. c. Finally, a postage stamp (flat rate) capacity-based charge applied to loads only, which will be used to cover costs not recovered with the other charges. 4. The EA s proposal, however, fails to satisfy fundamental principles for transmission pricing and, therefore, will not promote efficiency. The new proposed deeper connection and area of benefit charges intend to recover sunk costs from the alleged beneficiaries of historical investments. This will negatively impact on dynamic efficiency for three reasons: a. First, whether historical (sunk) costs are recovered from beneficiaries of the existing assets would not promote efficient decisions on new investments; b. Second, to the extent that the new charges depend on location, they could create inefficient location decisions, based on the attempt to reduce transmission charges. c. Third, the beneficiaries-pay principle applied to new investments is not based on charges proportional to net benefits. 5. Moreover, the EA s proposed change in the TPM is not neutral with respect to retail prices. We estimate that under the EA s proposal, retail prices would increase between $2.5/MWh and $3.95/MWh, increasing current residential electricity prices in the range of 1-1.5%. On the other hand, the implementation of a TPM that satisfies basic principles for sunk cost recovery could reduce retail prices to consumers in New Zealand in the range of 2-3% relative to the current residential electricity prices, via a reduction in transmission charges paid by line companies. 6. To achieve efficiency, sunk cost recovery should be done in a way that minimizes distortions. An appropriate method is one based on the so called wide base approach, such as 5 11 August 2015
recovering transmission sunk costs via a widespread and relatively low flat (postage stamp) charge on all users of the transmission grid. The use of a beneficiaries-pay principle for new investments, on the other hand, may promote dynamic efficiency by making beneficiaries accountable for the expansion of the grid as long as the approach is based on defining charges proportional to net benefits and granting beneficiaries the ability to block investments. 7. Hence, a TPM that satisfies the minimum distortion principle and provides the right signals for efficient use of the grid and efficient investment should be composed of two fundamental charges: a. A postage stamp charge for sunk cost recovery applied to loads and generators independently of location. The general postage stamp charge should cover both the return on historical investments as well as system wide operational and maintenance costs (O&M), net of losses and congestion rents which must be fully allocated towards sunk cost recovery through a transparent mechanism. b. A charge based on the beneficiaries-pay principle to pay only for new investments. The application of this principle needs the identification of all the beneficiaries, who would be called to pay for new investments based on the net benefits they obtain from the investment. 8. We estimate that this minimum distortion TPM would generate lower transmission charges to line companies and would, therefore, reduce current retail prices in the range of $5.72/MWh and $9.04/MWh, representing a reduction ranging of 2% to 3% relative to current residential prices. 6 11 August 2015
II. CREDENTIALS II.1 PABLO T. SPILLER 9. Professor Pablo T. Spiller is a Senior Consultant at Compass Lexecon. He is also the Jeffrey A. Jacobs Distinguished Professor (Emeritus) of Business and Technology at the Haas School of Business, University of California, Berkeley; research associate at the National Bureau of Economic Research; and a former president of the International Society for New Institutional Economics. 10. Before joining Compass Lexecon, he was the co-chair of LECG s international arbitration practice. He has written extensively on regulatory, antitrust, and institutional issues, having published more than 100 academic articles and nine books. He has also extensive consulting and expert testimony experience. 11. He has contributed to the design and implementation of regulatory reforms, and consulted extensively with the World Bank, United Nations, the Inter-American Development Bank as well as governments and private companies on business valuation, damage analysis, and regulatory analysis of infrastructure projects in multiple countries including Argentina, Bolivia, Brazil, Canada, Chile, Colombia, Costa Rica, the Commonwealth of Dominica, Croatia, Dominican Republic, Ecuador, El Salvador, Egypt, Guatemala, Hungary, Jamaica, Kuwait, Malaysia, México, Norway, New Zealand, Panama, Peru, the Philippines, Poland, Russia, Senegal, Spain, Trinidad and Tobago, Turkey, Ukraine, the United States, Uruguay and Venezuela. He has participated as a valuation expert in numerous international arbitration cases involving both treaty and contractual disputes. 12. He was the editor-in-chief and co-editor of the Journal of Law, Economics, and Organization for over 19 years, and has been co-editor of numerous other academic and professional journals. He was also the chair of the Business and Public Policy group at the University of California, Berkeley for five years. On leave from Haas, he has also been a special advisor to 7 11 August 2015
the director at the Bureau of Economics of the Federal Trade Bureau. He was also an elected member of the board of directors of the American Law & Economics Association. II.2 MARCELO SCHOETERS 13. Mr. Schoeters is an Economic Consultant with 23 years of experience now working as Senior Vice President for Compass Lexecon at the Argentine branch. He has advised both public and private institutions on several issues including: firm valuation, tariff analysis, privatization processes, rural electrification, risk management and regulation. During his professional experience, he has worked closely with the Argentine Secretariat of Energy, the Gas National Regulatory Office, the Argentine Secretariat of Mining, the Electricity National Regulatory, the 9th. Group on Tariffs at Mercosur, the World Bank, the I.A.D.B., the Coastal Corporation (El Salvador), the Association of Electrical Lenders of the Province of Buenos Aires, FUNDELEC (Venezuela), Electricidad de Caracas, Electrocosta and Electricaribe (Unión Fenosa - Colombia), ANEEL (Energy Regulator of Brazil), CONAM (Ecuador), CSPE (Gas Regulator of San Pablo, Brazil), among others. 14. He participated in the feasibility study for a 500 kv transmission line in a mining region in Argentina. He also participated in the team that helped FREBA (Regional Electricity Forum of Buenos Aires Province) in the design of alternative regulatory procedure for capacity expansion projects on electricity transmission within the Buenos Aires province. He was in charge of a consultancy work for the Argentine National Secretariat of Energy, in which different regulatory procedures for capacity expansions projects on the Argentine electricity transmission grid were analyzed and a new proposal was presented. 15. Between 2001 and 2006 he worked at Mercados Energéticos as Executive Consultant. He specialized on Prices and Tariffs and Corporate Support, participating in different projects related to tariff setting, oil and gas, electricity distribution and transmission, regulatory risk analysis and design of strategies to develop rural electrification. 8 11 August 2015
16. He was involved in more than fifty cases in the electricity sector of Argentina, Bolivia, Brazil, Chile, Colombia, Ecuador, El Salvador, Guatemala, Italy, Panama, Paraguay, Peru, Russia, Spain, Uruguay and Venezuela. 17. On May 2006 he joined LECG again as Senior Managing Economist. Nowadays he is mainly dedicated to the International Arbitration Practice of Compass Lexecon, leading projects and providing testimony in diverse sectors. He was involved in more than twenty commercial and investment treaty cases and ten preliminary damage assessments in electricity, natural gas, oil, airports, roads, fishing, and hospitality sectors. 18. He obtained his BA in economics at the National University of Cordoba (Argentina) and is now a PhD candidate in economics at the same institution. 19. Mr. Schoeters has been selected by Global Arbitration Review (GAR) as one of the expert witnesses to be recognized in The International Who's Who of Commercial Arbitration 2010, 2011, 2012, 2013 and 2014. 9 11 August 2015
III. GENERAL POLICY FRAMEWORK III.1 THE ELECTRICITY AUTHORITY S POLICY OBJECTIVES 20. The Electricity Industry Act 2010 states that [t]he objective of the Authority is to promote competition in, reliable supply by, and the efficient operation of, the electricity industry for the long-term benefit of consumers. 3 The EA seems to be of the view that transmission pricing should focus on overall efficiency of the electricity industry for the long-term benefit of electricity consumers. Overall efficiency refers to both efficient operation of an efficient investment in the electricity industry the grid, generation, and on the demand-side. 4 Moreover, the EA seems to recognize that there may be a trade-off between static and dynamic efficiency. 5 The EA s interpretation of the long-term benefit to consumers relates to dynamic efficiency and, therefore, if faced with a trade-off, dynamic efficiency should prevail. 6 21. The EA has adopted a Decision-Making and Economic framework (hereafter DME ) for developing the TPM. The DME is supposed to be used for ensuring that the TPM achieves the EA policy objectives, as defined above. According to the EA, under the DME, the hierarchy of pricing approaches consists of: 7 a. Market-based or market-like charges: charges established by interaction of buyers and sellers in a competitive market, or likely to replicate such charges. 8 3 See Electricity Industry Act 2010, 5 October 2010, Section 15. 4 See Transmission Pricing Mechanism Review, 3.25. 5 See Transmission Pricing Mechanism Review, 3.27. 6 See Electricity Authority, Interpretation of the Authority's statutory objective, 14 February 2011, A.11. 7 See Electricity Authority, Decision-making and economic framework for transmission pricing methodology: Decisions and reasons, 7 May 2012, 5-6, 17-27. 8 See Electricity Authority, Decision-making and economic framework for transmission pricing methodology review: Consultation paper, 26 January 2012, 7. 10 11 August 2015
b. Exacerbators pay: charges aimed at internalizing the externality caused by the exacerbator, to incentivize efficient decisions. 9 c. Beneficiaries pay: charges by which the cost of an asset is to be recovered from the users who benefit from it. It requires a robust method for identifying beneficiaries. 10 d. Alternative charging options: charges (e.g. postage stamp) used to recover costs that could not be recovered through market-based, exacerbators or beneficiaries charges. 11 22. It is the EA s view that the result of applying a hierarchy as described above would be a transmission pricing mechanism that minimizes cost recovery distortions, and provides the right incentives for investment and consumption. Market exacerbators and beneficiaries based charges are intended to provide specific signals for decision making. Exacerbators-pay charges provide incentives for efficient use of the grid by equalizing private and social costs. Beneficiaries-pay charges provide incentives for efficient investment by creating a mechanism that associates investment costs with its benefits. Finally, a flat (postage stamp) charge would only be used in case some transmission costs could not be recovered through the other market-based charges. The hierarchy under the DME, therefore, seems conceptually reasonable to achieve the EA s efficiency objectives, but its successful implementation requires that charges be well designed and both exacerbators and 9 See Electricity Authority, Decision-making and economic framework for transmission pricing methodology review: Consultation paper, 26 January 2012, 14. The DME defines exacerbators as a party whose action or inaction led to a particular cost and who would change its behavior to avoid or reduce the cost if faced with the social cost of its action or inaction. See Electricity Authority, Decision-making and economic framework for transmission pricing methodology: Decisions and reasons, 7 May 2012, 19(a). Essentially, an exacerbator is creating a negative externality in the network. 10 See Electricity Authority, Decision-making and economic framework for transmission pricing methodology review: Consultation paper, 26 January 2012, 17-18. 11 According to the EA, these charges should be designed in a way that limits distortions and achieves full cost recovery. See Electricity Authority, Decision-making and economic framework for transmission pricing methodology review: Consultation paper, 26 January 2012, 20. 11 11 August 2015
beneficiaries be accurately identified. Otherwise, the TPM, while reflecting good policy intentions may end up implementing them erroneously. III.2 BASIC TRANSMISSION PRICING PRINCIPLES 23. Based on the EA s interpretation, the main objectives of the TPM in New Zealand can be summarized as follows. a. Efficient operation: Ensuring the maximization of short-run consumer and producer surplus (static efficiency). That is, given the state of the grid, transmission prices should be set to give consumers and producers the right signals for their consumption and production decisions. b. Efficient investment: Ensuring the maximization of long-run expected welfare (dynamic efficiency). That is, transmission prices should provide the right incentives so that efficient (welfare improving) investments are made, while inefficient investments are not made. 12 24. Efficiency would be achieved whenever the pricing mechanism provides the correct signals to the users of the grid. A TPM designed to achieve efficiency on these two fronts should then satisfy the following five principles: a. Transmission charges should not distort generation decisions: Generation decisions are both related to static efficiency (injection decisions) and dynamic efficiency (generation investments). Transmission charges, therefore, should ensure that injection decisions are based on the marginal cost of electricity generation and that decisions to invest in generation are made when the value of the expected benefits from the investment outweighs its incremental cost. 12 Efficient investment includes decisions on location by generators and loads. 12 11 August 2015
b. Transmission charges should not distort consumption decisions: Similarly, consumption decisions should be based on the marginal benefit of electricity consumption. For that to be the case, transmission charges should not distort the prices that consumers pay for electricity, by introducing charges not linked to the economic value of transmission. c. Transmission charges should not distort location decisions, whether by consumers or generators: Location decisions, both for consumers and generators relate to the issue of dynamic efficiency. Transmission prices should only affect location decisions to the extent that there are geographical differences in marginal energy prices as a result of losses and constraints. d. Transmission charges should not promote inefficient bypass: Inefficient bypass takes place when market participants make socially inefficient investments to avoid excessive prices. Inefficient bypass lowers a particular market participant s costs without lowering the overall system costs. In contrast, economic bypass occurs when market participants investments reduce the costs of the system, for example, when a well-designed mechanism to promote new investments is in place. 13 Transmission charges should ensure that only economic bypass takes place. e. Transmission financing investment decisions should be delegated to the users: Users or beneficiaries of the investments are best placed to evaluate whether the benefits from investments outweigh their costs. Delegating investment decision (and financing) to users, therefore, is necessary to achieve efficient investment. Users of the transmission grid ought to include both consumers and generators as both agents benefit from transmission investments. 13 Uneconomic bypass may occur when prices do not reflect the market value of transmission assets and the economic cost of transmission. In that case, some users may be paying excessive transmission prices and may have incentives to invest in alternative technologies to avoid the use of the transmission grid and, therefore, avoid paying transmission charges. 13 11 August 2015
25. Moreover, efficiency would be best served when transmission prices are simple, transparent, acceptable and stable, with a minimum of unexpected changes adverse to existing customers. 14 Stability of transmission pricing, by facilitating long term investments, also promotes efficient long-run decisions. A transparent and stable transmission pricing mechanism helps investors by reducing the inherent uncertainty present in the investment decision-making process. 26. Our analysis of the EA s proposal, therefore, will be based on whether, and to what extent, the changes to the TPM proposed by the EA satisfy the basic principles for efficiency in transmission pricing. III.3 FUNDAMENTALS OF SUNK COST RECOVERY 27. Sunk cost recovery tends to be a large component of transmission charges in those jurisdictions in which sunk cost recovery is allowed. 15 The need to recover sunk costs prevents any TPM from achieving full (first-best) efficiency, as inefficiency is inherent to sunk cost recovery. Only second-best (constrained) efficiency is achievable. Therefore, in order to achieve the efficiency objectives explained above, the TPM must be designed so as to allocate sunk costs in a way that minimizes potential distortions, that is, that impacts the least on consumption, generation and investment decisions. In this section we explain the types of distortions that may arise from sunk cost recovery and the principles that a pricing mechanism should follow to minimize them. 28. Sunk cost recovery may negatively affect both static and dynamic efficiency. Regarding static (short-run) efficiency, if sunk costs were to be recovered through variable charges based on injection or consumption levels per MWh or kwh, generators and loads would find strategies to modify their energy dispatched and consumed as a way to avoid or reduce the 14 See Bonbright, J.C., Principles of Public Utility Rate, Columbia University Press, New York, 1961. See also Green, R., Electricity transmission pricing: an international comparison, Utilities Policy, Vol. 6(3), September 1997. 15 See below, 51. 14 11 August 2015
charges they have to pay. Thus, sunk cost recovery through variable charges would affect injection and consumption decisions. 29. Regarding dynamic (long-run) efficiency, sunk cost recovery may distort investment decisions, both in terms of location and in the type of investments that take or do not take place. In addition, when sunk cost recovery charges are too high, users may have incentives to invest in inefficient bypass with the sole purpose of avoiding the charge. 30. Thus, the best way to think about sunk cost recovery is along the lines of optimal taxation, which focuses on minimizing distortions of raising, via taxes, a certain amount of funds. Two fundamental principles of optimal taxation are generally agreed upon: a. Ramsey taxes: To minimize distortions, tax rates should be higher for those taxpayers whose economic response to the imposition of the tax is minimal. That is, the tax rate should be inversely related to the elasticity of demand/supply (inverse elasticity or Ramsey rule). 16 b. Largest tax base: The tax should be imposed across as many taxpayers as possible, so as to minimize the impact of the tax on each individual (proportionality or wide base rule). 16 Ramsey s main insight was that, if consumers differ in their demand elasticities, then an equal mark-up over marginal cost to all consumers would make some consumers choose to reduce their consumption too much, while others will reduce their consumption too little. Since the consumer surplus loss from marking up prices above marginal cost is related to how elastic the consumer demand is at the original price, Ramsey s insight was that the mark-up should be negatively related to the demand elasticity. In other words, the mark-up over marginal cost should be higher to those customers who would not change their consumption pattern too much. This is known as the inverse elasticity rule. This rule can be applied not just to taxes or mark-up on consumption but also to taxes or mark-ups on production, whereby the relevant elasticity is not the elasticity of demand, but rather the elasticity of supply. 15 11 August 2015
31. The inverse elasticity rule can also be applied to optimal utility pricing. 17 Ramsey taxation, then, requires identifying transmission users (generators and loads) whose dispatch, consumption and location decisions are relatively independent of the sunk cost charge. 32. The wide base rule, on the other hand, suggests that sunk cost recovery should be based on a (small) postage stamp applied to all users (including generators and loads) independently of their location and actual consumption/production. This charge has the ability to avoid the normal distortions of sunk cost recovery: a. It prevents bypass because the charge is relatively small and, therefore, incentives to bypass are low. b. It does not distort locational decisions, as changing location would not exempt the user from paying the postage stamp tax. 33. In summary, if the postage stamp charge is widely distributed across the network, it has the highest potential of minimizing economic distortions. 18 17 See Ramsey, F., A contribution to the theory of taxation, Economic Journal Vol. 37, 1927. See also Baumol, W., and Bradford, R., Optimal Departures from Marginal Cost Pricing, American Economic Review, Vol. 60(3), 1970, pp. 265-283. 18 Final users may also face variable sunk cost charges (on a per kwh basis), and therefore, the postage stamp tax would not fully eliminate consumption distortion. In any case, as long as the charge is small, consumption distortions would be limited. 16 11 August 2015
IV. NEW ZEALAND S CURRENT TRANSMISSION PRICING MECHANISM IV.1 THE DIFFERENT COMPONENTS OF THE TRANSMISSION PRICING MECHANISM IN NEW ZEALAND 34. New Zealand s electricity market operates under a full nodal pricing system. 19 Under this scheme, the price of electricity at each point in the network reflects losses and the shadow value of transmission constraints. In addition to losses and congestion, transmission pricing is focused exclusively on sunk cost and operating cost recovery. We explain these components in the next sections. IV.1.1 Nodal pricing system 35. Electricity spot prices in New Zealand are based on nodal marginal costs. 20 Generators offers and loads bids are used to pre-schedule generation and to develop forecast prices. Final (ex-post) prices are determined by a market clearing process for each half-hourly trading period. 21 Node prices attempt to measure the geographical differences in marginal energy prices as a result of losses and constraints. 22 Under this system, generators will produce to the extent that their avoidable costs of generation are not greater than the marginal value of electricity at their location. In the same way, loads will consume up to the point 19 See Mathiesen, V. (ed.), Mapping of selected markets with Nodal pricing or similar systems Australia, New Zealand and North American power markets, 2011 pp. 20-22. 20 The spot price is the wholesale price of electricity traded in any given half-hour. 21 See Electricity Industry Participation Code 2010, Schedule 13.3. 22 It is well known that if transmission revenues were exclusively based on transmission short-run marginal costs, the transmission revenues would not be sufficient to finance future investments or maintenance costs. See Bastos, C. and M.A. Abdala, Reform of the electric power sector in Argentina, 1999, p. 186-187. See also Hsu, M. An introduction to the pricing of electric power transmission Utilities Policy Vol. 6(3), p. 257. In New Zealand, loss and constraint rents are called Loss and Constraint Excess ( LCE ). According to the regulation, the LCE has to be paid to Transpower and Transpower allocates it to its customers via rebates. See Electricity Authority, Information paper: Allocation of residual loss and constraint excess post introduction of financial transmission rights, 3 July 2012, 2.1.3. 17 11 August 2015
where their willingness to pay for electricity is at least as high as the marginal cost of electricity at their location. IV.1.2 Transpower s charges for cost recovery 36. According to the Electricity Industry Participation Code of 2010 ( Code ), Transpower s pricing must recover the costs of providing its transmission services, which include capital, maintenance, operating and overhead costs. 23,24 Before the beginning of each year, Transpower forecasts the revenue required to recover the sunk and current costs, which is collected through the Transmission Pricing Methodology. 25 The charges for (current and sunk) cost recovery consist of: 26 a. Connection charges: Used to recover part of Transpower s High-Voltage Alternate Current (AC) revenue by reference to the cost of providing connection assets. 27 This charge is paid by both loads and generators. b. Interconnection charges: Used to recover the remainder of Transpower s AC revenue. The interconnection rate is the same for all load customers at all connection locations for all regions (postage stamp pricing). Generators do not pay interconnection charges. 23 See Code, Schedule 12.4, clause 2(1). 24 Transpower New Zealand Limited (hereafter Transpower ) is a state owned company in charge of electricity transmission in New Zealand. 25 Transpower s costs include costs related to investments which are not subject to approval by the Commerce Commission. See Code, Schedule 12.4, clause 1. 26 To prevent uneconomic bypass, a customer with a viable and uneconomic alternative project may apply for a prudent discount. If the discount is approved, the customer will pay to Transpower an annuity determined by reference to the cost of the alternative project and transmission charges that would be calculated as if the bypass project had been implemented. That is, through this prudent discount policy, a customer who has a viable bypass project would be charged an amount that would leave it indifferent between developing the project or not. See Transpower New Zealand Limited, Transmission Pricing Methodology, June 2007, 9.1-9.2 and 9.19. A similar mechanism exists in Australia. See Australia National Electricity Rules Version 72, July 2015, Section 6A.26. 27 AC revenue is the revenue required to recover the (current and sunk) costs of providing AC transmission services during a pricing year. The connection charge is applied to connection points between the grid and generators, distributors or large customers. The connection charge varies according to the connection node in which it is applied. See Transpower New Zealand Limited, Transmission Pricing Methodology, June 2007, 2.1.1. 18 11 August 2015
c. High-Voltage Direct Current (HVDC) charges: Used to recover Transpower s HVDC revenue. 28 This charge is only paid by South Island generators. IV.2 EA S CONCERNS WITH THE CURRENT SYSTEM 37. The EA has raised several concerns with the current TPM. These are fundamentally related to the substantial investments in the transmission grid, which, in the EA s view, have strengthened the interconnection and HVDC pricing signals, creating potential inefficient investment activities. 29 38. According to the EA the current problems with transmission pricing are: a. An unequal sharing of the burden of recent past investments between the Upper North Island and other regions of New Zealand. b. The allocation of the HVDC charges to South Island generators only. c. An inefficient use and expansion of the grid. 39. According to the EA, since 2004 more than $1.3 billion on transmission investments have been commissioned in the Upper North Island, translating into an increase in Transpower s revenue requirement of $221 million per year. Only 39% of this additional cost, however, has been paid through increased charges in the Upper North Island, 30 with other regions of New Zealand covering the reminder 61% of the additional annual revenue requirement. 31 According to Transpower, the North Island share of overall transmission assets has gone 28 HVDC revenue is the revenue required to recover the (sunk and current) costs of providing the HVDC assets during a pricing year. HVDC charges are paid by all HVDC customers at each South Island generation connection location. See Transpower New Zealand Limited, Transmission Pricing Methodology, June 2007, 2.1.2. 29 See Transmission Pricing Mechanism Review, 1.21. 30 The EA highlights that due to the design of the interconnection charge as a postage stamp charge paid by loads in all regions, transmission investments in areas such as Auckland end up being financed by customers in other areas, who do not actually require expansions. See Transmission Pricing Mechanism Review, 1.25. 31 See Transmission Pricing Mechanism Review, 1.23, 4.14(c) and Table 3. 19 11 August 2015
from 60% in 2007 to 79% in 2014, while its share of charges has remained constant at about 66%. 32 40. A second source of potential inefficiencies identified by the EA relates to the allocation of the HVDC charges. While the North Island generators often use the HVDC link to send power from the North to the South, they do not pay for this use because, in the current framework, only South Island generators pay HVDC charges. 33 Hence, although North Island generators benefit from the HVDC link, they do not contribute to the recovery of the HVDC cost. 34 41. Finally, the EA states that to obtain a more efficient use of the grid, and more efficient long term investments, a pricing structure is required that better reflects the costs of using the grid. This is the objective that the EA is allegedly pursuing with the proposed revision. 35 32 See Transmission Pricing Mechanism Review, 1.24 and 4.14(d). 33 See Transmission Pricing Mechanism Review, 1.28. Although it may be the case that in some situations the North Island exports electricity to the South Island, particularly during dry periods, this is not the usual situation. Most of the time, South Island generators export electricity to the North Island. 34 Note that loads in both islands also benefit from the HVDC link. 35 See Transmission Pricing Mechanism Review, Figure 2 and 1.77. 20 11 August 2015
V. THE EA S PROPOSED CHANGES IN TRANSMISSION PRICING 42. It is the EA s view that the current TPM can be improved in such a way that the TPM could be more dynamically efficient by better promoting efficient investment, ensuring lowest cost development of transmission and other electricity assets over time. 36 EA is considering three options for revising the TPM: a. Base Option: It includes a revised Loss and Constraint Excess crediting system, the existing connection charge, a deeper connection charge, a kilovolt ampere reactive ( Kvar ) charge, an Area of Benefit ( AoB ) charge, and a postage stamp capacity-based residual charge on load. 37 b. Base Option + LRMC: Base option combined with a Long-Run Marginal Cost ( LRMC ) charge. 38 c. Base Option + SPD: Base option combined with a Scheduling, Pricing and Dispatch ( SPD ) beneficiaries-pay charge. 39 V.1 MAIN CHARACTERISTICS OF THE PROPOSAL 43. The proposal introduces new charges, mostly based on the idea that the beneficiaries of the investments should be the ones paying for those investments. In particular, the proposal includes a new deeper connection charge, which would be applied to connection assets that 36 See Transmission Pricing Mechanism Review, 1.3. 37 The order in which the charges are applied is supposed to respect the hierarchy under the DME. See above, 21. 38 The LRMC charge would be applied to all forecast transmission investment above $20 million for a project that would not be subject to connection or deeper connection charges. It would be applied at peak congestion rather than at peak demand and would be adjusted to reflect the price signals provided by nodal prices to avoid double counting. See Transmission Pricing Mechanism Review, 7.10-7.17. 39 The SPD charge would be calculated on a net benefits only basis. Parties receiving a net loss (negative benefit) from the investment would pay zero. Charges for distributed generation would be calculated on the basis of net injection. See Transmission Pricing Mechanism Review, 8.10. 21 11 August 2015
are used by a small number of parties and are not included in the connection charge. 40 charge would be paid by all parties involved, whether loads or generators. This 44. In addition, the EA proposes a new Area of Benefit charge to assets not covered by the deeper connection charge. The charge would be applied to beneficiaries of the investments, whether load or generation. The charge would be computed to load on a capacity basis and to generation in proportion to their MWh injection (the latter, allegedly to avoid disincentivizing peaking generation). 41 45. Finally, costs not recovered with other charges would be recovered through a residual charge. 42 The proposed residual charge is a postage stamp (flat rate) capacity-based charge on load only. 46. Apart from these main changes, the EA s proposal also includes the current connection charge, a change in the way the LCE is allocated among users, 43 and a Kvar charge based on the average aggregate kvar draw of off-take transmission customers in areas of the grid where investment in static reactive support is likely to be required. 44 V.1.1 Alternative applications of the new charges 47. The EA is considering two possible applications of the new charges: 45 40 According to the EA, the deeper connection charge would be a proxy for negotiated charges that would result under a multi-party investment agreement in which the parties directly negotiate with Transpower for the provision of the asset. See Transmission Pricing Mechanism Review, 6.30. 41 See Transmission Pricing Mechanism Review, 6.57-6.59. 42 See Transmission Pricing Mechanism Review, 6.92-6.93. 43 Under the current methodology, Transpower allocates LCE credit generated on the different types of assets to customers associated to those assets. Under the revised methodology, a LCE attributable to an individual connection or deeper connection asset would be credited against the charges of customers that pay for that asset. Otherwise, the LCE would be credited in bulk against Transpower s remaining recoverable revenue. 44 The Kvar charge would recover the costs of static reactive support. The EA describes it as an exacerbators-pay charge because it would provide a price signal of the need for investment in static reactive support equipment. See Transmission Pricing Mechanism Review, 1.41 and 6.26. 45 See Transmission Pricing Mechanism Review, Table 2 and 1.82. 22 11 August 2015
a. Application A: New charges would be applied to both existing assets and new assets and investments. The EA proposes that the deeper connection, AoB and SPD charges be applied to assets that satisfy one of the following conditions: i. The investment is an existing investment that has been approved and commissioned after 28 May 2004, with a cost above $50 million; 46 ii. It is a new investment with a cost above $20 million; 47 iii. This charge could potentially be applied to HVDC Pole 2. 48 b. Application B: New charges would apply to new assets and investments only, with the costs of existing assets recovered through the existing charges. 48. In a nutshell, Application A proposes to use the new deeper connection and beneficiaries-pay charges for sunk cost recovery. Under Application B, on the other hand, the new charges based on the beneficiaries-pay principle would be applied only to new investments. 46 The rationale for including investments since 28 May 2004 above $50m is that this includes all large investments approved under a regulatory process. A cut-off date (28 May 2004) has been applied to the AoB charge to provide a line in the sand for determining what assets are subject to the AoB charge. Approval under a regulatory process is relevant for the AoB charge as information provided in the regulatory approval process is used to identify beneficiaries and, therefore, apply the charge. See Transmission Pricing Mechanism Review, 6.61. Furthermore, the EA argues that if new investments are affected by this charge, consistency and competitive neutrality requires that recent large investments be also applied this charge. Ibid, 6.62. 47 New investments are defined as those that are approved or commissioned (or both) after the publication of the TPM guidelines. See Transmission Pricing Mechanism Review, 6.63. 48 Pole 2 is an investment in the HVDC link that was made prior to 28 May 2004. The EA states that it should be included in the beneficiaries-pay charge to make it consistent with Pole 3. See Electricity Authority, Transmission Pricing Methodology: issues and proposal, 10 October 2012, 34 23 11 August 2015
VI. ANALYSIS OF THE EA S PROPOSED TPM CHANGES VI.1 SUNK COST RECOVERY VI.1.1 Use of the beneficiaries-pay principle for sunk cost recovery 49. An important part of the changes suggested by the EA relates to the recovery of sunk costs. As explained in Section III.3 above, sunk cost recovery should be designed so that it minimizes market distortions for both generators and consumers. The EA argues that efficiency would be achieved through its proposal to allocate sunk costs to the alleged beneficiaries of the existing assets. The existing investments, however, were promoted, accepted by the regulators and implemented based on the current TPM. System users since then, both generators and loads, made strategic decisions based on those policy decisions and under the expectation that the current TPM will remain in place. Had grid users known that the Government intended to change the way Transpower would charge for those investments, they may have withdrawn their support for the investment, or undertaken investments to mitigate the costs (such as contracting for embedded generation, or other ways to avoid the charges). Drastically changing the TPM in an ex-post fashion generates substantial uncertainty about New Zealand s regulatory stability. 50. Furthermore, these transmission investments have already been funded for and are sunk. Once these investments have been sunk, transmission charges will always be perceived as a tax that users will seek to avoid by distorting their decisions. As the theory of optimal taxation shows, the most efficient tax is one that cannot be avoided. 49 51. In Application A, the EA s proposal attempts to allocate sunk costs to the agents through the deeper connection, AoB and SPD charges, while under Application B only new investments 49 An additional problem with this proposal is the ability to identify ex-post who the ex-ante beneficiaries of a particular investment were. In this particular case, the EA argues that this is feasible for post-2004 investments. 24 11 August 2015
would be subject to the new charges. Observe, however, that sunk cost recovery represents 93% of both the deeper connection and AoB charges. 50 52. The introduction of a beneficiaries-pay principle is associated with the goal of improving dynamic efficiency. Dynamic efficiency, however, is independent of how the costs of historical investments are recovered. Hence, there are no efficiency gains from including historical assets on the application of the new and more targeted charges. On the contrary, this approach goes against the wide base rule for optimal taxation that we outlined in Section III.3. Since the new charges aim at concentrating sunk cost recovery on fewer market participants, rather than spreading it out, they could lead to substantial inefficiencies by distorting these users consumption and investment patterns. 53. Therefore, the proposed mechanism that concentrates sunk cost recovery on a limited number of users violates the basic principles as described in Section III.3: a. It does not improve dynamic efficiency because it cannot impact decisions on investments that have already been made. On the contrary, dynamic efficiency may worsen as it may impact future location decisions; 51 b. By allocating costs among a limited number of users, it increases transmission prices for individual users, promoting inefficient consumption and investment choices, as well as grid bypass. 50 To evaluate the impact of the proposed TPM, the EA has developed a model that is used to simulate the charges that each user of the grid would have to pay under the different pricing options, including the status quo. See Transmission Pricing Mechanism Review, 11.31 and 11.34. Using the EA s model, we calculate sunk costs as the difference between costs recovered under Applications A and B. Since under Application B these charges are applied only to new investments, the additional charges under Application A have to come from sunk investments. 51 Several submitters to the consultation of 2012 version of the proposal for TPM expressed their concern that the beneficiaries-pay principle applied to historical investments would alter the way sunk costs are recovered and, therefore, would give rise to economic inefficiencies. See Electricity Authority, Transmission pricing methodology: Sunk costs, 8 October 2013. See also Competition Economists Group, Transmission Pricing Methodology Economic Critique, February 2013, 8, and Mighty River Power, Mighty River Power submission to Electricity Authority s transmission pricing methodology: Issues and proposal consultation paper, 1 March 2013, 2.2. 25 11 August 2015
54. In addition, the EA s proposal generates a substantial wealth transfer. For example, under the Base option, the North Island generators contribution would increase by $24 million per year relative to the status quo, while the contribution of Upper North Island mass-market load would increase by $140 million per year. 52 Conversely, South Island generators, Lower North Island mass-market load, South Island mass-market load and large industrial users would pay lower transmission charges under the proposal. 53 In other words, under the EA s proposal, North Island generators and Upper North Island mass-market load will experience a substantial increase in their allocated transmission charges, to the benefit of the other market participants. Figure I below shows total charges (excluding LCE and connection charges) 54 under the EA s Base option and the current TPM. 52 See Transmission Pricing Mechanism Review, Table 14. 53 The EA estimates an annual reduction in charges relative to the status quo for South Island generators, Lower North Island mass-market load, South Island mass-market load and large industrial users equal to $47 million, $15 million, $27 million and $74 million respectively. See Electricity Authority, TPM options working paper and related documents revisions to indicative modelling, dated 30 July 2015, Table 14. 54 LCE and connection charges are identical in the two scenarios and hence, do not affect the change in charges. 26 11 August 2015
Figure I. Transmission charges under EA s proposal (Base option) vs status quo Excluding LCE and connection charges (in $ million) Source: Electricity Authority, TPM options working paper and related documents revisions to indicative modelling, dated 30 July 2015, Table 15.a. Note (*): The Electricity Authority has excluded some geothermal power plants and some industrial customers from the modelling results in Table 15.a. See Transmission Pricing Review, E.6-E.7. 55. Policies implemented in other countries to address the sunk cost recovery issue may be instructive in identifying potential solutions for New Zealand. As we show in Appendix A, in countries like Argentina, sunk costs attributable to historical investment decisions have been essentially eliminated in the deregulation process in order to avoid distortions. Such distortions and inefficiencies are far from being only a theoretical possibility and are, on the contrary, easy to arise. For example, in Chile the high costs of transmission have led some 27 11 August 2015
generators to bypass the grid, by building their own transmission lines parallel to the main transmission operator. 55 56. In summary, the EA s proposal attempts to include sunk costs under different tariff charges, some of them directly related to assets (deeper connection) and benefits (AoB). These charges will be paid by generators and loads. As long as these charges are applied to existing assets, the proposal fails to implement the minimum distortion principle for sunk cost recovery because: a. Sunk cost recovery through beneficiaries-pay limits rather than widens the user base against which the required revenue is recovered, resulting in incentives for inefficient bypass; b. Dynamic efficiency is not improved by including historical assets on the application of the new charges. VI.1.2 Nodal prices give sufficient signals for location decisions 57. Generators, as users of the transmission grid, should face incremental transmission costs that provide incentives to properly locate. However, as explained in Section IV.1.1 above, nodal prices have been designed so as to give the proper short-run signal incentives for location decisions to generators and loads because prices reflect losses and constraints at each point in the network. 58. As long as nodal prices are properly set, both load and generators have the rights signals to make efficient location decisions and, therefore, should not be affected by the way sunk costs are allocated. In other words, the allocation of sunk costs would generate a distortion if it alters generators location decisions made following properly set nodal prices. 55 This occurred before the 2004 electricity reform in Chile, when generators paid 100% of transmission costs. See Pollit, M., Electricity reform in Chile: Lessons for developing countries, September 2004, p. 18. 28 11 August 2015
59. In countries that do not apply a full nodal pricing system, though, prices may not give enough signals for efficient location to generators. This is the case, for example, in Australia and the UK. These countries do have additional locational charges, although in Australia these only apply to load. 60. This is not the case of countries with full nodal system, such as New Zealand, where the LCE charge accounts for losses and constraints of the transmission grid. 56 Additional charges based on location may, therefore, distort location decisions. For example, the current HVDC charge applied only to South Island generators may incentivize inefficient investments in generation in the North Island only to avoid paying the charge. 61. This does not mean that generators should not contribute to sunk cost recovery. Instead, the allocation of transmission sunk costs to generators has to be independent of their location. VI.1.3 Generators are users and should contribute to sunk cost recovery 62. Both generators and loads are users and beneficiaries of the transmission network. As such, they should both contribute to the recovery of transmission costs. The EA s proposal includes a residual (postage stamp) charge to be applied only to load. The EA argues that excluding generation from the residual charge would improve efficiency because: 57 a. A residual charge based on capacity would be disadvantageous to generators with low capacity utilization (such as back-up or peak generation). b. Generators would be able to pass-through the charge to customers and, therefore, it would become a variable charge, which would generate distortions. 58 56 Other examples where full nodal prices are applied are Argentina and Chile. 57 It is worth noting that the 2012 version of the proposal included a residual charge that would be shared equally between load and generation. See Transmission Pricing Mechanism Review, 6.98-6.100. 58 The EA argues that pass-through would be possible because all generators would be subject to the charge and would need to recover their costs. 29 11 August 2015
63. As we show below, the EA s concerns have no merit. Low utilization generators do not have to be particularly disadvantaged by a move to a minimal distortion TPM. Furthermore, generators will, for the most part, be unable to pass-through fixed costs to final users. Thus, the EA has not provided any valid argument for why generators should not be charged. On the other hand, we have already explained in Section III.3 the potential distortions from a residual charge that reduces the base on which the tax is applied. The residual charge paid only by loads would probably materialize in incentives for distorting consumption, investment and uneconomic bypass. 59 Although embedded generation could be economically reasonable for very large loads, it would probably not be so for most of the customers. 60 64. The international practice on this issue is mixed. Australia is one example where sunk cost recovery is based on charges exclusively applied to loads. 61 In other jurisdictions, sunk cost recovery is based on charges levied on both generators and loads. 62 59 Since transmission charges are pass-through costs for distribution companies, high transmission charges applied to loads will eventually result in higher energy prices for end consumers. Note that the current interconnection charge paid only by loads has the same defect. 60 Embedded generation could take the form, for example, of inefficient solar or wind systems built for houses or buildings, or may appear within distribution networks, thus, reducing the overall demand faced by line companies. The current prudent discount policy is intended to prevent this type of uneconomic bypass by reducing transmission charges for a customer with a viable bypass project to a level such that the customer is indifferent between developing and not developing the project. The prudent discount, however, shifts transmission costs to other loads, further exacerbating consumption inefficiencies elsewhere. 61 As transmission charges to loads might turn out to be excessive, the Australian charging system is complemented by a prudent discount policy by which large loads directly connected to the grid may apply for a reduction in its postage stamp charge. Although this policy could mitigate bypass incentives, it has two disadvantages compared to the wide base rule. First, line companies are not eligible for the discount and, therefore, excessive transmission charges would result in excessively high electricity prices to end consumers. Second, it promotes inefficient investment in searching for alternative projects. 62 In the UK, charges are based on capacity and are allocated 27% to generators and the remaining 73% to loads. In Norway, a residual charge is applied to generators and loads. On average, generators pay between 25% and 35% of network costs, while the remaining is allocated to loads. In Chile, sunk costs, together with operation and maintenance fees are collected from both generators (80%) and loads (20%). In this case, the allocation within generators and loads is based on the marginal participation methodology, which takes into account the marginal effect of each user on line flows. 30 11 August 2015
65. Despite this mixed evidence, in order to minimize the distortions from sunk cost recovery, the proposed residual charge should include both loads and generators, as a wider base would reduce the charge for each individual user, minimizing the potential for inefficient bypass or disconnection decisions. VI.1.3.a A postage stamp charge would not be disadvantageous for low profitability generators 66. The EA argues that a postage stamp charge based on capacity may discourage investment on plants that generate small rents (such as a thermal peaking plant), which are necessary for sectorial efficiency. In spot markets, however, small thermal plants are usually called to generate only at peak times, when their bids (not including the postage stamp charge) set the spot price. If, however, the system operator fears that transmission charges would lead these generators to shut down, it could design specific contracts in which the postage stamp charge is part of thermal peaking plants operational and maintenance costs, so as to guarantee their supply. 63 Must-run generation plants could face a similar problem, as their remuneration, which only covers operation and maintenance costs, does not include transmission charges. In the same way, the system operator may need to write specific contracts with must-run plants, including the postage stamp charge. VI.1.3.b Generators would not pass-through postage stamp charges to customers 67. The EA argues that a residual charge applied to generators based on capacity would be passthrough to customers and would, therefore, become a variable charge, losing the incentive neutrality of the postage stamp charge and introducing distortions in consumption decisions. 68. The proposed residual (postage stamp) charge, however, would be a fixed cost for generators, driven by capacity and not by dispatching decisions. Generators bids, however, and hence, 63 As long as the tax base of the postage stamp charge is sufficiently large, however, the effect on quasi rents should be small. 31 11 August 2015
the spot price, are not determined by generators fixed costs, but rather by marginal costs considerations. An increase in the generator s fixed costs produced by the application of the residual charge would not be passed through to consumers and, therefore, would have no effect on energy prices. 64 The only effect of the residual charge would be the reduction of the generators locational rents, which would be used to cover transmission costs. 65 69. On the contrary, as explained by the EA, the transmission charges on loads (including the postage stamp) would be passed through to final users via higher distribution charges, eventually increasing retail prices faced by mass-market (non-industrial) consumers. 66 Hence, adding generators to the postage stamp charge base would reduce the actual transmission charges paid by line companies, decreasing retail prices. We will explain this effect in Section VII. VI.2 IMPACT OF THE EA S PROPOSAL ON CURRENT RETAIL PRICES 70. The EA s proposed change in the TPM is not neutral with respect to retail prices. 67 We use the EA s simulation results to show the impact that the increase in the transmission charges paid by line companies that results from the EA s proposal would have on retail prices, compared to the status quo. Table I below shows the change in transmission charges paid by loads and generators under the EA s proposal. 64 There is a way in which the residual charge applied to generators could have an impact on consumers prices. This would be the case if generation plants chose to close down or not develop because transmission charges become too high. In that case the spot price would increase. As long as the tax base of the residual charge is sufficiently large, however, this effect will be of minimal importance. 65 Since new entrants would enter only if spot prices cover all costs, there could be a small long term impact on prices. As long as future investments are hydro, which have locational rents, the impact would be minimal. Other types of renewables, such as wind farms may be more affected. 66 See Transmission Pricing Mechanism Review, 6.101. 67 The EA actually estimates that retail prices faced by residential consumers would increase by 10% in some regions, by 4.5% in a second set of regions and would decrease by 2% in a third group of regions. See Transmission Pricing Mechanism Review, F.8. 32 11 August 2015
Table I. Difference between annual transmission charges by user: EA s proposal vs status quo Forecasted 2017-2019 Source: Own elaboration based on TPM options working paper and related documents revisions to indicative modelling, dated 30 July 2015, Table 14. 71. The EA estimates that transmission charges paid by line companies would increase by $98 million per year under the proposal as compared to the status quo. We show below the impact of this increase in transmission charges paid by line companies on retail prices. To do so, we divide the estimated increase in transmission charges to load customers on two measures of electricity consumption: total electricity consumption and non-industrial electricity consumption. 33 11 August 2015