MERIDIAN ENERGY SUBMISSION ON TRANSMISSION PRICING METHODOLOGY: ISSUES AND PROPOSAL CONSULTATION PAPER

Transcription

1 MERIDIAN ENERGY SUBMISSION ON TRANSMISSION PRICING METHODOLOGY: ISSUES AND PROPOSAL CONSULTATION PAPER 1 March 2013

2 TABLE OF CONTENTS EXECUTIVE SUMMARY 4 The Authority s proposal is based on sound principles and analysis 5 The status quo is no longer an option 6 The Authority s proposal for the interconnection charge 7 Support for the SPD charge 8 Recommended changes to the SPD charge 9 Support for the residual charge 10 Recommended changes to the residual charge 11 Cost benefit analysis 11 Embedded generators should be subject to the SPD and residual charges 12 Contract counterparties 12 Loss and Constraint Excess 13 Connection charge 13 INTRODUCTION 14 DECISION-MAKING FRAMEWORK 15 Statutory objective 15 Concern about wealth transfers 16 Consultation Charter Code Amendment Principles 17 Concern about retrospectivity 17 PRINCIPLES UNDERPINNING THE PROPOSAL 19 Decisions about the TPM should be based on analysis and evidence 19 HVDC and HVAC assets should be treated consistently 19 Charges should not exceed private benefit 23 CONNECTION CHARGE 24 Problems with the connection charge 24 Proposal for connection charge 25 PROBLEMS WITH THE HVDC AND OTHER INTERCONNECTION CHARGES 26 Key points 26 Response to questions 26 PROPOSAL FOR INTERCONNECTION CHARGE 31 Key points 31 Authority s proposal for the interconnection charge 33 Codifying loss and constraint rentals 33 Beneficiaries pay the SPD charge 34 Support for the SPD charge 34 SPD charge recommended changes 37 Assets subject to SPD 38 Billing cycle 40 Revenue capping period 41 Improving transparency and reducing discretion 41 Postage stamp residual charge 42 Support for residual charge 43 Recommended changes to residual charge 44 Meridian Energy Submission 1 March

3 Embedded generators 46 Contract counterparties 47 Summary SPD and residual charges 48 Prudent discount policy 49 Alternative approaches 50 Is the Authority s proposal consistent with its statutory objective? 53 Economic value accounts 54 CHARGE FOR NETWORK REACTIVE SUPPORT SERVICES 55 COST BENEFIT ANALYSIS OF THE OVERALL PROPOSAL 57 Key points 57 The status quo must be changed 58 The Authority s proposal for the interconnection charge is more efficient than the status quo 58 Greatest benefit will be stronger incentives to scrutinise transmission investment 60 Substantial gains also to be made from more durable TPM 62 Authority s cost benefit calculation 62 Static inefficiencies will be reduced by Meridian s modified proposal 64 PROCESS, TPM GUIDELINES AND DEVELOPMENT OF TPM 67 Materiality of changes 67 Process for developing and approving TPM 67 TPM Guidelines 68 Process for Transpower to develop the TPM 69 Meridian Energy Submission 1 March

4 EXECUTIVE SUMMARY 1 Developing a transmission pricing methodology (TPM) which meets the Electricity Authority s (Authority) statutory objective is a difficult problem, with no one right answer and many trade-offs to be made. 2 Issues with the current TPM have been thoroughly analysed, alternatives assessed and debated and the extent of efficiency problems with the status quo have been quantified. It is important that now the Authority has identified that efficiency problems exist, that these are dealt with in a principled and durable way. As Professor Evans states: To maintain the status quo after this examination of the evidence and the consequent conclusions would not be in accord with the Act and would signal lesser commitment to its objective. 1 3 Meridian Energy Limited (Meridian) supports the general direction set out in the Authority s proposal. This is principally because it resolves the standout problem with the current TPM, which is the arbitrary and inefficient treatment of the HVDC link and the large disparities between who benefits from the link and who pays. Resolving this core problem will be a great improvement over the status quo, and will result in substantial efficiency gains that will benefit electricity consumers over the long term. 4 Meridian considers that the use of the Scheduling Pricing & Dispatch (SPD) model to determine who benefits from transmission and by how much is a constructive approach that breaks down the historical and unsubstantiated arguments around who uses and benefits from the national grid. In particular, it coherently deals with changes over time in load and generation in a principled way that is far preferable to estimating the impossible, i.e. who will benefit into the future from an asset with a life of fifty years. 5 Meridian is aware that a number of parties have concerns with the proposal. In particular, the degree of uncertainty associated with the SPD component of transmission charges and the general complexity involved with its implementation. 6 Meridian believes that it can manage the complexity and any uncertainty associated with the Authority s proposal. 7 However, others do not necessarily share our confidence. Having listened to their views in particular those of smaller participants (including those of our subsidiary Powershop) we are concerned that the complexity and uncertainty inherent in the proposal will be difficult for small participants to understand and manage and may create barriers to entry, particularly for new retailers. These outcomes would be undesirable for competition in the retail electricity market and could reduce the degree of efficiency gains that are achievable from a new TPM, and have been achieved by the retail market reforms to date. 1 Professor Lewis Evans, NERA, The question Is the proposal from the EA more efficient than the status quo (1 March 2013), p. 3 (Evans Report). Meridian Energy Submission 1 March

5 8 Our submission therefore focuses on providing feedback where we consider simplifications can be made to the proposal that: 8.1 maintain the general approach of treating all assets consistently; 8.2 implement a beneficiaries pay methodology; and 8.3 provide a more predictable, less complex and lower risk starting point. 9 Meridian believes that if the Authority is willing to consider simplifications to its proposal, the concerns of a number of parties can be addressed by making transmission charges more predictable for retailers and consumers. This will have the added benefit of reducing implementation risks and administration costs. 10 Like the Authority and hopefully all stakeholders Meridian s objective is to achieve a more efficient and durable solution to the TPM problem. We think that a simplified proposal will place the realisation of this objective within reach through combining the essence of the Authority s proposal with modifications that will assist efficient market operation. The Authority s proposal is based on sound principles and analysis 11 Meridian has long advocated for transmission pricing decisions to be principled, and to be based on sound evidence and analysis. Meridian believes the principled basis of the Authority s proposal is one of its main advantages, and the key to a durable TPM. 12 The two key principles underpinning the Authority s proposal are: 12.1 the HVDC and HVAC assets should be treated consistently (this has been achieved by folding the HVDC into the interconnection charge). There is no evidence demonstrating that HVDC and HVAC assets perform different functions, deliver different benefits, or are different in any way that is relevant to transmission pricing in other words, the previous decision to treat the assets differently was arbitrary. Different treatment results in considerable inefficiencies which, if different treatment continues, will persist regardless of the pricing methodology. The first step in designing an efficient TPM is to remove the arbitrary distinction between the assets and fold HVDC charges in with the rest of the interconnection charges; and 12.2 parties should not pay more than their private benefit. This principle is fundamental to an efficient pricing methodology and Meridian strongly supports the Authority s commitment to it. 13 Meridian believes that these key principles provide a sound basis on which to develop the TPM, and should not be departed from. 14 The risks of basing decisions on assertion and widely-held but mistaken belief are clear. The inefficient current HVDC charge was implemented on the basis that South Island generators were the main beneficiaries of the link, but as the Authority notes to date there has been little rigorous analysis to support the assertion that Meridian Energy Submission 1 March

6 South Island generators are the beneficiaries. 2 Now, the Authority has conducted the necessary rigorous analysis, and that position has been conclusively shown to be incorrect. The beneficiaries of the HVDC are in fact widespread (as they are with many other components of the transmission system). The status quo is no longer an option 15 There is now a bow-wave of evidence that shows that the current TPM is inefficient. We believe there is a near-consensus that the status quo can no longer be a part of a modern and efficient electricity industry. 16 In particular, the question of whether the HVDC charge is inefficient has been settled. The Authority has assessed the inefficiencies of the current HVDC charge at $30m PV. 3 The magnitude of this inefficiency is material, and a compelling case to change the HVDC charge has now been established. 17 The analysis of TPAG complements the Authority s assessment. This analysis found that the current HVDC charge causes an efficiency loss of between $31m and $57m PV. 4 The fact that two independent analyses have established the current HVDC charge to be materially inefficient is conclusive in this context. 18 Meridian endorses TPAG s and the Authority s analysis of the inefficiencies of the current HVDC charge. 19 Further, Meridian agrees with the Authority that there is a large mismatch between the private benefits of the HVDC link and HVDC charges. 5 Meridian has carried out two pieces of analysis into the private benefits associated with the HVDC link, in 2007 and in early The results of those analyses were: analysis: the impact of expanding HVDC capacity (from single pole MW to bi-pole MW) and applying the current TPM would result in a private detriment to Meridian in the order of $1 billion; and analysis: the private detriment to Meridian from the HVDC upgrade to pole 3 and applying the current TPM is between $300m and $900m. 20 While the precise results of Meridian s and the Authority s analysis differ, both have clearly established that, under the current TPM s approach to allocating HVDC costs, South Island generators would be allocated a substantially greater cost than the private benefits they receive from the HVDC link. 21 What is not made as clear as it could be in the Consultation Paper is that the overriding cause of the mismatch problem is the different treatment of the HVDC 2 Consultation Paper, para C Consultation Paper, para TPAG Transmission Pricing Analysis, Report to the Electricity Authority (31 August 2011), para 23 (TPAG Report). 5 Consultation Paper, para Meridian Energy Submission 1 March

7 and HVAC. Large efficiency gains can be captured simply from folding the HVDC charge into the interconnection charge Meridian also recognises that other parties have legitimate issues with the interconnection charge status quo which has stressed its durability. In particular, some South Island consumers have legitimate concerns about paying too much for North Island grid upgrades, which they see as providing little or no benefit to them. 23 The results of the application of the Authority s SPD method show South Island consumers concerns to be justified. A significant mismatch between HVAC interconnection charges and private benefits is therefore also present. As this is the same problem that has been identified for the HVDC charge, and the estimated inefficiencies are material, Meridian agrees that a change to the status quo should be made. The Authority s proposal for the interconnection charge 24 Meridian supports the Authority s general approach for the interconnection charge, which consists of the following elements: 24.1 codifying the current arrangements for the treatment of loss and constraint excess (LCE); 24.2 use of the SPD model to set beneficiaries pay charges (the SPD charge); 24.3 a postage stamp residual charge that is charged far and wide i.e. to generation and load; and 24.4 refining the prudent discount policy. 25 While Meridian believes that the Authority s proposal is a substantial improvement from the status quo and will deliver efficiency gains, we propose that the Authority considers some simplifications, summarised in the table below. Our rationale is set out in the paragraphs that follow. 6 Evans Report, p. 12. Meridian Energy Submission 1 March

8 SPD Element of proposal Assets included in SPD charge Electricity Authority s proposal Current: Since May 2004 all >$2m plus Pole 2 Going forward: >$2m Meridian s simplified proposal Current: Pole 2 & 3 HVDC, NIGUP, NAaN, Wairakei Ring Going forward: >$50-100m Billing cycle Monthly ex post Annual ex ante Time period for benefits capping Residual (postage stamp) charge Half hourly Longer time period (i.e. weekly or monthly) RCPD / RCPI split 50 RCPD / 50 RCPI 75 RCPD / 25 RCPI Regions/peaks Contract counterparties Transpower should determine Distributors Option of opting out No opt out Retailers Generators Embedded generators Direct connects Subject to SPD and residual (where distributor has opted out) Subject to SPD and residual No change Subject to SPD. Unclear whether subject to residual Subject to SPD and residual No change Specified in Guidelines RCPI Allocated on MWh RCPD as current Not subject to SPD or residual (distributors pass through) Subject to SPD and residual if >10MW Support for the SPD charge 26 In principle, Meridian supports the SPD approach. Importantly, the SPD charge breaks the deadlock over who is asserted to benefit from transmission assets by employing an objective analytical approach. 27 Meridian agrees that the SPD method provides an acceptable approximation of beneficiaries and private benefits, and supports the proposed SPD methodology. The following two elements of the proposal are important safety valves to manage unintended pricing consequences occurring: 27.1 charges capped at either the revenue necessary to recover the costs of the investment or private benefit; and 27.2 private benefit collared at zero (only positive benefits). 28 Meridian understands that the Authority is not seeking perfection with the SPD method. What is important is that the method provides an acceptable approximation of benefits, and Meridian believes that this is what the SPD method accomplishes (this is especially so when the SPD method is considered against methods used in Meridian Energy Submission 1 March

9 other jurisdictions to measure benefits such as load flow modelling or being fixed in advance in perpetuity). 29 The flexibility of the charge and its ability to adapt to changes in beneficiaries and their level of private benefits is a critical positive element. This feature should contribute to the longevity of the charge, and minimise the occasions for future disputes about who benefits from a transmission investment when circumstances change. 30 In summary, Meridian supports the SPD approach because: 30.1 it is an acceptable approximation of the benefits from transmission assets; 30.2 it correctly identifies that the beneficiaries of the HVDC are widespread; 30.3 it avoids drawing arbitrary distinctions between HVDC and HVAC assets; 30.4 it implements the principle that charges must not exceed private benefits; 30.5 it is flexible and can adapt to changes in beneficiaries and their level of benefit; 30.6 it encourages greater scrutiny of transmission investment; and 30.7 for these reasons, it will lead to efficiency gains over the status quo. Recommended changes to the SPD charge 31 Meridian understands that some parties have concerns over the application of the SPD charge and aspects of its design. These include the number of assets subject to the charge and the volatility an ex-post half-hourly cost allocation may create. To address these concerns, Meridian suggests the Authority considers the following design simplifications: 31.1 Assets subject to SPD: Meridian recommends reducing the number of assets subject to the SPD charge. The assets subject to the charge could be: (a) the largest four investments since May 2004 (HVDC pole 3, NIGUP, NAaN and the Wairakei Ring) plus HVDC pole 2; and (b) for new investments, the threshold for inclusion should be between $50m to $100m rather than $2m; This simplification strikes a pragmatic balance by including the largest and most expensive investments where the main beneficiary (and therefore stability) concerns arise with current assets and where the material dynamic efficiency gains are possible with future investments, while at the same time reducing implementation and administration complexity for Transpower; 31.2 Billing cycle: While Meridian is confident that it can manage any increased volatility in transmission charges, smaller retailers may however find it more Meridian Energy Submission 1 March

10 difficult. To solve this problem while still retaining the essence of the beneficiaries pays methodology, Meridian suggests a change to the billing arrangements. Our recommendation is to shift to an ex-ante yearly billing cycle with charges allocated on the basis of historic market outcomes. A yearly billing cycle would also have the significant advantage of reducing Transpower s costs of processing information (according to PwC s Impact Assessment on the Transmission Pricing Methodology) and mitigating some of the operational pressures on Transpower; 31.3 Revenue capping period: Meridian suggests that rather than revenue being capped in each half hour, a longer capping period should be adopted (i.e. weekly or monthly). The value of transmission investment, especially in the early years, tends to accrue over very short timeframes the investment exists as back up for infrequent and short events (like outages, planned and unplanned). Therefore, to cap private benefits at a half hourly level means the true value of transmission in those peak periods may be significantly undervalued, and less of the value of the asset will be captured by the SPD charge than should be the case. It may even suggest that sunk investments were built too early or on too large a scale given demand growth. Moving the cap to a weekly or monthly timescale allows a better apportionment of costs to beneficiaries; 31.4 Improve transparency and reduce operational discretion: Some aspects of the design of the SPD and residual charges are likely to significantly affect transmission charges for parties in particular, how the counterfactuals in the SPD solve are constructed. Meridian recommends that decisions concerning the design of the SPD and residual charges that have a significant impact on transmission charges be made by the Authority and included in the TPM guidelines rather than left to Transpower s operational discretion. We identify some of the relevant decisions relating to the counterfactual in this submission. Support for the residual charge 32 Meridian supports the residual charge because: 32.1 a residual charge is necessary for Transpower to recover its full revenue requirement; 32.2 a charge like a broad-based tax is the most efficient and least distortionary way to ensure Transpower recovers its full revenue requirement; 32.3 the residual charge is cast far and wide that is, it would apply to generators, direct connect customers, and distributors 7 and this will promote the least distortion to the use of the grid; 32.4 the allocation of residual costs to generators and customers will encourage a broader oversight of the transmission investment process; 32.5 it will promote efficient use of the grid by encouraging efficient avoidance of peak use of the grid; and 7 That is, assuming distributors do not have the option to opt out, as we recommend in this submission. Meridian Energy Submission 1 March

11 32.6 for these reasons, it will lead to efficiency gains over the status quo. Recommended changes to the residual charge 33 Meridian recommends changing the 50 RCPD / 50 RCPI ratio. 34 International practice strongly suggests a greater allocation of a postage stamp charge to load. Many of the jurisdictions assessed in the 2009 Frontier Economics report for the Electricity Commission adopt a 100% allocation to load. 8 Only two of the thirteen jurisdictions surveyed opted for an allocation of 50% or greater to generation. The Authority s 50/50 proposal places it in a small minority. 35 As a general proposition, much of the grid in particular the recent investments in the North Island have been built to meet reliability standards for load customers. In general terms load customers demand higher degrees of grid reliability, drive more transmission investment, and benefit more from it than generation plant. 36 Instead of using an arbitrary ratio, Meridian suggests the Authority use its SPD methodology to create a starting point for the allocation of costs between generators and retailers. This would involve running the SPD method on the basis of the last two years data to determine the proportion of benefits between generation and load. We believe this is likely to be approximately 25 RCPI/75 RCPD, which is similar to the ratios adopted in the United Kingdom, Sweden and Norway. This process could be repeated periodically and the proportion amended to reflect prevailing market conditions. 37 Two other key benefits from increasing the allocation of the residual charge to load are to provide strong signals for peak demand management and to increase the extent of fixed transmission costs flowing straight to consumers rather than through the wholesale energy market. Cost benefit analysis 38 Meridian asked Professor Evans to give his opinion on whether the Authority s proposal would be more efficient than the status quo. In summary, Professor Evans found that: 38.1 the Authority s proposal is more efficient than the status quo; 38.2 the status quo must be changed if the Authority is to act consistently with its statutory objective; 38.3 the Authority s proposal for the interconnection charge (which includes the HVDC) is more efficient than the status quo; and 38.4 whether the Authority s proposal is more efficient than a pure postage stamp charge (i.e. 50 RCPD / 50 RCPI) depends on whether the dynamic efficiency benefits of the SPD charge outweigh the static inefficiencies of the charge. 9 Empirical evidence is needed to assess the balance. 8 Frontier Economics International Transmission Pricing Review (July 2009). 9 That is, uncertainty over the extent of long term efficiency improvements in transmission investment versus potential short term wholesale market distortions. Meridian Energy Submission 1 March

12 39 Meridian acknowledges Professor Evans point that there is uncertainty regarding the balance between static and dynamic efficiency arising from the SPD charge. 40 However, based on the available evidence, it is Meridian s view that the dynamic efficiency gains would more clearly outweigh any static inefficiencies were the proposal to be modified according to Meridian s recommendations in this submission. This is primarily through Meridian s recommended changes reducing static inefficiencies, although we also expect some improvement in dynamic efficiency (for example, from the greater certainty that would result from a shift to an ex ante yearly billing cycle). 41 Further, Meridian agrees with the Authority and Professor Evans that the Authority s proposal (and therefore the proposal modified by Meridian) will be substantially more efficient than the status quo. Embedded generators should be subject to the SPD and residual charges 42 Meridian agrees that embedded generators should be subject to the SPD and residual charges. Given wholesale market obligations begin at 10 MW capacity for embedded generation, Meridian suggests that only embedded generation greater than 10 MW be subject to the charges The current situation is a regulatory anomaly in that embedded generators do benefit from grid (at least from the security the grid provides) but in many cases do not pay for that benefit. At a principled level, if the SPD method shows that a party benefits from the grid, then that party should be charged. Making embedded generators subject to the SPD and residual charges may reduce the otherwise perverse incentives to embed plant behind a GXP where the embedded generator still receives the benefits of being connected to the wider power system. 44 As the proposal stands, we do not see that Part 6 of the Code (Connection of Distributed Generation) will require amendment. That said, given the economics of embedded generation are likely to be affected by the proposal, a review of Part 6 may be justified. Contract counterparties 45 Meridian recommends that distributors and direct connected customers remain as the contract counterparties with Transpower for all load based charges (residual and SPD) and not retailers. 46 Distributors are the only parties with the information and operational capabilities to respond to peak demand signals by managing load within a region. To expect all retailers within a region (such as Auckland) to be able to coalesce to manage peak demand is impractical. In the worst case, this would lead to peak demand being less managed or unmanaged and therefore may bring forward the need for new transmission investment. 47 Additionally, there are well working institutional arrangements between Transpower, distributors and retailers that deal with on charging of transmission and distribution costs. Having retailers as customers under the TPM will significantly increase the 10 Meridian s Te Uku (64 MW) and White Hill (58 MW) wind farms are embedded. Meridian Energy Submission 1 March

13 number of contract counterparties for Transpower and create another degree of complexity and cost for small retailers which again could lead to barriers to entry. 48 Making a change to invoice transmission customers on an ex ante (yearly) billing cycle should also eliminate distributor concerns that an ex post (monthly) billing cycle would increase the likelihood of distributors breaching Commerce Act pricecontrol obligations (since distributors are required to annually forecast transmission charges to pass through to customers, and any deviation from the forecast may result in a breach of the price-path). Loss and Constraint Excess 49 The proposal to codify the LCE arrangements is sensible and Meridian supports it. Connection charge 50 The current connection charge has stood the test of time, and is efficient and stable. However, Meridian recommends that the connection charge should reflect the valuation approach used for price control purposes, where new investment is added at actual cost to a 2011 asset base valuation. Meridian Energy Submission 1 March

14 INTRODUCTION 51 Meridian welcomes the opportunity to submit on the Authority s consultation paper Transmission Pricing Methodology: Issues and Proposal (10 October 2012) (Consultation Paper). 52 In addition to this submission, we submit the report Professor Lewis Evans, NERA The question Is the proposal from the EA more efficient than the status quo? (1 March 2013) (Evans Report). 53 Meridian s contact person for this submission is: Guy Waipara General Manager, External Relations Meridian Energy Limited Tel: Guy.Waipara@meridianenergy.co.nz Meridian Energy Submission 1 March

15 DECISION-MAKING FRAMEWORK 54 The decision to publish new TPM guidelines and to amend the Code to implement a new TPM is a significant exercise of the Authority s powers, and needs to be consistent with the Authority s statutory role and constraints on that power. In this section, we assess the Authority s proposal against its role and constraints, and consider related issues. Statutory objective 55 In early 2012, the Authority consulted on and published its decision-making framework for the TPM. The decision-making framework is effectively the Authority s exposition of its statutory objective as it relates to the TPM. 56 One particular statement in the framework neatly captures the key role of the Authority in relation to the TPM: The Authority is required to ensure the TPM is consistent with its statutory objective to promote competition in, reliable supply by, and the efficient operation of, the electricity industry for the long-term benefit of consumers. 11 (emphasis added) 57 Thus, if the TPM is not consistent with the statutory objective, the Authority is required by law to act to change the TPM. 58 The question of whether the TPM is consistent with the statutory objective is a question of whether it is optimally efficient while also being practicable. This reflects the view of the Authority which did not attract significant disagreement from the industry that the statutory objective can be summarised as requiring the promotion of efficiency, with a primary focus on dynamic efficiency: The Authority considers that the TPM should focus on the overall efficiency of the electricity industry for the long-term benefit of electricity consumers. 12 In regard to the long-term benefit, the Authority considers its primary focus is to promote dynamic efficiency in the electricity industry In light of the Authority s assessment of the status quo and its cost-benefit analysis, which shows the current TPM to be inefficient, the statutory objective leaves the Authority little choice but to act to remove the inefficiencies caused by the status quo. According to Professor Evans: The EA s final decision will affect the credibility of the electricity regulatory regime as well as the performance of the market. The EA has found under its innovative charging regime and accepted under the standard approach that the status quo is less efficient. Thus the EA has found the status quo of the HVDC charge to be dynamically inefficient. Its statutory objective implies that change should take place if decisions are to be in accord with the EIA and credibly foster outcomes satisfying 11 Electricity Authority Decision-Making and Economic Framework for Transmission Pricing Methodology: Decisions and Reasons (7 May 2012), p Ibid, p Electricity Authority Interpretation of the Authority s Statutory Objective (14 February 2011), para A11. Meridian Energy Submission 1 March

16 that Act. To maintain the status quo after this examination of the evidence and the consequent conclusions would not be in accord with the Act and would signal lesser commitment to its objective. 14 Concern about wealth transfers 60 During consultation on the decision-making and economic framework, some parties attempted to revive the wealth transfers issue that the Authority considered in some depth in the consultation on its interpretation of the statutory objective. In its decision, the Authority concluded that wealth transfers were not per se a relevant consideration, but that to the extent that wealth transfers had efficiency effects, those effects would be considered. The Authority s rationale for this view was as follows: 15 The aggregate consumer approach [whereby the Authority considers the net effects on electricity consumers and assesses the benefits to them in aggregate] means the Authority s decisions will be consistent with expanding the size of the economic pie, whereas if direct wealth transfers are included (but indirect wealth effects excluded) then regulatory initiatives can be adopted even when they shrink the pie. If applied consistently, the shrinking pie approach has a long term deleterious effect on electricity consumers and the Authority does not believe that was the purpose or intent of the Act. 61 This view was confirmed by the Authority in its decision on the decision-making and economic framework. The Authority also confirmed that, where wealth transfers had efficiency effects, those effects would be relevant to decisions about transmission pricing Some of the discussion leading into this round of submissions has sought to refocus on wealth transfers and the short term impact on consumers. There has been some assertion that consumers may ultimately pay more for transmission services under the Authority s proposal. 63 Two points are relevant here: 63.1 the only (published) robust analysis conducted on the impact on consumers is the Authority s Estimation of Impact of Authority s TPM proposal on consumer prices by line company area. This analysis shows the near-term impact on consumers to be roughly neutral Excluding two outliers, the potential impact on average retail tariffs by line company area ranges from -5.8% to +2.9% ; 17 and 63.2 in any event, short-term impacts should not be the focus. The statutory objective requires a focus on the long-term benefit of consumers. The leastcost provision of transmission services in other words, the most efficient provision of transmission services is exactly what will be for the long-term 14 Evans Report, p Electricity Authority Interpretation of the Authority s Statutory Objective (14 February 2011), para A7. 16 Electricity Authority Decision-Making and Economic Framework for Transmission Pricing Methodology: Decisions and Reasons (7 May 2012), p Electricity Authority Transmission Pricing Methodology Review: Estimation of impact of Authority s TPM proposal on consumer prices by line company area (6 December 2012), p. 1. Meridian Energy Submission 1 March

17 benefit of consumers. As the Authority notes, 18 a focus on short term wealth transfer effects may have the effect of increasing the cost of transmission services over time, and that will certainly disadvantage consumers. Consultation Charter Code Amendment Principles 64 Although the Code Amendment Principles (CAPs) are not binding on the Authority, it is good regulatory practice to follow them, particularly as they are intended to ensure the Authority s process for Code amendment achieves the statutory objective. Below we assess the Authority s proposal against the CAPs. Principle 1 Lawful CAP Principle 2 Provides Clearly Identified Efficiency Gain or Market or Regulatory Failure Principle 3 Net Benefits are Quantified Tiebreaker 1: Principles 4 8 apply when the cost-benefit analysis of Code amendment options demonstrates a positive net benefit relative to the counterfactual, but is inconclusive about which is the best option. The Authority will weight these principles in accordance with their relevance and significance for each proposal Tiebreaker 2: Principle 9 applies when the cost benefit analysis of Code amendment options is inconclusive that a Code amendment would yield net benefits and there are no options that are small-scale, flexible, scalable and relatively easily reversible. Assessment Yes, the proposal is lawful and is consistent with the Electricity Industry Act. Yes, qualitative and quantitative efficiency gains have been identified. Yes, a cost-benefit analysis has been applied, net benefits have been identified, and key assumptions and sensitivities have been disclosed. No tie has been identified the Authority s option will generate higher net benefits compared to other options. 19 Principles 4 8 do not apply. No tie has been identified the Authority s option will generate net benefits. Principle 9 does not apply. Concern about retrospectivity 65 Another line of discussion leading into this round of submissions concerns what has been termed the retrospective aspect of the Authority s proposal. The complaint is that the interconnection pricing proposal (SPD and residual charges) will apply to investments that have been made in the past, going back to This line of argument is unfounded. 18 Electricity Authority Interpretation of the Authority s Statutory Objective (14 February 2011), para A7. 19 Meridian has proposed a modification to the Authority s proposal (see table, p. 7 of this submission). Meridian has assessed this modified proposal against the Authority s (see table, p. 64 of this submission). Meridian Energy Submission 1 March

18 66 There is nothing retrospective about the Authority s proposal. If implemented, the TPM would only apply to prices going forward. The fact that the new rules would apply to existing investments is irrelevant. What is important is that there is no impact on past prices or previous use of the grid. Nor will there be any re-visit of history that affects future prices. For example, there is no suggestion that the current inefficient charging of only South Island generators for the HVDC would be corrected for by lowering the future charge that South Island generators would otherwise face. 67 A rational investor will not assume that the rules relating to its investment will never change. For example, a property investor in 2013 will take into account the probabilities of a capital gains tax being implemented in the medium term. And investors in electricity generation should understand that future changes to climate change regulation could affect the cost of energy. 68 We suggest that any reasonable electricity industry participant would have anticipated possible changes to the TPM for quite some time, even though the exact implementation was unknown. The principles underlying the Authority s proposal are consistent with transmission pricing mechanisms used in other electricity markets. 69 Regulatory change is often necessary to correct problems with the status quo and is contemplated by the Authority s statutory objective which requires that it pursues efficiency gains. The key is that changes in the rules of the game are principled, made in response to robust evidence of a problem with the status quo, and stakeholders are given a genuine chance to provide their views. This is precisely what is happening in the current TPM review. Meridian Energy Submission 1 March

19 PRINCIPLES UNDERPINNING THE PROPOSAL 70 Taking a step back from the detail, one of the key positives of the Authority s proposal is the sound principles which underpin it. We discuss these principles below. Decisions about the TPM should be based on analysis and evidence 71 In the past, decisions about the TPM have not always been backed by robust analysis and evidence. The current charging regime for the HVDC link is premised on South Island generators being the main beneficiaries of the link but, as the Authority has recognised: 20 to date there has been little rigorous analysis to support the assertion that South Island generators are the beneficiaries. 72 It is only through principled decision-making backed by robust evidence and analysis that a durable TPM can be achieved. A key reason the industry is here now considering a new TPM is that the current TPM was the result of a decision to arbitrarily allocate the costs of the HVDC assets to a small subset of the beneficiaries of the assets that is, South Island generators. Unprincipled and intuition-based decisions simply don t stand up to scrutiny, and lobbying for change is an inevitable outcome of such decisions. 73 Meridian therefore supports the Authority s renewed commitment to making TPM decisions on the basis of analysis and evidence. HVDC and HVAC assets should be treated consistently 74 The central advantage of the Authority s proposal is that it treats the HVAC and HVDC assets consistently. There is no evidence demonstrating that HVDC and HVAC assets perform different functions, deliver different benefits, or are different in any way that is relevant to transmission pricing for the New Zealand power system. 75 Typical arguments made for different treatment are that HVDC power flows are controllable, that HVDC assets connect two specific nodes, that HVDC power flows from South to North, and that HVDC assets connect two groups of beneficiaries South Island generators and North Island consumers. These arguments do not withstand a reasoned and factual analysis. Below we respond to each these points. 76 Power flows across HVDC assets are controllable. However, technologies are also available to control power flows across HVAC assets. These are described as flexible AC transmission systems (FACTs) and they include series compensation, variable frequency transformers and phase shifting transformers. These technologies are used in power systems to control flows across HVAC networks. The adoption of FACTs has also been investigated in New Zealand as an alternative to better utilise the existing transmission capacity in both the North and South Islands. 20 Consultation Paper, para C1.3. Meridian Energy Submission 1 March

20 77 The actual power flows in real time across both HVAC and HVDC assets are not controlled but are an outcome of the same economic dispatch process. The dispatch process incorporates generation offers, demand bids, available transmission capacity and security constraints. The outcome of this process is a least cost generation dispatch profile to meet demand, within transmission and security constraints. Power flowing across all HVAC and HVDC lines is a function of this process. There is no special or different dispatch process for the HVDC link. 78 The HVDC is an interconnector between the North and South Islands. HVAC assets can be, and often are grouped and simulated as interconnected regions across New Zealand. The figure below (Sustainable total energy transfers) 21 from Transpower illustrates this point that New Zealand can be considered and analysed as a group of zones all interconnected with either HVDC or HVAC transmission links. It is also notable that the quantum of expected power flows across the HVDC link is within the range expected across the main HVAC zones. 79 HVAC assets are also grouped together in real time dispatch. Within the dispatch process, some transmission lines are grouped together as group constraints, in particular where security constraints such as voltage stability limits exist in certain regions. The transmission lines from Whakamaru and Huntly into Auckland is one example of where a group constraint exists within Transpower s dispatch model. 80 If HVAC transmission can be grouped into zones and regions for transmission planning and in real time dispatch then it is also possible to simplify the entire power system into demand and generation zones, interconnected by transmission for transmission pricing purposes. 21 Transpower Investing in the Grid Beyond the Catch Up (May 2010). Meridian Energy Submission 1 March

21 81 The next assertion is that the HVDC is different because it supports power flows from the South to the North Island. The figure below (Distributions of Historic half hourly HVDC flows) shows the distribution of actual flows over the HVDC link since While average flows are from the South to the North, there are significant distributions of flows in the opposite direction from the North to South. The trend over this period is that average flows from the North to the South have increased and that these have been significant during periods of low hydrology. MW Flow South-> North Distributions of Historic half hourly HVDC flows ( ) 75-95th % 25-75th % 5-25th % min/max P Flow North-> South The next figure (Distribution of historic half-hourly reference prices) shows the distribution of average prices between Benmore and Haywards over the same period. This graph demonstrates that South flows are associated with higher market prices. Therefore the value of the flow transfers (quantity x price) across the link become even more balanced between the North and South Islands. $450 Received price $ $400 (nominal) $350 Distribution of historic half-hourly reference prices ( ) $300 $250 $ th % 25-75th % 5-25th % P50 $150 $100 $50 $ ,000 HVDC transfers (MW) Flow North-> South Flow South-> North Meridian Energy Submission 1 March

22 83 Previous submissions on this subject have highlighted this point along with the fact that there are HVAC links, such as the lines into Auckland (including NIGUP) where power always flows in one direction. Therefore if power flows are used as the differentiating characteristic, there are far clearer examples in the HVAC network that meet this criterion. 84 The final point asserted is that the HVDC link is different because it benefits only South Island generators. The Authority s analysis in the Consultation Paper has proven that this is incorrect. Using the SPD method, the Authority has mapped the spread of benefits to load from HVDC pole 3 in the following heat map. The heat map shows private benefits in $/MWh for the period 1 July June The heat map illustrates: 85.1 that load benefits substantially from pole 3; and 85.2 that private benefits to load from pole 3 are diffuse. 86 More importantly, the results of the SPD method show that the spread of benefits for the period was 75.2% to load and 24.8% to generation It is time to move on from the mistaken view that treating the HVDC link differently from the HVAC can be justified. There is no rationale, no evidence, and no analysis which supports the distinction. The Authority s proposal to fold the HVDC charge 22 Electricity Authority TPM Presentation for Issues Paper Release (10 October 2012). 23 Ibid. Meridian Energy Submission 1 March

23 into the interconnection charge is a great improvement over the status quo and will deliver substantial efficiency gains. Charges should not exceed private benefit 88 One of the fundamental principles necessary for an efficient and durable TPM is that a party should not be charged at a level greater than its private benefit. This is a principle that has been approved many times in the transmission pricing context by many different parties, 24 and is in line with developing international practice. 89 Meridian is encouraged that the Authority has now committed to this principle, and has carried out the necessary beneficiaries analysis to support its application to transmission pricing. Specifically, the Authority has stated that efficiency requires that beneficiaries should only be charged up to their private benefit The Authority s commitment to the principle consolidates a long standing but unimplemented recognition that it is a necessary condition for the efficiency of a charging regime that a party should not be charged a level greater than its benefit. For example: 90.1 The Electricity Commission has stated: 26 for efficiency and fairness reasons, the Commission does not consider it appropriate to allocate charges to a beneficiary that are greater than its actual benefit And TPAG observed: 27 Most participants would agree, as a general principle, that the parties benefiting from particular grid assets should meet the cost of, and should rationally be willing to pay for, providing those assets where those beneficiaries can be clearly identified and charges can be determined which do not exceed the beneficiaries private benefit. 91 For Meridian, implementation of this principle is the core change that is needed to the TPM, for the Authority s beneficiaries analysis reveals that the current charging regime for the HVDC link is in severe breach of this principle Meridian Energy Submission on Decision-Making and Economic Framework for Transmission Pricing Methodology Review: Consultation Paper (24 February 2012), para Consultation Paper, para Electricity Commission Transmission Pricing Methodology: Final Decision Paper (7 June 2007), para TPAG Report, para Consultation Paper, Appendix C. Meridian Energy Submission 1 March

24 CONNECTION CHARGE 92 Meridian agrees with the Authority that the connection charge is efficient and stable. It has stood the test of time. While some improvement can be made at the edges of the charge, there will be little benefit from wholesale changes. Problems with the connection charge Q3 Do you agree with the Authority s view that the arrangements under the TPM for recovering connection costs are generally efficient? Explain your answer. 93 Yes. In practice, however, the detailed methodology used to determine the asset charges and the averaging of maintenance costs considerably blunts the efficiency of the charging mechanism. A more robust approach (in both longevity and efficiency terms) would be to have connected parties face the full costs of the actual assets used to connect them. In this way, connecting parties are then free to make the actual trade-offs between connection options, the timing around the renewal of assets and whether a Designated Transmission Customer (DTC) or Transpower should own the assets. The current mechanism is very opaque as to what the actual costs of the assets involved are. Q4 What comments do you have about the potential for inefficient outcomes to arise from incentives to shift connection costs into the interconnection charge? 94 As a boundary needs to be established using a methodology that applies across the whole grid, there are always going to be specific instances where the methodology creates inefficient incentives. Given this, the general approach to fixing the classification of the existing assets appears appropriate. However, if due to circumstances outside a DTC s control (such as an investment initiated by Transpower), the DTC s connection assets are incorporated into the interconnected grid, then there should be flexibility for the classification to be changed to reflect the use of the assets. The Authority could determine the change upon application from either Transpower or the DTC. Q5 Do you agree that there is the potential for inefficient outcomes to arise from incentives for connected parties to hold out for connection asset replacement to occur as a grid upgrade rather than under an investment contract? Explain your answer. 95 Yes. This is primarily due to the detailed methodology used. In order for efficient investment decisions to occur the real costs (asset charges and maintenance costs) of each specific asset should be reflected in the charge. The Authority s proposal goes some way to alleviate the issue and is a good step forward. Q6 Do you consider that there are any other problems with the connection charging arrangements under the current TPM? Provide a detailed explanation of the nature and materiality of the problem. Meridian Energy Submission 1 March