Submission: Second Issues Paper Transmission Pricing Methodology; issues and proposal

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1 ENERGY TRUSTS OF NEW ZEALAND INC. P O Box Newmarket Auckland 1149 Phone: (09) July 2016 Electricity Authority Wellington submissions@ea.govt.nz Submission: Second Issues Paper Transmission Pricing Methodology; issues and proposal As the organisation representing consumer and community owners of EDBs, the Energy Trusts Association (ETNZ) has both an asset owner and a consumer perspective in addressing this topic. We have a number of observations on the economic justifications for change put forward in the issues paper. Notably, we believe that the failure to recognise the primary regulatory requirements relating to incentives for energy efficiency and demand-side management in the Commerce Act is a fundamental flaw in the rationale provided for the proposed TPM. 1. Regulatory consistency and regulatory mandates Background: governing legislation The allocation of transmission charges and the mechanisms for passthrough of those charges are relevant to the pricing approaches adopted by electricity distribution businesses (EDBs) that are regulated under Part 4 of the Commerce Act. Section 54Q of the Commerce Act requires the Commerce Commission, in the context of its requirement to develop price-quality paths, to promote incentives, and avoid imposing disincentives, for suppliers of electricity lines services to invest in energy efficiency and demand side management, and to reduce energy losses. The relationship between the Commerce Commission and the Electricity Authority s precursor (the Electricity Commission) with regard to s54q was acknowledged in the 1

2 13 November 2008 memorandum of understanding between the two industry regulators, headed Protocol on improving incentives for electricity businesses. More recently, the December 2010 Memorandum of Understanding between the two regulators acknowledges the purpose of the Commerce Act to promote outcomes that give suppliers incentives to upgrade and invest and incentives to improve efficiency.. The Authority undertakes [para 15 b)] to take into account the pricequality paths set by the Commission in relation to suppliers of electricity lines services and, where overlaps occur, both regulators recognise that Solutions to issues need to be consistent with the roles and mandates of each party. It seems clear that there is no justification for one regulator to develop policies that negate the goals of the other regulator, and this is the intent of the liaison process that has been set up between the Authority and the Commission. Section 54Q took effect from 1 April 2008, preceding the Electricity Industry Act 2010, and was not amended at that point to recognise any overlapping role that the latter Act might have created for the Electricity Authority. Accordingly, it is the primary legislative requirement underlying regulatory incentives and disincentives for EDBs investing in the activities it identifies. Relevance to the proposed residual charge We note the comment (para 115 of the issues paper) The residual charge has been designed to minimise the incentives on transmission customers [essentially EDBs and a few direct connects, as the Authority is not proposing to apply the residual charge to generators] to invest in more costly alternatives to avoid the charge. This design approach contrasts with the purpose of s54q, which is to provide incentives and avoid disincentives for such behaviour. An incentive is needed where a more costly alternative that delivers the results sought by s54q is available, but is not being pursued because of its cost. Essentially, the Authority is arguing that EDBs and their customers should not have an incentive from the TPM to undertake investments in demand side management or technology such as rooftop or localised solar that reduce their demand for energy from remote generators, reduce the energy losses associated with shortened transmission distances/reduced transmission loads, or to invest in energy efficiency and demand-side management. 2

3 We recognise the requirement the Authority has to ensure that the TPM allows Transpower to recover its costs. To do this, without undermining the s54q requirements, the Authority needs to consider a design modification. One option is to load 50% or more of the residual charge onto transmission-reliant generation. As long as such generation faces at least half the cost of moving its product to the point where it competes with demand-side options it could be argued that incentives and disincentives are balanced. Alternatively, it would seem even more reasonable to load 100% of the residual charge onto grid-reliant generation, on the basis that forcing EDBs and consumers who are interested in demand-side options to pay for the services remote generators require to bring their product to the point of competition is in breach of the s54q requirement not to impose disincentives. Relevance to prudent discount policy and other proposed TPM elements Here we note the comment (para 2.38 of the issues paper) The TPM states that the purpose of the PDP is to help ensure that the TPM does not provide incentives for uneconomic bypass of existing grid assets, and that the PDP aims to defer investment in alternative projects that would allow a customer to reduce its own transmission charges, while increasing economic costs to New Zealand as a whole. This same theme recurs throughout the TPM issues paper, applying to most aspects of the proposed methodology. The Authority is proposing to extend the PDP to cover instances where transmission customers may undertake wasteful activity and, as a result, increase charges to other transmission customers. Parliament s intention in approving the inclusion of s54q in the Commerce Act was to promote what it perceived as the overall benefit to New Zealand by creating incentives for investment in energy efficiency and demand-side management through the emergent phase of the relevant technologies. In contrast, the Authority s proposals for the PDP etc. fail to acknowledge that intention, and (in the case of the PDP) specifically create a mechanism for the suppression of such technologies by allowing Transpower to target discounts at parties that pose a competitive threat to grid-reliant generators. The argument put forward in the issues paper, that this approach discourages investment in alternative projects that would increase economic costs to New Zealand as a whole, is second guessing 3

4 Parliament s views on beneficial investments. The intent of s54q is to push the electricity industry towards investment in such alternatives because, in the longer term, this is regarded as the right path to take in order to maximise the economic and environmental outcomes, despite any early economic costs associated with start-up industries. The PDP, as proposed, is another example of a mechanism that creates a disincentive for the outcomes sought in the Commerce Act, defeating the purpose of s54q. Relevance to the proposed reallocation of the HVDC Charge The issue paper notes (para 6.11) the HVDC charge [at present] creates inefficient incentives to locate generation in the North Island. This is because the HVDC charge is paid solely by South Island generators. Regardless of the assumptions involved in defining inefficient here, we also note that the existing HVDC Charge provides some incentive to demand-side options etc. in the North Island areas where demand growth is occurring. It would seem appropriate to at least consider the impacts on the s54q objectives of any changes to the HVDC allocation arrangements. 2. Area of Benefit cost allocation The cost-benefit model used by Oakley Greenwood appears to load 60% of the future Transpower capex charges onto load (essentially EDBs) and 40% onto generators. This seems economically inefficient for a number of reasons. While this allocation may not be designed flow through directly into the actual Area of Benefit charge, we assume that it will be captured in the final TPM as developed by Transpower. It this is not the case, then it should not be used in the CBA, as it will lead to misleading conclusions on the net benefit of the proposed changes. First, a 60/40 split waters down the process of correcting the current residual charge imbalance, where load pays the lion s share of transmission costs. In other words, this transitional compromise is not fully phased out as quickly as it could be. Parties considering investments that become rational once the imbalance between generator and load pricing burdens abates will delay or modify those decisions accordingly. Second, it plays favourites among the two parties (generation and load) on each side of a commercial transaction. Basically, it gives generators less of a drive than loads to minimise new transmission capex. 4

5 3. Static and dynamic reactive support cost allocation The issues paper states that The need for reactive support equipment arises because transmission customers and their downstream customers are using power in a manner that results in a poor power factor for other transmission users. The TPM proposals provide for the development of a kvar charge to address this, if this is considered efficient at some point. We suggest that the Authority give some thought to the parallels with other producer-delivery chain arrangements when considering who should pay for power factor correction. This is becoming increasingly relevant as distributed generation emerges as a competitive threat to Grid-reliant generation. Typically, in market situations a supplier is expected to provide a merchantable product at the point of sale. For example, a supplier of frozen vegetables has to factor in the costs of refrigerated transport in getting them to the point where they compete with fresh vegetables. Similarly, where a generator uses the transmission system to bring its product to market it would seem reasonable, and consistent with normal market behaviour, for that generator to meet the costs associated with maintaining its product in a merchantable state. (We note that this was once the case, with the then generation monopoly ETNZ using equipment at one of the since decommissioned Marsden power stations for power factor correction on the transmission system.) On a more positive note, we support the Authority s shift of stance on the reduction of the power factor minimum to This is a sensible and realistic move that the distribution industry has advocated for some years. 4. Materiality The Oakley Greenwood CBA indicates a net present value in the $210m-242m range (i.e. an average of around $12m/year). How much of this benefit would flow through to customers annually depends on many imponderables, such as the timing of investments, and the strength of competition in the energy markets. We are concerned that the modeling does not seem to question whether the benefits assumed from post-2004 transmission investments are tangible. In our view it would be appropriate to treat a 5

6 significant proportion of the capex involved as an imprudent investment that should not be recognised in the CBA. Given the relatively small annual net benefits identified in the CBA, vs the overall annual Transpower charges of around $1 billion-plus over the modeling period, and the apparent failure to write down (for CBA modeling purposes) significant imprudent post-2004 investments or to recognise the uncertainties associated with imperfect energy market competition, it is questionable whether a reasonable case has been made for undertaking the costly and disruptive development work envisage in restructuring the TPA. Concluding comment Ultimately, the biggest losers from the proposed changes to the TPM seem likely to be (mainly) domestic consumers, who'll face a real wealth transfer representing the Net Present Value of the 10% additional share of Transpower's $970m+ annual bill that is being transferred to distributors, over the 20-year life used in the cost-benefit analysis, offset by possibly non-existent benefits that the post-2004 investments in areas such as the Upper north Island have delivered or will deliver and some other efficiency gains. We note that the Authority intends to make its final decision on the TPM proposals on the basis of its primary objective of promoting the overall efficiency of the electricity industry for the long-term benefit of electricity consumers. On this basis, we would expect it to reject the proposals as they stand, and to develop a revised TPM that captures the positive elements of the existing proposals (without creating the disincentives for energy efficiency etc.) and that also addresses the other concerns identified above. As part of that process, it would be useful to have a facilitated discussion with a representative consumer panel involving a range of domestic consumers, as they are the group most likely to feel disadvantaged by the current TPM proposals. Karen Sherry Chair ETNZ 6