What are the benefits from reform of the TPM?

The Authority considers that there is potential for reform of the TPM to better promote overall efficiency, and better promote the Authority’s statutory objective.

This involves facilitating:

  • Efficient investment in the electricity industry through providing incentives so that the right investments occur at the right time, and in the right place. Those investments may be in the transmission grid, generation (including distributed generation), distribution networks or on the demand-side.
  • Efficient operation of the transmission grid, generation (including distributed generation), distribution grids and demand-side management. This means pricing incentives so that the day-to-day operation of transmission, generation, distribution and demand-side management involves an efficient trade-off between reliability and cost.

The Authority considers that the primary focus of the TPM should be on dynamic efficiency, which includes efficient investment and ensuring the TPM is durable. The biggest long-term benefits to consumers will be achieved through improved investment efficiency.

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What is the Authority doing about large potential price increases from the changes?

The Authority is considering whether the proposed new charges should apply to existing and new investments (“Application A”) or to new investments only (“Application B”).

The Authority is considering adoption of the new TPM to new investments only (“Application B”) as a way of mitigating potential large price increases. The Authority is also considering potential transitional arrangements that could be considered under Application A. The Authority is conscious that it needs to weigh up that any arrangements that limit price increases for one party would also limit price decreases to other parties.

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Why do transmission prices increase for Auckland and Northland customers under the options proposed?

These changes do not raise or lower the cost of transmission across the whole country. All that the options do is reallocate the costs. For every plus there is a minus.

Charges to Auckland and Northland do not increase much under Application B. Transmission charges under Application A would be higher for Auckland and Northland consumers but these increases are partially offset by reduced energy costs and improved reliability of supply in those regions (due to the recent grid upgrades serving these regions).

The current TPM spreads the cost of recent transmission investments into Auckland across the whole country. All three options in the working paper allocate costs to the parties or regions receiving more transmission services as a result of those investments. Aucklanders and Northlanders pay more under the three options to reflect the fact that in recent times there has been more than $1.3 billion of transmission investment in the upper North Island to supply consumers in these regions. Also, transmission into Auckland has far greater spare capacity so that Auckland has higher levels of reliability than the rest of the country, which is costly to provide, and Aucklanders are clearly the beneficiaries of that reliability.

Transmission prices make up only 11% of a residential consumer’s bill. So any increase under Application A that occurred in Auckland and Northland transmission prices will not have a big effect on residential consumers in these regions. For example, if the base case scenario from the options working paper were adopted, this is estimated to increase residential consumers’ electricity bills in the Auckland and Northland regions by approximately 4%.

The Authority is considering a range of transition alternatives to manage the effect of any adverse price changes, which are outlined in the working paper. This should mean that any adverse impacts from price changes for Auckland and Northland are not excessive. The Authority would welcome feedback on these transition alternatives.

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Why is the Authority proposing to reduce charges to New Zealand Aluminium Smelters (NZAS) when the Government provided them with a subsidy?

The Authority is responsible for ensuring that transmission pricing arrangements promote 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.

The way transmission charges are currently allocated is not efficient. The bulk of the costs of transmission investment are smeared or socialised across New Zealanders. As a result, consumers in Southland for instance have helped pay for the recent $1.3 billion dollar transmission investments in the Upper North Island. Yet they have not caused this investment, nor do they benefit much from it.

There is no reduction in charges to NZAS under Alternative B. The options the Authority proposes under Application A promote efficiency because parties or regions pay for the cost of providing transmission services to them, rather than the costs being spread across the country. Accordingly, under Application A the prices for consumers in Southland, where there has been little recent transmission investment, will fall relative to what they pay now. This outcome is efficient. It is not a hand-out. Conversely, if there becomes a need for new transmission investment in Southland, then consumers in those regions would pay for it, not those in Auckland or Northland.

Note that if the Authority were to implement one of the transition alternatives outlined in the paper, the price reduction to NZAS and Southland consumers would be reduced and/or delayed depending on the option chosen. This is a consequence with any transition, as the costs of the transition still have to be paid for, so those that would otherwise experience a price reduction do not experience the full benefit of the change.

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Why is the Authority following an approach that will result in high charges for the West Coast, a region whose economy is experiencing difficulties?

There are no increased charges for the West Coast under Application B. The modelled increase, under Application A, in charges to Westpower reflects recent investments made to serve that region’s demand for transmission services. Under the current TPM, the additional costs are subsidised by other regions.

Under Application A, if the base option from the options working paper were adopted, this is estimated to increase consumer electricity bills in the West Coast region by approximately 9%. This is the result of West Coast transmission investment undertaken to improve the reliability of electricity supply in the region. Previously the network was vulnerable to outages. The investments were also undertaken to meet anticipated demand from new dairy and mining ventures in order to stimulate economic growth in the West Coast region. As this growth is realised, the fixed cost of that investment will be spread across a wider base.

The Authority is considering a range of transition alternatives under Application A that would limit or delay the extent of price increases for areas such as the West Coast, which are outlined in the working paper. This should mean that any adverse impacts from price changes for the West Coast are not excessive. The Authority would welcome feedback on these transition alternatives.

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Why is the Authority considering changes to the TPM when this will adversely impact avoided cost of transmission (ACOT) payments to distributed generators?

The Authority considers there may be circumstances where it is efficient to compensate parties for avoided transmission costs. For example, there may be a case for compensation where a distributed generator causes postponement of a transmission investment (and for the time that transmission investment is postponed, but not indefinitely). However, under the methodology that many distributors currently use to calculate ACOT, the payment is sometimes based on avoided transmission charges, not costs. Under the current postage stamp charge this incentivises investment in distributed generation even in areas where no transmission investment is imminent and advantages distributed generation over grid-connected generation. This is not efficient.

Under the options being considered by the Authority, because a significant portion of charges would be on a capacity rather than energy basis, the opportunity for distributed generation to operate to avoid transmission charges would be much more limited. However, all of the options include elements that provide the opportunity for refocusing ACOT payments, and therefore incentivising distributed generation, to avoiding future transmission costs. In order to support such a change, the Authority therefore has on its work programme a project reviewing the provisions under Part 6 of the Electricity Industry Participation Code (Code) (in particular,) that relate to ACOT payments.

Application B and some of the transition alternatives being considered by the Authority would limit the extent of change to ACOT payments. However, it is important to note that the Authority is intending to review Part 6 of the Code that relates to payment of ACOT so changes may still occur over the longer term even if Application B was adopted for the TPM.

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Why is the Authority’s focus on efficient investment when there are no large investments anticipated in the immediate future?

While there are no large transmission investments planned in the near future, there are in the longer term. Now is the perfect time for getting a charging regime in place that will help to ensure this investment is efficient. Further, as we have seen in the past, transmission investment plans can change quickly as market circumstances change, so it is important that an efficient charging regime is in place if it does.

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Why has the Authority taken so long with its TPM review, particularly given the uncertainty it has created?

The Authority understands that regulatory certainty is important. However, the TPM considerations are complex, and changing the TPM could have sizeable impacts on some parties. The TPM is a highly contentious issue, with deep disagreement among stakeholders when advisory groups have tried to address the issue. The Authority has worked steadfastly through the issues and has consulted on them thoroughly at each stage. A robust consultation process takes time.

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Aren’t there other more pressing priorities for the Authority to consider than TPM?

The Authority has advanced many other priorities, such as improving reliability of supply and enhancing competition in the electricity market. No one familiar with the Authority’s work programme would claim these priorities have been neglected over the period that the Authority has been reviewing the TPM.

The Authority identified that a material change of circumstances has occurred. The Authority then identified problems with the TPM, namely that transmission pricing does not promote efficient investment and efficient operation of the electricity industry.

The Authority is compelled to address the problems it has identified to ensure that the TPM promotes the Authority’s statutory objective.

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Why is there a duplication between Transpower’s operational review and the Authority’s TPM review?

There is no duplication. Transpower’s review is narrower in scope and focuses mainly on operational efficiency, while the Authority’s TPM review has a main focus on dynamic efficiency.

Transpower’s operational review is limited to making changes within the existing TPM guidelines. The Authority’s review is not – it is reviewing the guidelines themselves. However, because Transpower’s review is more limited in scope, and because of the process requirements under the Code, Transpower is able to complete its review faster than the Authority.

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Why hasn’t the Authority responded to submissions on the working papers to date?

The Authority has considered submissions on all working papers to date and has published summaries of submissions on working papers.

The Authority will communicate its views on the working papers once the working paper process is completed, which includes the options working paper we released today.

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Has a material change in circumstances been established?

The Authority has considered submissions and is of the view that, under any reasonable interpretation, there has been a “material change in circumstances” which warrants undertaking a review of the TPM. In particular, the Authority observed that there has been more than $2 billion worth of new transmission investment approved since 2006, which has changed the magnitude of the existing TPM’s price signals.

In addition the Authority also considers the following constitute a material change in circumstances:

  • Advances in technology, and the reducing costs of computational power, mean more sophisticated TPM options are now available.
  • The regulatory framework has changed significantly as a result of the Authority replacing the Electricity Commission and the establishment of the new statutory objective.

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Isn’t the Commerce Commission rather than the Authority responsible for investment efficiency?

The Commerce Commission is responsible for assessing whether any particular investment meets the grid investment test (an economic test). The Authority considers that transmission charges have an important role to play in that decision process by supporting the discovery of efficient transmission investments.

This is because the price for transmission services determines parties’ demand for transmission services, which in turn determines the transmission investment required. Transmission charges therefore affect the nature and timing of transmission investment proposals coming before the Commerce Commission for approval.

Where transmission charges do not adequately reflect the transmission services provided to different customers, the timing and nature of transmission investment proposals coming before the Commerce Commission is unlikely to be efficient.

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Has the Authority adequately defined the problem with the TPM?

The Authority considers that the current TPM gives rise to a number of potentially substantive issues. For example, more than $1.3 billion of investment has been approved in the upper North Island since 2006. This has led to an increase in transmission charges of approximately $221 million nationwide, yet charges in the upper North Island have increased by only $87 million. Charges in the other regions in New Zealand have increased to meet the additional revenue requirement caused by upper North Island investments.

The fundamental concern the Authority has with the current TPM is that the current charging arrangements for HVDC and interconnection assets provide inefficient incentives on participants to support the discovery of the most efficient transmission investments; specifically, as a consequence of socialisation of transmission costs and poor targeting of charges under the current TPM. Some customers pay considerably more than the cost of providing them with transmission services while others pay considerably less.

The Authority considers this situation creates inefficient investment incentives because the parties (and regions) receiving the additional grid services have incentives to promote transmission investments in their area even when the full costs exceed the economic benefits likely to be delivered, potentially resulting in more transmission capacity than is economically sensible. It also creates incentives for transmission investment (paid by the entire population) to supplant investment by local distribution networks (paid by the local population) even when the latter is more efficient than the former.

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Is the decision-making and economic framework for transmission pricing fit for purpose or should it be abandoned?

The Authority remains of the view that the decision-making and economic framework provides a valid basis for assessing which charging approaches may better promote efficiency and therefore the Authority’s statutory objective.

While the DME framework provides guidance as to the selection of TPM charging options it does not act as a substitute for a full qualitative and quantitative CBA.

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Have parties had insufficient time to assess the deeper connection option?

If after considering submissions on the options working paper the Authority decides to continue to explore the deeper connection charge, parties will have a further opportunity to submit on the deeper connection charge through the second issues paper.

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Why does the Authority continue to persist with an SPD charge despite the many problems submitters have identified with that charge?

The SPD charge is a feature of only one of the three options in the working paper.

The Authority considers that the SPD charge is adaptable to changes in grid use and is therefore durable. While the Authority accepts that participants may sometimes be able to change their behaviour to minimise the charge, such behaviour should be minimal given the design of the charge. The Authority has also made significant improvements to the model since it was first proposed. In particular:

  • the revised proposal calculates net rather than gross benefits
  • a monthly rather than half-hour cap has been introduced to ensure that more income can be recovered during peak usage times
  • the Authority anticipates including benefits and dis-benefits relating to instantaneous reserves
  • the Authority has further developed its calculation of the cost of unserved energy
  • the Authority is considering changes to the model to allow more recovery in the later years of an asset’s life, when private benefits are generally greater.

The Authority continues to be open to suggestions from submitters on the SPD charge and also other charges it is considering.

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