The impact on Far North households depends mostly on decisions made by Top Energy in response to the Authority’s decisions. At the very most, the Authority’s May 2016 proposal could have increased charges to Far North households by $21 or $87 per year depending on whether avoided cost of transmission payments to distributed generators ended or continued. Decisions by Top Energy could increase this to about $300 per year.
We released on 13 December 2016 a supplementary consultation paper that contains two refinements to our May 2016 proposal that would further reduce the impact on Far North households. If the Authority decides to adopt these refinements then the final electricity bills for Far North households change by an amount between a cost of $40 and a saving of $64, depending on potential changes resulting from the Commerce Commission regime, which could apply from April 2020.
Our modelling shows consumers in the Far North receive lower wholesale electricity prices and higher levels of reliability due to grid upgrades in the upper North Island.
The application of the cap proposed in the supplementary consultation paper, and other changes made in that paper, has resulted in Top Energy’s indicative charges reducing to $6m per year. This compares to a status quo charge of $4.3 million per year.
Top Energy states that the area-of-benefit charge we modelled in May 2016 didn’t take into account that the effect of Auckland’s growth in demand for electricity over the preceding decades would’ve created dis-benefits (ie, reduced service levels) for the Far North. We believe there may be some validity to that point and so we are planning to release modelling on the expected impact of this during the consultation period.
The Authority remodelled Top Energy’s area-of-benefit charges to take into account the impact of the announced 25MW expansion of the Ngawha generation plant. This has the effect of reducing Top Energy’s expected benefits from assets included in the area-of-benefit charge.
Under the Authority’s proposal the aluminium smelter at Tiwai Point would pay transmission charges that reflect the transmission services they receive. The smelter’s charges have increased from $44m to more than $60m in the past seven years. The great majority of this increase is to pay for new transmission investment in the upper North Island that delivers very little additional service to the smelter. The smelter’s actions have not imposed costs which led to these investments. That’s true for Invercargill consumers too; they are currently paying for costs that provide them with no benefit so they’ll see a reduction in their bills.
The reality is that the current TPM is resulting in odd outcomes. Some upper North Island industrial consumers benefit materially from recent grid upgrades but are actually paying lower interconnection charges than before the upgrades. Conversely, the Tiwai smelter received minimal benefits but has faced big increases in charges, adding to the risk of plant closure and job losses.
Most of the South Island is currently paying for North Island transmission investments without receiving the benefit of this investment. This is not about pitting any region against another; it is about making sure the people who benefit from investments in the grid are the ones that pay for them.
The advantage of the Authority’s proposal is that only the parties that benefit from future grid upgrades will pay for them. For example grid upgrades serving only the South Island will not be paid for by North Island consumers. Also, generators will now contribute to upgrades to the main high voltage assets that transport their electricity within each Island (“interconnection assets”). Currently, they pay nothing for these upgrades.
Over time all consumers, including in the Auckland area, will be better off under the Authority’s proposal. This is primarily due to better investment decisions, and better incentives to deploy alternatives to transmission investment, eg local generation and demand response.
The reality is that consumers in the Counties Power area receive lower prices for electricity and higher reliability of supply than would occur without the grid upgrades. It is important to ‘look at both sides of the ledger’ when considering the impact on consumers; that is, look at both the benefits they receive and the amount of the area-of-benefit charge on them. The Authority estimates that, for every $1 of area-of-benefit charge on Counties Power, consumers in the area receive $4.70 of benefits.
More generally, we need to find a solution that creates long-term benefits for New Zealand as a whole. The advantage of the Authority’s proposal is that only the parties that benefit from future grid upgrades will pay for them. For example generators will now contribute to upgrades to the main high voltage assets that transport their electricity within each Island (“interconnection assets”). Currently, they pay nothing for these upgrades.
Over time all consumers, including in the Counties Power area, will be better off under the Authority’s proposal due to better investment decisions and better incentives to deploy alternatives to transmission investment, eg local generation and demand response.
We have seen no evidence to support this claim. In addition, we are proposing a 3.5% price cap which would significantly moderate any price increases for farmers and other consumers.
We are not proposing to increase the total amount of transmission charges collected; we are simply proposing to recover the costs of the grid in a way that is cost-reflective and service-based. This involves collecting the same total amount in a different way than is done now, so that the overall cost is lower over time.
Transpower agrees there are problems with the current TPM. We have taken Transpower’s views on board throughout the development process, and have sought to give greater discretion to Transpower in the proposed refinements to the guidelines released on 13 December 2016.
Our May 2016 proposal also provided for a staged approach. In addition, we’re also now proposing capping arrangements in our supplementary consultation paper.
We’ve given considerable thought to Transpower’s ‘simplified staged’ approach and do not agree it is a lower risk and more durable approach. A fundamental requirement for durability is that only parties that benefit from grid assets are charged for those assets. This does not apply for key elements of Transpower’s simplified approach.
Although Transpower’s approach is simpler than the Authority’s proposal, it isn’t consistent with the Authority’s decision-making and economic framework, and therefore would be easily challenged in the courts.
The TPM has been under review since 2009 and the DGPP review was signalled in 2013. This time period is greater than for any of our other regulatory reforms, and in the past the Authority has been criticised by many parties for being too slow in reforming the TPM.
The Authority engaged an advisory group to advise it on the TPM in 2010/11—which made split recommendations on the key issue—consulted on nine working papers between 2013 and 2015, consulted on options for the TPM three times (in 2012, 2015 and 2016) and is now consulting on refinements to its May 2016 proposal.
The 40 per cent figure is a misunderstanding of our cost-benefit analysis. That analysis assumed investment in new distributed generation would reduce by 40 to 65 per cent. It seems people misinterpreted that as saying 40 per cent of existing distributed generation would shut down. We anticipate that around 6 per cent of distributed generators may close. These are likely to be generators with high operating costs, such as diesel generators.
Renewable power stations, such as hydro and wind, have a low operating cost compared to power stations that require fossil fuels to run, and we would not anticipate many, if any, of these would close.
Introducing the new arrangements in a phased manner provides a ‘soft start’ that removes any security of supply risks. Our decision to retain the DGPPs means any distributed generator that avoids transmission costs will be paid and remain operating during times of peak demand.
The percentage of distributed generators with low carbon emissions is no higher than the percentage of grid-connected generation. Ninety five per cent of new generation will be low-carbon-emission generation, regardless of our proposal.
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