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The regulator today published a final decision on how transmission will be charged for, ending a 12-year industry debate. They are expected to deliver about $1.3 billion in consumer benefits over 30 years, mostly from lowering peak-period power costs.
Rob Bernau, the authority's general manager of market design, said that a scenario of the smelter's closure hadn't been specifically modelled, given the uncertain timing, the share of charges that other users would have to pick up and the additional transmission investment that could be required to bring surplus power north.
But he said the cost-benefit analysis undertaken by the authority had allowed for a significant demand reduction from a customer like New Zealand Aluminium Smelters departing the market.
"That means the benefits of the proposal are still there, even if we have a demand reduction of the size of NZAS leaving the market," he said on an industry conference call.
The smelter, the country's biggest electricity consumer, is one of the prime beneficiaries of today's changes. Based on Transpower's projected 2022 charges, the smelter could be about $10 million a year better off.
But that is not nearly enough for the operation - currently under review for closure by majority owner Rio Tinto.
The firm has separately been seeking direction from the Government to require Transpower to consider charging only for the assets it actually uses - under an existing prudent discount policy.
The authority today reinforced that policy with an obligation to cap that discounted charge at the "stand-alone" cost of the service.
Authority chief executive James Stevenson-Wallace noted that the policy amendment was not developed for the smelter and the authority had no idea whether it would be taken up.
Setting charges for a price-sensitive consumer higher than they needed to be could result in their "inefficient" exit from the market.
But he noted that the stand-alone cost had to reflect the full cost of the service provided - not just the cost of "stringing a line."
Transpower now has one year to develop the new pricing system. It is expected to be effective from April 2023.
The new regime aims to charge consumers based on the benefit they receive from transmission projects and will increase costs for many large industrial power users on the North Island but will generally lower costs for South Island generators.
The cost of the high-voltage link across Cook Strait will no longer be met solely by South Island generators - principally Meridian Energy - and a peak-based charge that many industrial users were able to avoid is being removed.
Transpower will be able to charge for regional congestion charges if it believes that is necessary to manage loads in high growth areas like Auckland and Waikato.
Mixed lines impact
The impact on lines companies is mixed, but some of the smaller, more rural firms on both islands face some of the biggest per-customer increases. Transmission generally accounts for about 10% of a household bill.
While the average annual movement is a $19 a year household increase or decrease, Network Waitaki customers face a $41 increase, while customers of Westpower, Whakatane-based Horizon Energy and The Lines Company in Te Kuiti face increases of more than $30 a year.
Vector, the country's biggest distributor and the largest contributor to Transpower's revenue by a wide margin, faces an $8 million increase. Powerco, the second-largest distributor, gets a $4 million reduction, Christchurch-based Orion faces a $5 million increase and Wellington Electricity gets an almost $7 million reduction.
Increases are capped at no more than 3.5% a year, with most lines companies and some generators effectively paying more to cap the costs of the bigger North Island industrial players.
Among generators, Meridian remains the biggest potential beneficiary with a projected $27 million fall in its transmission costs, based on 2022 pricing. Mercury NZ and its geothermal joint venture partners face a collective increase of almost $10 million.
Better price signals are expected to deliver improved decisions on generation investment and remove an effective "tax" on South Island wind projects. Grid-scale batteries should also be used more efficiently - instead of just being installed to avoiding peak-time transmission costs.
Stevenson-Wallace emphasised that the changes are about "resetting" imbalances that had developed under the current transmission pricing model in place since 2008.
During the subsequent decade, close to $3 billion was invested in North Island transmission projects that South Island consumers, and some in the North Island, got little benefit from.
Among industrial consumers, the Tiwai Point smelter remains the biggest beneficiary, with a $10 million reduction based on 2022 charges. That is after the firm contributes about $1 million to help cap the charges of other industrial users.
New Zealand Steel - itself under financial pressure - faced a potential $9 million increase in its transmission costs. Even under the capped scheme, its charges could more than double to $5.7 million a year.
Paper maker Norske Skog could have seen its charges rise from zero to $6.4 million. Using 2022 charges, the firm would still face a $1.4 million bill after the cap.
Stevenson-Wallace noted that the authority had been under pressure from some not to press on with the reform in the midst of the covid-19 pandemic.
But he said the transmission pricing debate had gone on too long already and the country needed better price signals to capture the benefit of falling renewable generation costs and new technologies like batteries, solar and electric vehicles.
"There is no advantage, from our perspective, in postponing this decision," he said.
"We would argue that further delay could potentially worsen the outcome for consumers."
- By Gavin Evans