Rio Tinto, the majority owner of the Tiwai Pt aluminium smelter, announced last Thursday, 9^th July, that it has terminated its electricity contracts with Meridian Energy and that it will close the smelter by August 2021.  This will have a profound impact on the electricity sector which will be felt for years to come.

By Greg Sise, 13^th July 2020

Despite the hit to the economy, particularly in Southland, there will be many who view the closure of the Tiwai Pt smelter, which consumes about 13% of New Zealand’s electricity, in a positive light, with the prospect of lower electricity prices from 2021, the year in which the smelter will wind down its operations and then close.

However, the impact on electricity prices is more complex than one might imagine at first sight, the more so because the grid and generation supply have evolved over almost 50 years on the assumption that the smelter will remain as a ‘sink’ for large amounts of power in the lower South Is.

When the smelter finally closes, demand will fall by about 5,000 GWh per annum relative to today.  But the massive increase in power transfers from the far south to the far north will increase transmission losses on the grid from just over 3% of total generation, initially to at least 4% on average, reducing the net reduction in generation to around 4,600 GWh per annum.

The thermal sector, those generators that burn coal, gas or oil, collectively generates around 7,000 GWh per annum, more in a dry year and less in a wet year:  this will fall by around 65% when Tiwai closes, and it will impact particularly on Genesis Energy and Contact Energy.

The sector is currently around 85% renewable, but this will initially rise to around 94%.

Spot prices across the country will fall on average across wet and dry years, but more so the further south on the grid that one goes.  The falls in the first few years will be measured in whole cents per kWh as opposed to fractions of cents per kWh, but will vary from year to year depending on storage in the hydro lakes, how much demand grows, and where demand growth occurs.

A very rough indication of the impact on spot prices was given during lockdown, as shown in the chart below.  The shaded area shows the total daily demand from the grid in GWh, averaged over seven days, along with the daily average spot prices in Auckland and in the centre of the South Is. 

This is not a directly comparable situation because Tiwai continued operating during lockdown, so most of the loss of demand was in the North Is;  because the loss of demand was even larger than the impact of Tiwai closing;   because when Tiwai goes, the losses will be higher than they are now;  and because when Tiwai closes some of the plant that was available during lockdown is likely to be retired early.

Nevertheless, demand fell by about 16% by the first week in April, relative to what it was just prior to lockdown, but spot prices fell by 46% on average over the same period, or about 4 cents per kWh.  So as I stated above, what we can take from this is that the initial drops in spot prices, on average over wet and dry years, will be measured in whole cents per kWh, not fractions of cents per kWh.

 

During wetter years there will be restrictions on how much power can be exported from the lower South Is, so spot prices in the lower South Is will collapse during these periods.  Transpower is going ahead with grid upgrades which will allow generation at Manapouri, Roxburgh and Clyde during wet periods to be transmitted to the southern end of the inter-island HVDC link, and hence to the North Is, but this will only be completed in 2023.

Over time, thermal plant that is no longer needed will be retired early, possibly as early as 2021.  New generation that might have been built will not be built, and lower spot prices will cause demand growth to increase as larger businesses and industries take the opportunity to switch away from fossil fuels.

In the upper North Is spot prices under this scenario will rise again, over five or six years, to where they would be if the smelter had stayed.  But the recovery in spot prices will take longer the further south one moves on the grid.

In the far south, if less grid upgrades are undertaken, spot prices may never return to with-smelter levels.  But if the HVDC link is also upgraded then southern prices could recover to with-smelter levels by the of the decade.

There will, however, be a huge incentive on Meridian Energy, Contact Energy and other generators in the South Is to chase, and accelerate if they can, new electricity demand growth in the south, to help fill the massive hole left by Tiwai, and to help bring southern spot prices up sooner.

Consumers paying spot prices will get the benefit of this, though there will still be price spikes in dry years or when plant outages occur, for example.  In fact, one of the consequences of moving to a much higher percentage of renewable generation is that spot prices will become even more volatile than they are now.  Prolonged wet periods will see low, low prices, for sure, but when the hydro lakes get low, and the wind doesn’t blow, then we will have a smaller thermal fleet to make up the difference, and this thermal fleet will have higher fixed costs to recover, and potentially higher fuel costs as well.

Larger consumers with electricity bills in the hundreds of thousands or millions per annum will see significantly lower prices the next time they go to market to renew supply contracts.  We may witness a ‘price war’ of sorts as suppliers move to fill the gap left by the loss of Tiwai, or to protect their market share.

Prices paid by SMEs and households tend not to move as far or as dramatically as they do for larger consumers because a large proportion of these consumers don’t go chasing better pricing, but instead they sit with their incumbent supplier.  These “sticky” consumers may see either small falls in prices, or static prices for a few years.  For those prepared to make the effort, prices could fall significantly when they switch to another retailer or approach their existing supplier.

But the relative reduction in prices for SMEs and households will be less than it will be for larger consumers because the fixed costs of electricity supply are much larger, in relative terms, for small consumers than they are for large consumers.

However, even though spot prices will fall on average, transmission prices will rise, initially because Transpower’s revenue of $786 million per annum will be spread over 87% of the current electricity consumption:  in simple terms that represents an increase of around 0.2 cents/kWh when spread across all consumers.

To remove road blocks in the grid, Transpower will need to spend $150 million on the lower South Is grid by 2023, and then, on current indications, between $550 and $650 million on the inter-island (HVDC) link, by adding a fourth Cook Strait cable, and on the North Is grid, to remove the second road-block for all the extra energy wanting to find its way to the north.  Up to $750 million in grid upgrades will be additional to those already on the list, and will cause transmission charges to rise further, again tending to offset falls in spot prices.

Adding another Cook Strait cable increases the HVDC link’s capacity and also reduces the requirement to provide spare generating capacity in the North Is to cover the possibility of a failure in the link, thus allowing a disproportionately large increase in inter-island transfers.  There may be other ways of increasing the capacity of the link without having to add another cable, for example using a grid-scale battery in the North Is to cover the possibility of failure, as suggested this week by Meridian Energy, but this remains to be seen.

The issue of who pays for these grid upgrades is one that was hotly debated for over a decade, but the Electricity Authority recently issued their final decision on a new transmission pricing methodology, which will come into effect in April 2023 (assuming it is not successfully challenged in the meantime).  Initially, under the current transmission pricing structure, all consumers will pay equally for the smelter-closure-related grid upgrades, but from 2023 the cost will be allocated to consumers based on how they benefit from the upgrades.  South Is generators can expect to pay the majority of these costs, because they will allow their generation to be sold at higher prices, but consumers in the far north will also pay a share because the upgrades will keep their energy prices lower for longer. 

Exactly how the charges will fall can only be determined by detailed modelling of the impact of the upgrades, so I won’t even attempt to guess at the split.  But a quick back of the envelope calculation based on $750 million in upgrades puts the annual total charge at least to $44 million per annum plus opex costs relating to the upgrade.

I noted above that when Tiwai closes we will move to 94% renewable electricity supply:  but actually this is an overestimate, because for the first two or so years some renewable generation will be “trapped” in the lower South Is, resulting in more spill and a lower percentage of renewables.

But suffice to say, we will experience a dramatic increase in the proportion of renewables in the supply mix, which all sounds good in terms of dramatically reduced emissions form the electricity sector.  But at this level, we will start to experience some of the downside of being at very high renewable percentages.  Now you might say “other countries are there and not experiencing problems”, for example Norway has 98% renewable electricity and Denmark also gets close to 100% at times.  But both of these countries have links to electricity grids in other European nations, and we don’t have any in New Zealand.

Currently, our thermal fleet fills in the gaps in dry years and during winter peaks when the wind is not blowing.   As we discovered recently when gas supplies were severely disrupted in 2018, having a diverse fuel supply has major advantages in terms of keeping the lights on.  But when this diversity disappears as the thermal fleet shrinks, we will have to deal with the risk of having periods when the lakes are low, or when there are cold-winter peaks in demand, and we have a couple of thermal generators out of action, for whatever reason.  The alternatives like batteries, hydrogen and pumped storage are currently all very expensive compared to thermal generation.

Reduced gas-fired thermal generation will also be one more challenge for the domestic gas sector, and after existing supplies and gas contracts run their course, it may become obvious that highly capital‑intensive gas exploration and production leads to more expensive gas when demand falls.