The closures raise several important questions about our electricity market and the economy: what went wrong, and is it just a natural part of our economy evolving or could it have been avoided? And what does it mean for our trade with the rest of the world?
It’s not this year’s prices that are the problem
The industrial energy users shutting up shop are generally not closing because of the high cost of power this winter.
Large electricity users buy most of their electricity wholesale. They also tend to purchase the bulk of their load on the futures market. This means buying the right to use electricity at a future date, usually a year or more in advance. They will then arrange other contracts with large energy companies to manage any “peaks” over and above their base electricity use. They will also try to hedge against the threat of abnormally high electricity costs, insulating themselves from the threat of abnormally high peaks.
Margaret Cooney, chief operating officer at Octopus Energy, a renewable energy company, told the Herald it was electricity futures that were causing industrial users to shut up shop.
“Generally if you are a prudent trader you are buying the vast majority of your load a year in advance,” Cooney said, noting that the current futures price for a megawatt hour (MWh) of electricity in Q3 of next year is about $288, coming down to $141 in summer.
According to data kept by the regulator, the Electricity Authority, average futures prices have risen dramatically since 2018, the year of the offshore oil and gas exploration ban.
Data going back to 2009 shows remarkably stable or even falling prices for electricity futures. In mid-2009, the forward price curve, showing the price for power delivered in a year or more’s time cost about $79/MWh. For the next 10 years prices stayed low and stable; the average futures price never cracked $92/MWh and fell as low as $71/MWh.
Industrial power users were getting real-terms price cuts as inflation slowly eroded the real price of their futures contracts. Things began to change in September 2018, when prices began their slow, seemingly inexorable rise. Within a year they had cracked $100/MWh, by 2021 they hit $130/MWh and earlier this year they hit $208/MWh, with some futures prices settling even higher.
Unsurprisingly, industrial firms whose business is predicated on being able to buy electricity at $70-$90/MWh become unviable when prices ticked up to $200/MWh. Many large and well-hedged industrial businesses could probably sustain a spike in peak prices like what we saw in August, when wholesale peak prices reached $800/MWh, however they cannot sustain year upon year of those prices, and the electricity futures market suggests that is precisely what they are in for: a future of exceedingly high electricity costs.
Data from MBIE, the Ministry of Business, Innovation and Employment, on industrial users’ total electricity costs showed those costs had increased by 25% in real terms since 2010.
Cooney was concerned those high electricity futures prices will squeeze out many businesses.
“We won’t have any business left in New Zealand,” she said of a future with prices that reflected the current futures price.
Cooney said it was wrong to describe the prices as a “short-term issue... It’s a really systemic economic issue.”
Energy Collective CEO Huia Burt also laid much of the blame for industrial closures at futures prices.
“Based on the ASX forward electricity price curve on which industrial and commercial electricity contract pricing is based, businesses who typically contract anywhere between one-three years forward are experiencing 30%-40% increases in overall cost when re-contracting,” Burt said.
She said this was making many businesses “hesitant to re-contract for longer periods of time, leading some to opt for three- to six-month contracts, which is risky considering electricity price forecasting is not (and should not have to be) their core business”.
Where did all the power go?
New Zealand is not generating substantially more electricity now than it was 15 years ago.
Electricity demand flatlined after the Global Financial Crisis, despite New Zealand’s population growing dramatically in that time with households purchasing large televisions, computer equipment, and electric cars.
Households account for more than a third of New Zealand’s electricity consumption. Household appliances, particularly things like fridges, have become vastly more efficient, meaning that despite a population increase of about 800,000, the country has not had to invest in significant new generation.
In fact, total generation capacity actually decreased in some years as old fossil fuel plants were retired and not replaced with equivalent new renewable generation. Thermal electricity generation reduced by an entire gigawatt between 2014 and 2017 (about 10% of generation at that time).
This was a logical response. There were fears from the gentailers that if they kept up the impressive pace of new generation construction seen in the 1990s and 2000s, they might flood the market with cheap electricity – a good outcome for households and businesses, but not necessarily good for the power companies’ bottom line.
Seen in that light, the last 10 years were something of an aberration, in which an unexpected burst of technological efficiency helped sustain a decade of unnaturally low, stable prices for industrial producers. If that’s the case, then it raises another difficult question: whether it was possible to sustain those low prices over the long term, or whether they need to rise to a “new normal”.
Mercury Energy general manager Phil Gibson told the Herald the 2010s was an “oversupplied market”.
“There was a lot of build in the early 2000s... demand has basically been flat from 2006 to 2023,” Gibson said.
He said that with no more electricity required, the few projects that were built were renewables designed to squeeze out retired thermal generation.
“You have a market which is largely oversupplied for a decade or so,” he said.
Gibson said futures prices were meant to reflect the long-run marginal cost (LRMC) of the next most competitive new electricity project in the market. In New Zealand, most electricity generation is generated by renewables. The next most available “unit” of generation tends to be fossil fuel generation, which is fired up to manage peaks. The cost of bringing this generation online tends to set the price of electricity.
Gibson said that since 2018, the forward price curve has actually been higher than the LRMC. The reason for that is “a lack of certainty about the reliability of assets in the market” – mainly the lack of reliable gas and thermal generation.
Gibson said part of the solution to the crisis would be the country accepting that “gas is a good thing for decarbonisation, not a bad thing”.
“We need to grow our gas generation footprint to enable ourselves to grow demand affordably and reliably and enable renewables to take up the growth,” he said.
Gibson said the 2018 ban on new offshore oil and gas exploration had not helped the electricity market, but there were other problems too.
“There’s gas in the ground. There’s stuff to be extracted but for some reason, we have failed on all fields in the last six years. You can make up your own mind about whether that is attributable to politics or not but we need to sort it out,” he said.
Regular, reliable and affordable gas supply would likely help to stabilise the price of electricity, however, affordable and reliable gas is increasingly difficult to come by – at least in the short term.
Recent modelling by MBIE concluded that a repeal of the offshore oil and gas exploration ban could mean greater investment in existing gas fields and potentially lead to new offshore fields being discovered, giving the country greater gas reserves to draw on in the event of a crunch.
However, it said that existing fields were unlikely to raise production significantly in the short term and it was unlikely any new fields would come online before 2035. In any event, officials believed gas prices would rise “to within the range of the cost of importing LNG” (liquefied natural gas).
Can heavy industry survive the greening of the grid?
One of the big questions looming over electricity in New Zealand is whether affordable electricity in the quantities required for industrial producers can co-exist with the drive to bring more renewable energy online.
Gibson cited recent innovations, like the new contract with the Tiwai Point smelter that meant it would turn off potlines when there are generation shortages, allowing it to act almost as a giant battery that the grid could draw on during a crisis.
“Tiwai is a great flex provider... I think they’re a help, not a hurt, they’re making things better,” he said.
This could be an area where the interest of New Zealand as an exporting nation conflicts with the interests of the power companies. While negotiating more flexible contracts with large industrial users might be good for the long-term certainty of electricity supply, periodically shutting down manufacturing businesses is hardly ideal for New Zealand as a country, particularly when we already run a substantial trade deficit, meaning we export far fewer goods than we import.
Octopus Energy’s Cooney thinks bringing on new, affordable, renewable energy is possible, but it would need changes. Currently, there are not the right incentives in place for bringing on large amounts of renewable generation. She said most other markets around the world have managed the decommissioning of fossil fuel plants better than New Zealand has by ensuring there is sufficient supply available before those plants are decommissioned.
There is always the fear that companies will overbuild and spend large amounts of money building renewable generation that does not recoup the significant costs of construction.
“In New South Wales for example, they’ve set up a New South Wales energy company, which is owned by the Government and has this consumer trustee function, and that they’re issuing options that ensure that there’s sufficient return there for people that are investing ahead of the curve,” Cooney said.
She said that the United Kingdom used CFD (Contract For Difference) mechanisms, which encouraged the development of renewable generation by guaranteeing a minimum price.
“That’s quite a common approach where you have Government saying, ‘we’ll put an option out for however many gigawatts of new energy to be developed to guarantee price for a 10-year period’,” Cooney said.
The Energy Collective’s Burt told the Herald regulatory reform was needed, including the operational separation of the large, majority Government-owned gentailers.
“It’s our view that the regulatory reform we and others are proposing with respect to operational separation of the gentailers and implementation of non-discrimination rules will provide immediate relief in terms of fair pricing in contract markets,” she said.
Burt said this would soon “flow through to greater investment and competition on both the supply and demand-side of the electricity market”.
It would be “straightforward to implement, low cost and proven to work in telco markets: it simply requires the Electricity Authority to move it from a “backstop” option to one that is put into place immediately”.
Thomas Coughlan is deputy political editor and covers politics from Parliament. He has worked for the Herald since 2021 and has worked in the Press Gallery since 2018.
