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Mining
The uranium spot price is going crazy, surging to around US$50/lb on Friday to nine-year highs after two weeks of massive gains.
At the end of August the long term and spot prices were just US$34.25, with prices up around 70% year to date.
That came after years in the doldrums, hampered by oversupply as well as negative sentiment and nuclear reactor shutdowns after the Fukushima disaster in 2011.
A dramatic turnaround has been driven by the introduction of the Canadian-listed Sprott Physical Uranium Trust, which has used a US$300 million at-the-market equity raise to buy up 28.3Mlbs of uranium in recent weeks, more than the amount of nuclear fuel required to power France for a year.
It is aiming to ramp its buying spree up even further, revealing plans to increase its at-the-market offer limit by US$1 billion to US$1.3 billion.
At a macro level, the downturn shook out high cost producers and production cuts from the world’s biggest uranium miners, Kazakhstan’s Kazatomprom and Canada’s Cameco, should remain in place until 2023, meaning the supply side remains muted.
Meanwhile demand is expected to rise significantly as nuclear power emerges as a carbon emissions free baseload power option to support renewables in the transition from fossil fuel-powered energy.
According to the latest edition of the World Nuclear Association’s fuel market report, world reactor requirements are 62,500 tU, equivalent to around 162Mlbs.
In the Reference Scenario, only including planned and high confidence reactor builds and expansions, these needs are expected to rise to 79,400 tU in 2030 and 112,300 tU in 2040.
At the upper scenario, decarbonisation spurs a major shift to nuclear energy that could see needs rise to 99,000 tU in 2030, and 156,500 tU in 2040.
Comparatively, mined supply fell from 63,207 tU in 2016 to just 47,731 tU in 2020, and in the reference case is projected to rise to 70,100 tU by 2030 before falling to 50,600 tU in 2040.
The shortfall remains stark even in the upper case of 76,100 tU and 53,200 tU, respectively.
Ergo, new mines will be essential if these projections come to bear.
A price of around US$60/lb has often been cited as the magic number that will justify new operations to start or restart operations to shake off the cobwebs and get going again. And at the current pace of the market it may not be that far off.
But the uranium market is an opaque and complex beast, so Stockhead spoke to a couple of experts to get our heads around how it works.
In principle the relationship between uranium and nuclear power is a simple one. Uranium mining and processing is the first stage in the nuclear fuel cycle.
Miners sell uranium oxide or U3O8 – colloquially known as yellowcake – to utilities before it is enriched and converted into fuel rods to generate power in nuclear reactors.
Uranium is sold to utilities by uranium miners under long-term contracts, so historically only a small percentage of the uranium in circulation has been traded on the spot market. The liquidity is pretty low.
This uranium is sometimes bought by utilities to ensure they maintain an inventory of two years or more to protect against supply uncertainty, and want some exposure to spot in case they can get a bargain on some of their supplies when the spot market is trading at a big discount.
It is also bought by actors who form the secondary demand market, like hedge fund traders and governments who for security reasons want to maintain a national reserve, something the US has been working to establish under both the Trump and Biden administrations.
Miners with contracts to fulfil and inventories to maintain, or for financial reasons, may also end up buying in the spot market, especially at times of stalled production like today.
Brandon Munro, the CEO of uranium explorer Bannerman Energy (ASX:BMN) and co-chair of the World Nuclear Association’s demand working group, says liquidity on the spot market has typically been around 220,000lbs a day in recent months.
Sprott has been hoovering up 400,000lbs a day. But it is also being front run by other hedge funds, utilities, uranium companies and investors who would normally be in the market.
“Essentially, this current demand is driven by Sprott. But what it’s also done is it’s also drawn other demand into the sector,” Munro said.
“So traders, for example, have either been buying material to try and front run Sprott, there’s other investors who are coming in to try and front run Sprott.
“And it’s also given end users and producers a reason to quickly try and get in and buy some uranium.
“To give you some context, the liquidity in the spot market was very, very low for several months. So to throw a number at you between April and July, for that four month period, the average liquidity for the spot market was about 220,000 pounds per day.
“Now Sprott’s been buying at about 400,000 pounds per day, hence why they’ve had such an effect on price. But on top of that, the non-Sprott buying is running at greater than what the average liquidity was before.”
“It’s not just the people who were buying before plus Sprott, it’s the people that were buying before plus Sprott, plus those other parties who are now motivated to come into the market and buy uranium at these prices, because they expect it to go up.”
Munro estimates in the past few weeks liquidity has been running at 3 to 4 times previous levels, helping to fuel the price run seen in recent days.
Sashi Davies is a member of the World Nuclear Fuel Market’s Board of Governors and strategic and marketing advisor at ASX-listed Boss Energy (ASX:BOE).
According to Davies the spot price is reported daily on the basis of transactions reported to pricing agencies. The term price, on the other hand, is only reported once a month on account of the limited number of deals it takes into account.
This means there could be a lag on the term price, even though it normally trades at a premium to spot.
“I think one thing you’ve got to bear in mind also is that the spot price has moved dramatically in just about a month,” she told Stockhead.
“So it takes a while for procurement strategy to catch up with this type of movement. So I think … I didn’t expect to see a huge jump in term price at the end of this month, but I would expect it to catch up over the months that come as the contracting catches up with the price movement.
“It doesn’t mean that there aren’t going to be term contracts that jump quite significantly.
“It just means that there might not have been any in this month, because the price movement has been quite violent and it hasn’t given the kind of the procurement thinking time to catch up.”
Hell yes it does.
Spot still makes up a portion of the uranium purchased by utilities, who like to leave themselves some exposure in case they don’t have enough uranium supply contracted for their needs and to take advantage of lower prices when they can get them.
Davies says spot prices are also the starting point for long-term contracts.
“The spot price is always relevant to negotiations going forward. When it’s rising, it influences the starting level of contracts,” she said.
“And unfortunately, it also affects contracts when it’s falling. So the spot price is definitely the baseline. It’s the first point of call when you start a negotiation.”
Davies said contracting can be organised through an open request for proposals, or off-market, where a utility will contact select producers to negotiate uranium supply.
“When you look at negotiating, essentially you’d be replying to a request for proposals,” she said.
“Transactions or negotiations tend to be either competitive proposals, through requests for proposals which are issued by the utilities, or off market transactions where the utility might approach a few producers and invite them to come in for discussion.
“But either way, the environment would be set by the prevailing spot price. So the prevailing spot price would influence the starting point of discussions.”
The uranium market is considered especially opaque when compared to metals like gold and iron ore and even other energy sources like oil, gas or coal, and contracts can be priced and written in a number of different ways.
“So the thing about the long term contract of uranium is there’s no standard form contract,” Munro said.
“It’s a pretty clunky system. It’s a pretty clunky process. And it’s effectively a negotiation that’s based on certain industry norms, such as the time frame, deliveries, whether it’s fixed price, whether it’s price escalated, whether it’s spot reference, whether there’s collars, whether there’s cuffs, whether there’s flexibility in terms of how many pounds are delivered, whether there’s flexibility in terms of what timeframe they’re delivered, what the location is for delivery.”
Long-term contracts, he noted, tended to be priced in general at around a 20% premium to the spot price.
“Utilities are happy to potentially pay that premium knowing that they will get material. And that’s because there’s a massive amount of investment in a nuclear power plant and to run out of uranium is a catastrophic failure,” Munro said.
“The other thing is in a typical nuclear power plant, such as in the US, the U308 component is about 5% of the cost of producing the electricity.
“So what that means is, even if they do pay a little bit more, it’s not going to particularly affect the cost of the power they’re making.”
But when the spot market dropped below US$20/lb, even contracted prices became lower than the cost of production for a large chunk of the world’s uranium miners.
“The mines weren’t prepared to write long term contracts at a typical 20% premium, because to do that they’d be locking in long term losses and so there produced a really big gap between the spot price and the long term contract price,” Munro said.
“When spot was $20, long term contracts were about $40. And that created a bunch of issues because it’s very hard for a utility to then go and say to their board, ‘hey, have I got a deal for you? I can get uranium at $39 on a long term contract’.
“And the board would say, ‘but I just read that uranium is $20, why on earth would you want to do that?’ And so the result of that is that there’s been … very little long term contracting over the last couple of years.
“And so now we face a situation where we’ve now got a spot price going through $45, which is healthy, you put a typical premium onto that, and it’s starting to get to the point where utilities will need to write long term contracts.
“And some of the cheaper producers will be willing to lock in that sort of pricing. So we can expect to see some contracting pick up soon.”
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Not necessarily and certainly not straight away.
One issue to consider is the number of large uranium operations that were taken offline because they were uneconomic to operate when spot prices dropped below US$30/lb.
One of these was the Macarthur River mine in Saskatchewan Canada. Owned by Canadian giant Cameco, the high-grade operation was responsible for around 13% of the world’s primary uranium production before it was placed on ice in 2018.
Kazakhstan’s Kazatomprom, the other major global-scale producer of U3O8, is another with a large amount of latent capacity to whom major nuclear utilities will turn to first.
Munro says these large producers and other restart projects will likely need to come back into the market before the road opens up for new producers to negotiate contracts.
“For new players, the issue is that utilities will first go to existing large style producers who had material to sell,” he told Stockhead. “Cameco is a good example, which is a giant Canadian company.
“They’ve got the Cigar Lake uranium mine in operation at the moment. They’ve got interest in Kazakh uranium mining coming in for the Inkai joint venture (with Kazatomprom). And they also have the Macarthur river uranium mine which they’ve put onto care and maintenance.
“So it’s easier for utilities to soak up any additional capacity that Cameco can offer through turning on McArthur river again, before they go to brand new producers. So there will be a period of time where Cameco says right, OK, we’re prepared to keep contracting at this rate and if you offer at these prices we’ll turn McCarthur River back on.
“And only once that slack is taken up, will there be a broader market for new producers. So it’s a bit hard to put an exact timeframe.”
Munro said very few new producers would be in a position to negotiate contracts right away.
“It’s still months away, not weeks away before we see any level of contracting for new producers,” he said.
That doesn’t mean uranium market experts are not bullish about the need for new sources of production to enter the market in the coming years.
According to Davies, even once mines on care and maintenance like Cameco’s, Paladin’s Langer-Heinrich mine in Namibia and Boss’ Honeymoon return to production, utilities will be in need of new, secure sources of uranium.
“Even if you include all the mines that have to come back, new production is needed from about 2024 onwards, which means that the price signals need to be there now to make sure that the mines are in operation from 2024 onwards,” she said.
“I think this is what’s quite exciting is that the prices that we’re seeing now, I think would justify a restart, if they seemed to be sustainable. But you still need the price – not just the spot price – but the term price to move into the $60s to bring on new production.”
Davies believes most utilities now recognise contract prices they have seen in recent times are not sustainable if they want to ensure fuel security over the decades long lives of their reactors.
“With the price rising now I think utilities, as well as producers, see that there’s a greater prospect for being able to have sustained prices that can sustain production over the long term,” she said. “Because in most cases you’re not looking at contracts that last a year or two years.
“For utilities, they’re looking at supplying reactors that have life times of 40 to 60 years. And it might not be through the one contract, but they want to know that there’s a pipeline of production that will be able to supply them reliably and at prices that will keep them healthy.
“So I think the rising spot price gives utilities the ability to pay prices that they see as sustainable, and it gives producers prices that will keep them in business going forward for the lifetime of reactors.”
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