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Nuclear's new deal

Is nuclear power necessary for a net zero future?
Nuclear's new deal

The race to net zero is typically framed as a shift away from fossil fuels such as coal and natural gas, towards renewables such as wind and solar. The role of nuclear power in the clean energy transition is often overlooked, despite it being the second-largest source of low-carbon electricity in the world behind hydropower.

Nuclear power is undoubtedly a divisive topic, not least because of its association with disasters such as Chernobyl and Fukushima. Sasja Beslik, head of sustainable finance development at J. Safra Sarasin, likens the atomic energy source to a Rorschach test. “You see what you want to see – a rosy nuclear future or an old-world dinosaur in a slow-death spiral,” he says.

 

The good, the bad and the ugly

Advocates of nuclear power point to the fact that it is an energy-dense, low-carbon and reliable source of power that could pair well with wind and solar. While renewables are on the rise, they are not a panacea for the race to net zero due to the problem of ‘intermittency’ – electricity is only produced when the sun is shining, or the wind is blowing.

So, until we achieve wide-scale battery storage to store and release excess power from renewables, nuclear could be used to provide large amounts of predictable power as part of a centralised grid. The idea is that it is ‘nuclear plus renewables’, rather than ‘nuclear versus renewables’.

“We need to be using all the technologies we currently have to enable us to get to net zero by 2050,” says Tom Greatrex, chief executive of the Nuclear Industry Association (NIA). “The successful way to decarbonise the power supply is by having a mix of sources, and nuclear is one of those.”

Robin Usson, credit analyst at Federated Hermes, agrees that “we shouldn’t put all of our eggs in the same basket. We should try to find a set of solutions that can tackle the decarbonisation of our society, so I do believe that nuclear can find its place.”

Usson also says that “one of the main attraction points for nuclear is its reliability. Nuclear plant load factors are actually the highest across all technologies – well above 90 per cent.” That reliability could potentially be put to use for hydrogen production.  

But critics argue that expensive and often-delayed nuclear power stations are a counter-productive investment given the urgency of climate change. Renewables are cheaper and faster to get up and running and also require less maintenance.

“[T]he costs are excessively high and, unlike renewables, show no signs of falling in practice,” says Peter Michaelis, head of the Liontrust Sustainable Investment team. “In addition, there does not appear to be any emerging technological improvement that can change this picture in the next decade. Capital that is directed to nuclear could be several times more effectively deployed into energy efficiency and renewables.”

Individual, ‘once-in-a-generation’ nuclear mega-projects make it very difficult to eke out efficiencies. China and South Korea have been better at managing costs – partly due to cheaper labour in the former – but also because they have built plants more frequently, meaning that supply chains do not need to be assembled from scratch. According to consultancy LucidCatalyst, recent nuclear power stations in South Korea have cost between $2,000-$4,000 (£1,400-$2,800) per kilowatt (KW) versus more than $8,000 per KW for Sizewell B, the last plant to be built in the UK.

“You don't build a factory to build one car,” says Greatrex. “It's exactly the same principle. You need to build again and again and use the same design. And when you build again, you use the same supply chain that you built up.”

But while nuclear power is low carbon, measures of environmental impact go beyond just greenhouse gases. Nuclear power stations also require a lot of water to act as a coolant, meaning that they are often located near rivers or the sea. Analysts at Moody’s note that “rising heat and water stress pose a risk to plant operations” and that “the proximity of power plants to large bodies of water leaves them vulnerable to flooding, hurricanes, and storm surges.” They believe there is about 48GW of nuclear capacity across the US with “elevated” exposure to increasing heat and water stress.

As well as concerns about potential nuclear accidents, there is also the more routine production, storage and disposal of radioactive waste, and the process of decommissioning old plants. In the UK, Renew (RNWH) is involved in asset care, decommissioning, decontamination and waste treatment for nuclear facilities, tapping into the Nuclear Decommissioning Authority’s (NDA) £3bn annual budget. So, not only would it benefit from any new nuclear capacity that is built, but also ongoing work from sites that have been shut down. Regulatory and safety requirements mean that this is an area with high barriers to entry.

 

Will we see a nuclear revival?

According to the International Energy Agency (IEA), the use of nuclear power has saved over 60 gigatonnes of carbon emissions over the past 50 years, which is equal to nearly two years’ worth of global energy-related emissions. Nuclear accounted for around 18 per cent of global electricity production in the 1990s, but amid a lack of new capacity and the rise of renewables and natural gas, this has dropped to roughly to 10 per cent today.

The IEA projects that unless we extend the lifetime of existing nuclear power plants and greenlight new projects, nuclear power output in advanced economies will decline by two-thirds over the next two decades. It says that gas, and to a lesser extent coal, would play a significant role in replacing the lost nuclear capacity, meaning that cumulative carbon dioxide (CO2) emissions would rise by four gigatonnes by 2040. There would also be an increased burden on wind and solar to scale up more quickly in order to achieve our climate ambitions. 

Terry Maxey, managing director of utilities at Accenture, puts it more bluntly: “Prematurely pulling the plug on nuclear would be tantamount to pulling the plug on net zero.”

Looking at a future where the world does indeed achieve net zero emissions by 2050, the IEA predicts that almost 90 per cent of the world’s electricity will be generated from renewable sources and most of the remainder will come from nuclear. In this scenario, it forecasts that the energy supplied from nuclear will nearly double over the next 30 years.

Even in a more conservative ‘stated policies scenario’ – which only accounts for the firm government policies that are in place or have been announced – electricity generated by nuclear is expected to rise by a third between now and 2050.

 

Diverging paths

While China has a relatively young nuclear fleet, the average age of a reactor in the European Union (EU) is 35 years, while in the US it is 39 years. Around a quarter of the current nuclear capacity in advanced economies is set to be shut down by 2025.

New nuclear power stations cannot simply be built overnight – they are capital intensive and multi-year endeavours. Extending the lifetime of existing plants can be a cheaper interim solution and is also cost-competitive with the likes of new wind and solar projects.

Some countries are heading in the opposite direction, which is largely a legacy of the Fukushima nuclear disaster of 2011. Japan itself halted its nuclear power generation in the wake of the accident, and only nine out of its 55 reactors have been restarted.

Meanwhile, the German government reversed a decision to extend the life of its 17 nuclear power plants and will instead phase out nuclear power altogether by the end of 2022. Michael Liebreich, founder of Bloomberg New Energy Finance (BNEF), says this is “nothing short of a climate tragedy, and German anti-nuclear activists will be weighed in the same scales by history as fossil fuel promoters.”

A court ruling means that the German government will now have to pay a total of €2.8bn (£2.4bn) in compensation to the affected operators – EnBW (DE:EBK), E.ON (DE:EOAN), RWE (DE:RWE) and Vattenfall.

By contrast, China is forging ahead with nuclear, leading the world in adding new capacity. As part of its new Five-Year Plan, the country is aiming to increase nuclear power generation from 50GW to 70GW by 2025, which should benefit the likes of domestic players China Nuclear Engineering & Construction Corp. (CN:601611) and China National Nuclear Power Co. (CN:601985).

Over in the US – which is the world’s largest nuclear power producer – the Biden administration is reportedly looking to offer federal production tax credits as part of its infrastructure bill in order to keep existing nuclear power plants open. Nuclear power will also be included in the “clean energy standard”, which would require utilities to produce carbon emissions-free power by 2035.

The US leads the world with more than 90 nuclear reactors spread across 28 states, and it derived around a fifth of its electricity from nuclear last year. But it is currently only building two new reactors in Georgia – Southern Co’s (US:SO) overdue and over budget Vogtle plant – while ageing nuclear power stations have been closing due to economic pressures from cheaper shale gas.  

The Indian Point plant in New York – which is owned by Entergy (US:ETR) – shut down at the end of April, and Exelon (US:EXC) is putting two plants in Illinois into early retirement this year, citing “market rules that favour polluting power plants over carbon-free nuclear energy”.

According to the Rhodium Group, without any policy changes, more than half of the US’s nuclear fleet will retire by 2030.

If Biden’s nuclear ambitions do come to fruition, that could benefit the likes of NextEra Energy (US:NEE), which operates one of the largest nuclear fleets in the US. It also has a rapidly growing renewables portfolio and recently entered the Dividend Aristocrat club, meaning that it has increased its dividend for 25 consecutive years.

NextEra is one of the top 10 holdings of the iShares Global Clean Energy UCITS ETF (INRG), which also has exposure to other companies involved in nuclear power such as Xcel Energy (US:XEL) and Iberdrola (ES:IBE).

 

Nuclear power in the UK – a slow moving beast

In the UK, around a fifth of electricity comes from nuclear. There are currently eight operational nuclear power stations across the country, which are majority-owned and operated by French utility Électricité de France (FR:EDF). Centrica (CNA) has a 20 per cent stake in the fleet which it was trying to divest, but this process has been suspended due to “operational issues on a number of the power stations”. For example, one of the reactors at Hunterston B is currently closed due to cracking in the graphite bricks which make up the core.

All but one of the UK’s existing nuclear power stations are set to retire by the end of 2030 as they reach the end of their operational lives. That lost capacity needs to be replaced with something in order to keep pace with electricity demand.

At present, only Hinkley Point C in Somerset is under construction, although two further power stations, Bradwell in Essex and Sizewell C in Suffolk, have been proposed. Still, protracted decision making and a lack of suitable financing have led developers to abandon projects in the UK.

Last year, Hitachi officially pulled the plug on plans to build a £20bn nuclear power station in Wylfa in North Wales, and a £15bn plant in Olbury in Gloucestershire. It was unable to reach a funding agreement with the UK government, and Covid-19 proved to be the final nail in the coffin. This followed Toshiba (JP:6502) scrapping its Moorside nuclear project in Cumbria in 2018.

While construction of Hinkley Point C is under way, it certainly hasn’t been without troubles. The 3.2GW plant is being built by EDF and minority partner China General Nuclear Power (CGN), a Chinese state-owned energy company. It was approved in 2016 at an estimated cost of £18bn, but that has since spiralled to £23bn. Amid disruption from the pandemic, the start date for electricity generation has also been pushed back to 2026.

In order to get EDF and CGN to finance the project themselves, the government agreed to pay £92.50 for every megawatt hour (MWh) of electricity that it produces for 35 years. For comparison, the most recent ‘contracts for difference’ (CFD) auction saw offshore wind projects due for delivery in 2023 secure a price of just £39.65 per MWh.

EDF and CGN’s next project, the proposed £20bn Sizewell C plant, will likely rely on a different funding model. The government is exploring taking a direct stake and using a ‘regulated asset base’ (RAB) model. The latter would allow operators to earn money before the site is up and running, as they would be able to charge electricity suppliers a regulated price in exchange for providing and operating the nuclear infrastructure that will ultimately materialise. This could bring down borrowing costs and allow investors to reap returns much sooner.

Funding the construction of nuclear power stations is currently less attractive to private sector investors than other assets because these projects are extremely capital intensive and take many years to start producing any revenue. There is also the rising influence of ‘environmental, social and governance’ (ESG) mandates on investment decisions.

Prudential (PRU) has said that it is “highly unlikely” that it will invest in Sizewell C. “The issue of the energy transition and the role nuclear energy should play is complex and it differs from market to market,” said chairwoman Shriti Vadera at the group’s recent annual general meeting (AGM). "As an Asia and Africa-focused group going forward, Sizewell is highly unlikely to be the sort of project that we would directly invest in.”

Aviva (AV.) is similarly cool on nuclear. Chairman George Culmer told investors in May that “the ESG impact of nuclear is at this time still far from clear….We are not currently actively involved in any such investments.”

Regardless, the UK intends to push ahead with nuclear. The government’s long-awaited energy white paper – which was finally published in December – asserted that “additional nuclear beyond Hinkley Point C will be needed in a low-cost 2050 electricity system of very low emissions”, and said that at least one large-scale nuclear project will be given the greenlight before the end of this Parliament.

The white paper projects that the UK will have anywhere between 5GW and 40GW of nuclear capacity by 2050, and Professor Francis Livens, director of Manchester University’s Dalton Nuclear Institute, sees the bottom end of this range as “entirely achievable” if both Hinkley C and Sizewell C come online. But he believes that if we only stick to currently available technology, then “nuclear will pretty much be an irrelevance to achieving the overall net zero targets”.

Livens says that delivering an “extremely ambitious” 40GW will require “new technologies, new ways of deployment, new uses of nuclear energy, all delivered for less money and in less time. That’s quite a stretching target for a historically conservative sector.”

 

Have your yellow cake and eat it

Nuclear energy likely getting a demand boost for environmental reasons must be a real surprise for those living near proposed uranium mines. The radioactive nature of the product means mines have a tougher time getting built.

That’s not to say there is an issue with supply. The Fukushima disaster a decade ago knocked off demand, and the price of uranium – sold as yellowcake (U3O8) – has only recently recovered. Two very different London-listed companies demonstrate the difficulty of making money from the actual production of uranium. These are Rio Tinto (RIO) and Berkeley Energia (BKY).  

For Rio, the Jabiluka mine in Australia is a striking example of why miners should not bank on licensed projects going ahead. The traditional Aboriginal owners of the site have consistently refused permission for development, and now that the nearby Ranger mine has closed and its stake in the Langer Heinrich mine in Namibia has been sold, Rio is out of the uranium business. 

The proposed Jabiluka mine was in the middle of a national park, with sacred sites set for destruction if the project went ahead. The decision to not proceed – even after a mine entry point (decline) was built and plenty of land was cleared – came after massive protests and an international campaign against it. Ironically, Rio cited the sacred sites and the traditional owner’s lack of support as the reason not to go ahead 20 years before it destroyed the Juukan Gorge resting places. Former chief executive Jean-Sebastien Jacques said that the Langer Heinrich sale strengthened Rio’s portfolio, even with a cash price of just $6.5m, although it could receive a contingent payment of up to $100m if the mine reopens.

Closer to the UK, Berkeley Energia has spent years trying to open a uranium mine in Spain. It has raised the money for the build – which is usually the last stage before construction – but progress has been challenged by local opposition in scenes reminiscent of Jabiluka in the 1990s. The company is still working on a final permit, for the processing plant. A new law came in this year to block further permits for the “exploitation of radioactive materials”, so Berkeley Energia could be the last uranium miner if it does get Salamanca built.

So, supply can be tougher than for other mined materials. But this doesn’t actually matter, because of the way the uranium market is structured.

World uranium supply is dominated by two companies: Kazatomprom and Cameco (CA:CCO). The former is majority-owned by the Kazakh state, and the latter is listed in Canada, where most of its mines are located. The market is in a strange position currently, with a huge supply deficit but still fairly weak prices. This is caused by excess inventory, according to BMO Capital Markets analyst Alexander Pearce. 

“After almost a decade of constant surplus following the GFC [global financial crisis], global uranium inventories are currently running at around four years of current consumption,” observes Pearce. He says that once inventory reaches closer to three years of demand, more supply will come on. 

BMO forecasts that Chinese demand will likely necessitate additional supply from 2023 onwards. And that can happen very quickly because it is idle existing mines that will be reopened to meet that demand, rather than new operations. 

Cameco shuttered the 18m pound (lb)-a-year McArthur River mine in 2017 because of weak prices and also stopped production at its key mine, Cigar Lake, in the first quarter this year due to Covid-19. This knocked 2.1mlbs from global supply, but had little impact on prices. Cameco will have to buy up to 13mlb this year to meet its delivery obligations, which is like BHP (BHP) buying iron ore from Rio Tinto to meet its contracted supply in China. It’s not unusual in the uranium market, however. 

“[Producer purchasing] is essentially shifting inventory around rather than actual “demand,” but it does serve to limit the availability of free float material in the market, which will be making utilities incrementally more nervous,” says Pearce. 

Broadly, there is plenty of agreement that more supply is needed. Cameco made a convincing argument for long-term demand growth in its first-quarter update as upcoming nuclear reactors outweigh the impact of those going offline. It pointed to 52 reactors currently under construction compared with 444 in operation, as well as “a number of reactor construction projects recently approved, and many more planned”.

Pearce says that the uranium price would need to get back to the $40/lb level for more supply to arrive from McArthur Lake and Kazatomprom, which could add 10mlb a year by restarting shuttered mines. 

“This ‘race to market’ [would] be a key test of the hitherto robust producer discipline seen between the major uranium players,” he says. 

So, there is a clear demand case to be made, even without a longer-term acceleration of nuclear power as part of the shift away from coal and gas. Investment options are limited but growing.

 

Equitable returns

London’s only pure-play uranium option is Yellow Cake (YCA). It is an investment vehicle for uranium, and holds just under 10mlbs of its namesake material. It recently ramped up its purchasing, spending $10m in May to add 343,053lbs to its stockpile, and also maxing out its option to purchase $100m of uranium a year from Kazatomprom.

As of 19 April, with uranium at $30.65/lb, Yellow Cake’s net asset value (NAV) was 228p and it was trading at 252p, giving it a premium to its uranium holding. It has not always traded above its NAV, and the company has spent millions on buybacks to try and get rid of the discount. 

Similar to gold ETFs, Yellow Cake has not beaten the miners. Gold miners can often outpace price rises in the metal itself because of even greater earnings growth and investor interest. The split between Cameco and Yellow Cake is only recent, however, with its share price closely following Cameco between around April 2020 and February this year, until Cameco shot ahead. On a 12-month basis, the Canadian miner is now up 92 per cent while Yellow Cake is up 18 per cent. 

Berkeley Energia is more beholden to the Spanish permitting processes than the uranium market, and its shares have more than doubled over the past year, to 32p. But while the signals are definitely positive for uranium, we would stick to a vehicle like Yellow Cake rather than a miner to reduce risk, despite the strong run from miners recently. The CQS Natural Resources Growth and Income Trust (CYN) has performed strongly in the past year, and with 5 per cent of its portfolio invested in uranium, it could be a way to dip a toe into the sector.

 

The next generation

A new generation of nuclear technology is emerging in the form of ‘small modular reactors’ (SMRs), which are seen as a more affordable alternative to mega-projects. SMRs are targeting economies of scale by pre-fabricating standardised units and putting them together on site more quickly than traditional reactors. Rather than expensive ‘one-of-a-kind’ plants, countries could roll out fleets instead, building multiple plants to the same design and specifications and reducing costs.

The UK government has promised up to £215m in public funding to develop a domestically-designed SMR which it says will unlock £300m-worth of investment from the private sector. This will likely go to a consortium led by Rolls-Royce (RR.), which has developed a 470MW SMR with a lifespan of 60 years. It is aiming to build up to 10 SMRs by 2035, and says that each unit will initially cost £2.2bn, before dropping to £1.8bn after five have been completed. Chief executive Tom Samson says that the consortium’s SMRs will be able to generate electricity at a comparable cost to offshore wind, at around £50 per MWh.

Rolls-Royce used to be more involved in nuclear power, selling systems for civil power generation. But it offloaded its North American civil nuclear services business to Westinghouse Electric Company last year, and struck an agreement to sell its civil nuclear instrumentation and control business to Framatome for an undisclosed sum in December.

For SMRs to achieve the promised economies of scale, it will require a large number of orders, and it’s not clear at this stage that that will actually happen. Even the International Atomic Energy Agency (IAEA) acknowledged last year that “although SMRs have lower upfront capital cost per unit, their economic competitiveness is still to be proven”.

The question is also whether they will arrive too late. By the time SMRs become operational, they will likely be competing with more advanced renewables and potentially better storage technology as well.

 

So, is nuclear worth investing in?

Nuclear power does have positive attributes. But high costs, slow lead times and safety and environmental concerns mean that it is unlikely to experience the spectacular growth rates associated with renewables and connected technologies. Nonetheless, it should still remain a not insignificant part of the global energy mix in the long term.

The trouble for investors, is that the pool of nuclear-centric opportunities is rather small – especially when compared with renewables. EDF may spring to mind, but the debt-laden utility – which is majority-owned by the French government – is trying to restructure into a fully state-owned nuclear business with a publicly listed subsidiary focused on renewable energy.

“It's not easy to invest in nuclear in a listed equity. In fact, it is very difficult to,” observes Franks.

“There is no shortage – particularly in these very frothy capital markets at the moment – of companies coming to market with technology solutions to solve climate change issues. The net zero carbon commitments of last year and the experience of the pandemic has really galvanised the opportunity here,” says Franks. “And yet no one is talking to me about nuclear.”

The most fertile hunting ground seems to be uranium, and Ben Conway, head of fund management at Hawksmoor Investment Management, argues that the bull case doesn’t require a dramatic shift in attitudes towards nuclear power. He says that while the Chinese buildout of new nuclear power stations will propel demand for uranium, “what you really need is just an extension of the life of existing power stations – for the existing nuclear infrastructure around the world to be used to its full capacity for longer. That will drive significant demand in an already very, very tight market for uranium mining supply.”