The key to building less-expensive batteries that could extend the range of EVs might lie in a cheap, abundant material: sulfur.
Addressing climate change is going to require a whole lot of batteries, both to drive an increasingly electric fleet of vehicles and to store renewable power on the grid. Today, lithium-ion batteries are the dominant choice for both industries.
But as the need for more batteries grows, digging up the required materials becomes more challenging. The solution may lie in a growing number of alternatives that avoid some of the most limited and controversial metals needed for lithium-ion batteries, like cobalt and nickel.
One contender chemistry, lithium-sulfur, could soon reach a major milestone, as startup Lyten plans to deliver limited quantities of lithium-sulfur cells to its first customers later this year. The cells (which can be strung together to build batteries of different sizes) will go to customers in the aerospace and defense industries, a step on the journey to building batteries that can stand up to the test of EVs.
When it comes to new options for batteries, “we need something that we can make a lot of, and make it quickly. And that’s where lithium-sulfur comes in,” says Celina Mikolajczak, chief battery technology officer at Lyten.
Sulfur is widely abundant and inexpensive—a major reason that lithium-sulfur batteries could come with a much cheaper price tag. The cost of materials is around half that of lithium-ion cells, Mikolajczak says.
That doesn’t mean the cost for the new batteries will immediately be lower, though. Lithium-ion has had decades to slowly cut costs, as production has scaled and companies have worked out the kinks. But a lower cost of materials means the potential for cheaper batteries in the future.
Not only could lithium-sulfur batteries eventually provide a cheaper way to store energy—they could also beat out lithium-ion on a crucial metric: energy density. A lithium-sulfur battery can pack in nearly twice the energy as a lithium-ion battery of the same weight. That could be a major plus for electric vehicles, allowing automakers to build vehicles that can go farther on a single charge without weighing them down.
However, there are still major technical barriers Lyten needs to overcome for its products to be ready to hit the road in an EV. Chief among them is getting batteries to last.
Today’s lithium-ion batteries built for EVs can last for 800 cycles or more (meaning they can be sapped and recharged 800 times). Lithium-sulfur options tend to degrade much faster, with many efforts today hovering somewhere around 100 cycles, says Shirley Meng, a battery researcher at the University of Chicago and Argonne National Laboratory.
That’s because taming the chemical reactions that power lithium-sulfur batteries has proved to be a challenge. Unwanted reactions between lithium and sulfur can sap the life out of batteries and drive them to an early grave.
Lyten is far from the first to go after the promise of lithium-sulfur batteries, with companies big and small making forays into the chemistry for decades. Some, like UK-based Oxis Energy, have shuttered, while others, including Sion Power, have pivoted away from lithium-sulfur. But growing demand for alternatives, and a higher level of interest and funding, could mean that Lyten succeeds where earlier efforts have failed, Meng says.
Lyten has made progress in stretching the lifetime of its batteries, recently seeing some samples reach as high as 300 cycles, Mickolajczak says. She attributes the success to Lyten’s 3D graphene material, which helps prevent unwanted side reactions and boost the cell’s energy density. The company is also looking to use 3D graphene, a more complicated structure than the two-dimensional variety, in other products like sensors and composites.
Even with recent progress, Lyten is still far from producing batteries that can last long enough to power an EV. In the meantime, the company plans to bring its cells to market in places where lifetime isn’t quite so important.
Since lithium-sulfur batteries can be extremely lightweight, the company is working with customers building devices like drones, for which replacing the batteries frequently would be worth the savings on weight, says Keith Norman, Lyten’s chief sustainability officer.
The company opened a pilot manufacturing line in 2023 with a maximum capacity of 200,000 cells annually. It recently began producing a small number of cells, which are scheduled for delivery to paying customers later this year.
The company hasn’t publicly shared which companies will receive the first batteries. Moving forward, two of the company’s main focuses are improving lifetime and scaling production of both 3D graphene and battery cells, Norman says.
The road to lithium-sulfur batteries that can power EVs is still a long one, but as Mikolajczak points out, today’s staple chemistry, lithium-ion, has improved leaps and bounds on cost, lifetime, and energy density in the years that companies have been working to tweak it.
People have tried out a massive range of chemistry options in batteries, Mikolajczak says. “To make one of them reality requires that you put in the work.”
Heat pumps are still a hot technology, though sales in the US, one of the world’s largest markets, fell in 2023. Even with the drop, the appliances beat out gas furnaces for the second year in a row and saw their overall market share increase compared to furnaces, sales of which also fell last year.
Heat pumps heat and cool spaces using electricity, and they could be a major tool in the effort to cut greenhouse gas emissions. (About 10% of global emissions are generated from heating buildings.) Many homes and other buildings around the world use fossil fuels for heating in systems like gas furnaces—heat pumps are generally more efficient, and crucially, can be powered using renewable electricity. Experts say heat pump sales will need to grow quickly in order to keep buildings safe and comfortable while meeting climate goals.
Heat pumps have been around for decades, but the technology has been experiencing a clear moment in the sun in recent years, with global sales increasing by double digits in both 2021 and 2022, according to the International Energy Agency (IEA). Heat pumps were featured on MIT Technology Review’s 2024 list of 10 Breakthrough Technologies.
Sales fell by nearly 17% in 2023 in the US, one of the technology’s largest markets, according to new data from the Air-Conditioning, Heating, and Refrigeration Institute. The slowdown comes after nearly a decade of constant growth. The AHRI data isn’t comprehensive, but the organization includes manufacturers accounting for about 90% of the units sold in the US annually.
However, the decline likely says less about heat pumps than it does about the whole HVAC sector, since gas furnaces and air conditioners saw even steeper drops. Gas furnace sales declined even more than heat pumps did in 2023, so heat pumps actually made up a slightly larger percentage of sales this year than in 2022.
The broad slowdown reflects broader consumer pessimism amid higher interest rates and inflation, says Yannick Monschauer, an analyst at the IEA, via email.
“We have also been observing slowing heat pump sales in other parts of the world for 2023,” Monschauer adds. In Europe, a rush to electrify, driven by the energy crisis and rising natural gas prices, has slowed.
New incentives programs could help speed progress in 2024 and beyond. The Inflation Reduction Act, a sweeping climate bill passed in 2022, includes individual tax credits for up to $2,000 towards a new heat pump, which went into effect at the beginning of 2023.
However, the more generous incentives in that law have yet to take effect, says Wael Kanj, a research associate at Rewiring America, a nonprofit group focused on electrification in the US.
New rebates set aside funding of up to $8,000 towards a new heat pump system for low- and middle-income households. Distributing the rebates is up to individual states, and analysts anticipate those programs getting up and running in late 2024, or early 2025, Kanj says.
Heat pumps are a crucial component of plans to combat climate change. In a scenario where the world reaches net-zero emissions by 2050, heat pumps need to account for 20% of global heating capacity by the end of this decade, according to an IEA analysis.
“The next five, ten, 15 years are really going to be important,” Kanj says. “We definitely need to pick up the pace.”
This article is from The Spark, MIT Technology Review’s weekly climate newsletter. To receive it in your inbox every Wednesday, sign up here.
It must be tough to be a solar panel. They’re consistently exposed to sun, heat, and humidity—and the panels installed today are expected to last 30 years or more.
But how can we tell that new solar technologies will stand the test of time? I’m fascinated by the challenge of predicting how new materials will hold up in decades of tough conditions. That’s been especially tricky for one emerging technology in particular: perovskites. They’re a class of materials that developers are increasingly interested in incorporating into solar panels because of their high efficiency and low cost.
The problem is, perovskites are notorious for degrading when exposed to high temperatures, moisture, and bright light … all the things they’ll need to withstand to make it in the real world. And it’s not as if we can sit around for decades, testing out different cells in the field for the expected lifetime of a solar panel—climate change is an urgent problem. The good news: researchers have made progress in both stretching out the lifetime of perovskite materials and working out how to predict which materials will be winners in the long run.
There’s almost constant news about perovskite solar materials breaking records. The latest such news comes from Oxford PV—in January, the company announced that one of its panels reached a 25% conversion efficiency, meaning a quarter of the solar energy beaming onto the panel was converted to electricity. Most high-end commercial panels have around a 20% efficiency, with some models topping 23%.
The improvement is somewhat incremental, but it’s significant, and it’s all because of teamwork. Oxford PV and other companies are working to bring tandem solar technology to the market. These panels are basically sandwiches that combine layers of silicon (the material that dominates today’s solar market) and perovskites. Since the two materials soak up different wavelengths of light, they can be stacked together, adding up to a more efficient solar material.
We’re seeing advances in tandem technology, which is why we named super-efficient tandem solar cells one of our 2024 Breakthrough Technologies. But perovskites’ nasty tendency to degrade is a major barrier standing in the way.
Early perovskite solar cells went bad so quickly that researchers had to race across the laboratory to measure their efficiency. In the time it took to get from the area where solar cells were made to the side of the room where the testing equipment was, the materials basically lost their ability to soak up sunlight.
The lifetime of perovskite materials isn’t nearly this fleeting now, but it’s not clear that the problem has been entirely solved.
There’s been some real-world testing of new perovskite solar materials, with mixed results. Oxford PV hasn’t published detailed data, though as CTO Chris Case told Nature last year, the company’s outdoor tests show that the best cells lose only about 1% of their efficiency in their first year of operation, a rate that slows down afterwards.
Other testing in more intense conditions has found less positive results, with one academic study finding that perovskite cells in hot and humid Saudi Arabia lost 20% of their efficiency after one year of operation.
Those results are for one year of testing. How can we tell what will happen in 30 years?
Since we don’t have years to test every new material that scientists dream up, researchers often put them through especially punishing conditions in the lab, bumping up the temperature and shining bright lights onto panels to see how quickly they’ll degrade.
This sort of testing is standard for silicon solar panels, which make up over 90% of the commercial solar market today. But researchers are still working out just how well the correlations with known tests will transfer to new materials like perovskites.
One of the issues has been that light, moisture, and heat all contribute to the quick degradation of perovskites. But it hasn’t been clear exactly which factor, or combination of them, would be best to apply in the lab to measure how a solar panel would fare in the real world.
One study, published last year in Nature, suggested that a combination of high temperature and illumination would be the key to accelerated tests that reliably predict real-world performance. The researchers found that high-temperature tests lasting just a few hundred hours (a couple of weeks) translated well to nearly six months of performance in outdoor testing.
Companies say they’re bringing new solar materials to the market as soon as this year. Soon we’ll start to really see just how well these tests predict new technologies’ ability to withstand the tough job a commercial solar panel needs to do. I know I’ll be watching.
Related reading
Read more about why super-efficient tandem solar cells made our list of 10 Breakthrough Technologies in 2024 here.
Perovskites have been hailed as the hot new thing in solar for years. What’s been the holdup? In short: stability, stability, stability.
SARAH ROGERS/MITTR | GETTY
Explained
Welcome to the wonderful world of virtual power plants (VPPs). While they’re not physical facilities, VPPs could have actual benefits for emissions by stitching together different parts of the grid to help meet electricity demand.
What exactly is a VPP? How does it work? What does this all mean for climate action? Get the answers to all these questions and more in my colleague June Kim’s latest story.
Two more things
Scattering small particles in the upper levels of the atmosphere could help reflect sunlight, slowing down planetary warming. While this idea, called solar geoengineering, sounds farfetched, it’s possible that small efforts could get started within a decade, as David Keith and Wake Smith write in a new op-ed.
Read more about how geoengineering could start, and what these experts are saying we need to do about it, here.
The US is pausing exports of liquefied natural gas. The move was met with a wide range of reactions and plenty of questions about what it will mean for emissions.
As Arvind Ravikumar writes in a new op-ed, people are asking all the wrong questions about LNG. Whether this is a good idea depends on what the fuel would be replacing. Read his full take here.
Keeping up with climate
In an age of stronger hurricanes, some scientists say our current rating system can’t keep up. Adding a Category 6 could help us designate super-powerful storms. (Inside Climate News)
A fringe idea to put massive sunshades in space to cool down the planet is gaining momentum. Or we could, you know, stop burning fossil fuels? (New York Times)
Trains powered by hydrogen are starting to hit the rails. Here’s why experts say that might not be the best use for the fuel. (Canary Media)
According to the sponges, we’ve already sailed past climate goals. Scientists examining the skeletons of creatures called sclerosponges concluded that human-caused climate change has probably raised temperatures by 1.7 °C (3.1 °F) since the late 19th century. (New York Times)
A century-old law you’ve never heard of is slowing down offshore wind in the US. By requiring the use of US-built ships within the country’s waters, the Jones Act is behind some of the speed bumps facing the offshore wind industry. (Hakai Magazine)
→ Here’s what’s next for offshore wind, including when we can expect the first US-built ship to hit the waters. (MIT Technology Review)
Sorting recycling is a tough job, but AI might be able to help. New sorting systems could rescue more plastic from the landfill, though rolling out new technology to sorting facilities will be a challenge. (Washington Post)
This article is from The Spark, MIT Technology Review’s weekly climate newsletter. To receive it in your inbox every Wednesday, sign up here.
It must be tough to be a solar panel. They’re consistently exposed to sun, heat, and humidity—and the panels installed today are expected to last 30 years or more.
But how can we tell that new solar technologies will stand the test of time? I’m fascinated by the challenge of predicting how new materials will hold up in decades of tough conditions. That’s been especially tricky for one emerging technology in particular: perovskites. They’re a class of materials that developers are increasingly interested in incorporating into solar panels because of their high efficiency and low cost.
The problem is, perovskites are notorious for degrading when exposed to high temperatures, moisture, and bright light … all the things they’ll need to withstand to make it in the real world. And it’s not as if we can sit around for decades, testing out different cells in the field for the expected lifetime of a solar panel—climate change is an urgent problem. The good news: researchers have made progress in both stretching out the lifetime of perovskite materials and working out how to predict which materials will be winners in the long run.
There’s almost constant news about perovskite solar materials breaking records. The latest such news comes from Oxford PV—in January, the company announced that one of its panels reached a 25% conversion efficiency, meaning a quarter of the solar energy beaming onto the panel was converted to electricity. Most high-end commercial panels have around a 20% efficiency, with some models topping 23%.
The improvement is somewhat incremental, but it’s significant, and it’s all because of teamwork. Oxford PV and other companies are working to bring tandem solar technology to the market. These panels are basically sandwiches that combine layers of silicon (the material that dominates today’s solar market) and perovskites. Since the two materials soak up different wavelengths of light, they can be stacked together, adding up to a more efficient solar material.
We’re seeing advances in tandem technology, which is why we named super-efficient tandem solar cells one of our 2024 Breakthrough Technologies. But perovskites’ nasty tendency to degrade is a major barrier standing in the way.
Early perovskite solar cells went bad so quickly that researchers had to race across the laboratory to measure their efficiency. In the time it took to get from the area where solar cells were made to the side of the room where the testing equipment was, the materials basically lost their ability to soak up sunlight.
The lifetime of perovskite materials isn’t nearly this fleeting now, but it’s not clear that the problem has been entirely solved.
There’s been some real-world testing of new perovskite solar materials, with mixed results. Oxford PV hasn’t published detailed data, though as CTO Chris Case told Nature last year, the company’s outdoor tests show that the best cells lose only about 1% of their efficiency in their first year of operation, a rate that slows down afterwards.
Other testing in more intense conditions has found less positive results, with one academic study finding that perovskite cells in hot and humid Saudi Arabia lost 20% of their efficiency after one year of operation.
Those results are for one year of testing. How can we tell what will happen in 30 years?
Since we don’t have years to test every new material that scientists dream up, researchers often put them through especially punishing conditions in the lab, bumping up the temperature and shining bright lights onto panels to see how quickly they’ll degrade.
This sort of testing is standard for silicon solar panels, which make up over 90% of the commercial solar market today. But researchers are still working out just how well the correlations with known tests will transfer to new materials like perovskites.
One of the issues has been that light, moisture, and heat all contribute to the quick degradation of perovskites. But it hasn’t been clear exactly which factor, or combination of them, would be best to apply in the lab to measure how a solar panel would fare in the real world.
One study, published last year in Nature, suggested that a combination of high temperature and illumination would be the key to accelerated tests that reliably predict real-world performance. The researchers found that high-temperature tests lasting just a few hundred hours (a couple of weeks) translated well to nearly six months of performance in outdoor testing.
Companies say they’re bringing new solar materials to the market as soon as this year. Soon we’ll start to really see just how well these tests predict new technologies’ ability to withstand the tough job a commercial solar panel needs to do. I know I’ll be watching.
Related reading
Read more about why super-efficient tandem solar cells made our list of 10 Breakthrough Technologies in 2024 here.
Perovskites have been hailed as the hot new thing in solar for years. What’s been the holdup? In short: stability, stability, stability.
SARAH ROGERS/MITTR | GETTY
Explained
Welcome to the wonderful world of virtual power plants (VPPs). While they’re not physical facilities, VPPs could have actual benefits for emissions by stitching together different parts of the grid to help meet electricity demand.
What exactly is a VPP? How does it work? What does this all mean for climate action? Get the answers to all these questions and more in my colleague June Kim’s latest story.
Two more things
Scattering small particles in the upper levels of the atmosphere could help reflect sunlight, slowing down planetary warming. While this idea, called solar geoengineering, sounds farfetched, it’s possible that small efforts could get started within a decade, as David Keith and Wake Smith write in a new op-ed.
Read more about how geoengineering could start, and what these experts are saying we need to do about it, here.
The US is pausing exports of liquefied natural gas. The move was met with a wide range of reactions and plenty of questions about what it will mean for emissions.
As Arvind Ravikumar writes in a new op-ed, people are asking all the wrong questions about LNG. Whether this is a good idea depends on what the fuel would be replacing. Read his full take here.
Keeping up with climate
In an age of stronger hurricanes, some scientists say our current rating system can’t keep up. Adding a Category 6 could help us designate super-powerful storms. (Inside Climate News)
A fringe idea to put massive sunshades in space to cool down the planet is gaining momentum. Or we could, you know, stop burning fossil fuels? (New York Times)
Trains powered by hydrogen are starting to hit the rails. Here’s why experts say that might not be the best use for the fuel. (Canary Media)
According to the sponges, we’ve already sailed past climate goals. Scientists examining the skeletons of creatures called sclerosponges concluded that human-caused climate change has probably raised temperatures by 1.7 °C (3.1 °F) since the late 19th century. (New York Times)
A century-old law you’ve never heard of is slowing down offshore wind in the US. By requiring the use of US-built ships within the country’s waters, the Jones Act is behind some of the speed bumps facing the offshore wind industry. (Hakai Magazine)
→ Here’s what’s next for offshore wind, including when we can expect the first US-built ship to hit the waters. (MIT Technology Review)
Sorting recycling is a tough job, but AI might be able to help. New sorting systems could rescue more plastic from the landfill, though rolling out new technology to sorting facilities will be a challenge. (Washington Post)
The motor in your vacuum cleaner and the one in your electric vehicle likely have at least one thing in common: they both rely on powerful permanent magnets to function. And the materials for those magnets could soon be in short supply.
Permanent magnets can maintain a magnetic field on their own without an electric charge. They’re commonly used in motors, making them spin when an electric field is applied. The permanent magnets used in high-end motors today are built using a class of materials called rare earth metals. Demand for these materials is expected to skyrocket in the coming decades, fueled in particular by the growth of electric vehicles and wind turbines. As mines and processing facilities struggle to keep up, supplies may stretch thin.
One Minnesota startup has been working to address this looming shortage. Niron Magnetics is building a large-scale manufacturing facility to produce iron nitride, a magnetic material derived from common elements, while also working to improve the material’s properties so that it can be used in stronger magnets to power more products. The results may help address yet another coming supply crunch that threatens to slow down action on climate change.
A growing gap
The permanent magnets you’re probably most familiar with are the cheap ones made from materials called ferrites that are holding up postcards and wedding announcements on your refrigerator.
But many of the devices sprinkled through our daily lives, like our vacuums and EVs, require much higher-powered magnets. Motors that generate motion using permanent magnets tend to be more powerful and efficient, so rare earth metals, such as neodymium and dysprosium, have become vital for a wide range of devices. In a wind turbine, for instance, magnets in the generator harness motion from the blades and turn it into electricity.
Like many of the other materials needed for clean energy technologies, we can expect a meteoric rise in demand for rare earth metals used in magnets as the world rushes to address climate change.
In the case of neodymium and dysprosium, supply will need to increase sevenfold by 2050 just to meet demand for wind turbines, says Seaver Wang, co-director of the climate and energy team at the Breakthrough Institute, an environment and policy think tank.
In addition, rare earth metal demand for electric vehicles could increase 15-fold from today’s levels by 2040, according to an analysis from the International Energy Agency. And it’s not just clean energy technologies—increased access to electricity and cheap electronics means demand for rare earth metals will rise across other sectors, too.
The world is unlikely to exhaust the geological reserves of rare earth metals anytime soon, Breakthrough’s Wang says—rare earth metals aren’t actually all that rare, at least when it comes to the entire planet’s supply. But they don’t tend to be very concentrated even in the places they are found, so scaling the supply of rare earth metals quickly and economically enough will be a major challenge.
In the near term, global demand for magnets made with neodymium could triple by 2035, while production will likely only double by then, given the long lead times required to build new mines, according to materials research firm Adamas Intelligence.
Given the growing demand, “the world needs a different solution and technology,” says Jonathan Rowntree, CEO of Niron Magnetics.
Few alternatives to permanent magnets exist today. Recycling can help reduce the need for future rare earth mining and processing, but there won’t be enough used material to meet the growing demand for decades.
Rowntree and his colleagues see iron nitride as part of the solution to the anticipated problem of constraints in the supply of rare earth metals. Iron nitride magnets don’t use those metals, and they don’t require cobalt, another metal sometimes used in magnets (and in lithium-ion batteries) that’s under growing scrutiny because of the environmental and humanitarian issues often associated with its mining. And some experts say these iron-based materials might end up creating magnets just as strong as those that include rare earth metals.
An attractive alternative
Though iron nitride (specifically, a phase called alpha double prime) was discovered in the 1950s, it wasn’t until the 1970s that researchers discovered its strong magnetic properties, says Jian-Ping Wang, a professor at the University of Minnesota and the technical founder and chief scientist at Niron Magnetics.
Even then, scientists couldn’t explain the physics underlying the material’s magnetic properties, and they struggled to recreate magnetic samples reliably through the 1990s. Intrigued by this problem, Wang began work on iron nitride materials at the university in 2002.
After making hundreds of samples and working for nearly a decade, Wang cracked the code to reliably make iron nitride materials in thin films. He presented his findings at a major conference in 2010, the same year geopolitical tensions between Japan and China sparked a huge increase in the price of rare earth metals.
Suddenly, there was a greater appetite for alternatives to rare earths that could be used to make strong permanent magnets. The US Department of Energy’s ARPA-E office sponsored grants to develop such materials, awarding one to Wang and the research that would eventually become Niron Magnetics.
Rare earth metals became ubiquitous across technologies because they represented “a huge jump” in the energy density of magnets when they were discovered in the 1960s, says Matthew Kramer, a senior scientist at Ames National Laboratory.
One of the primary gauges of a magnet’s properties is its energy density, measured in mega-gauss-oersteds (MGOe). While the ferrite magnets on your fridge likely have an MGOe of around 5, neodymium-based magnets are much stronger, reaching around 50 MGOe.
Rare earth metals like neodymium are currently a crucial ingredient in permanent magnets because they can wrangle other metals into an arrangement that helps generate a strong magnetic field.
Permanent magnets produce magnetic fields because of spinning electrons, small charged particles in atoms. Different elements have different numbers of free electrons that in some circumstances can be made to spin in the same direction, generating a magnetic field. The more electrons that are free and spinning in the same direction, the stronger the magnetic field.
Iron has a lot of free electrons, but without an overarching structure they tend to spin in different directions, canceling each other out. Adding in neodymium, dysprosium, and other rare earth metals can help arrange iron atoms in a way that allows their electrons to work together, resulting in powerful magnets.
Iron nitride does what few other materials can: it arranges iron into a structure that gets electrons spinning together in this way and keeps them aligned—no rare earth metals required.
“If you could get the nitrogen to spread these irons out in the appropriate way, you should be able to potentially get a really, really good permanent magnet,” Kramer says. That has proven to be a challenge though, he adds, because it’s difficult to make these materials in bulk and to harness the complex chemistry in a way that forces them to retain their magnetization.
Idea to execution
After Wang was able to reliably create thin films of iron nitride, the next step was to figure out how to make it in bulk, grind it up, and squish it together to make magnets.
Finding a manufacturing process was a challenge in part because iron nitride degrades at high temperatures, which limits the options available in traditional magnet manufacturing, Wang explains. He developed several methods to make iron nitride in bulk, one of the most promising of which involves diffusing nitrogen through iron oxide (rust is a type of iron oxide) under very specific conditions.
In recent years, Niron has focused on perfecting and scaling up the manufacturing process, Rowntree says. A significant remaining challenge is determining how to help iron nitride reach its full potential.
NIRON MAGNETICS
In theory, iron nitride should be able to produce magnets that are even stronger than neodymium ones. But today, Niron’s magnets can only reach around 10 MGOe, Rowntree says. That’s sufficient for devices like speakers, which the company is exploring as an early product. It displayed small speakers made with Niron magnets at CES in January.
With higher magnet strength, iron nitride magnets will be more useful in devices like electric vehicles and wind turbines. In theory, the material should be able to reach 20 to 30 MGOe using Niron’s current manufacturing method, Wang says, though achieving that will require “a lot of optimization.” The theoretical ceiling is much higher, with iron nitride potentially being able to form magnets stronger than the neodymium ones used today.
Niron recently received over $30 million from investors, including GM Ventures and Stellantis Ventures, for a total of more than $100 million in funding. The company is working to scale up production capacity in its current pilot plant, with the aim of reaching 1,000 kilograms of production capacity by the end of 2024.
Niron’s work, along with other alternatives and workarounds, could be crucial in loosening a major potential bottleneck for several critical climate technologies.
“Increased magnets and increased magnet supply are critical to enabling the energy transition,” says Gregg Cremer, an advisor at ARPA-E. “Without more magnets, we’re just not going to be able to meet our objectives.”
A collection of brown pipes emerge at odd angles from the mud and overgrown grasses on a pine farm north of the tiny town of Tamarack, Minnesota.
Beneath these capped drill holes, Talon Metals has uncovered one of America’s densest nickel deposits—and now it wants to begin tunneling deep into the rock to extract hundreds of thousands of metric tons of mineral-rich ore a year.
If regulators approve the mine, it could mark the starting point in what this mining exploration company claims would become the country’s first complete domestic nickel supply chain, running from the bedrock beneath the Minnesota earth to the batteries in electric vehicles across the nation.
This is the second story in a two-part series exploring the hopes and fears surrounding a single mining proposal in a tiny Minnesota town. You can read the first part here.
The US government is poised to provide generous support at every step, distributing millions to billions of dollars in subsidies for those refining the metal, manufacturing the batteries, and buying the cars and trucks they power.
The products generated with the raw nickel that would flow from this one mining project could theoretically net more than $26 billion in subsidies, just through federal tax credits created by the Inflation Reduction Act (IRA). That’s according to an original analysis by Bentley Allan, an associate professor of political science at Johns Hopkins University and co-director of the Net Zero Industrial Policy Lab, produced in coordination with MIT Technology Review.
One of the largest beneficiaries would be battery manufacturers that use Talon’s nickel, which could secure more than $8 billion in tax credits. About half of that could go to the EV giant Tesla, which has already agreed to purchase tens of thousands of metrictons of the metal from this mine.
But the biggest winner, at least collectively, would be American consumers who buy EVs powered by those batteries. All told, they could enjoy nearly $18 billion in savings.
While it’s been widely reported that the IRA could unleash at least hundreds of billions of federal dollars, MIT Technology Review wanted to provide a clearer sense of the law’s on-the-ground impact by zeroing in on a single project and examining how these rich subsidies could be unlocked at each point along the supply chain. (Read my related story on Talon’s proposal and the community reaction to it here.)
We consulted with Allan to figure out just how much money is potentially in play, where it’s likely to go, and what it may mean for emerging industries and the broader economy.
These calculations are all high-end estimates meant to assess the full potential of the act, and they assume that every company and customer qualifies for every tax credit available at each point along the supply chain. In the end, the government almost certainly won’t hand out the full amounts that Allan calculated, given the varied and complex restrictions in the IRA and other factors.
In addition, Talon itself may not obtain any subsidies directly through the law, according to recent but not-yet-final IRS interpretations. But thanks to rich EV incentives that will stimulate demand for domestic critical minerals, the company still stands to benefit indirectly from the IRA.
How $26 billion in tax credits could break down across a new US nickel supply chain
The sheer scale of the numbers offer a glimpse into how and why the IRA, signed into law in August 2022, has already begun to drive projects, reconfigure sourcing arrangements, and accelerate the shift away from fossil fuels.
Indeed, the policies have dramatically altered the math for corporations considering whether, where, and when to build new facilities and factories, helping to spur at least tens of billions of dollars’ worth of private investments into the nation’s critical-mineral-to-EV supply chain, according to several analyses.
“If you try to work out the math on these for five minutes, you start to be really shocked by what you see on paper,” Allan says, noting that the IRA’s incentives ensure that many more projects could be profitably and competitively developed in the US. “It’s going to transform the country in a serious way.”
An urgent game of catch-up
For decades, the US steadily offshored the messy business of mining and processing metals, leaving other nations to deal with the environmental damage and community conflicts that these industries often cause. But the country is increasingly eager to revitalize these sectors as climate change and simmering trade tensions with China raise the economic, environmental, and geopolitical stakes.
Critical minerals like lithium, cobalt, nickel, and copper are the engine of the emerging clean-energy economy, essential for producing solar panels, wind turbines, batteries, and EVs. Yet China dominates production of the source materials, components, and finished goods for most of these products, following decades of strategic government investments and targeted trade policies. It refines 71% of the type of nickel used for batteries and produces more than 85% of the world’s battery cells, according to Benchmark Mineral Intelligence.
The US is now in a high-stakes scramble to catch up and ensure its unfettered access to these materials, either by boosting domestic production or by locking in supply chains through friendly trading partners. The IRA is the nation’s biggest bet, by far, on bolstering these industries and countering China’s dominance over global cleantech supply chains. By some estimates, it could unlock more than $1 trillion in federal incentives.
“It should be sufficient to drive transformational progress in clean-energy adoption in the United States,” says Kimberly Clausing, a professor at the UCLA School of Law who previously served as deputy assistant secretary for tax analysis at the Treasury Department. “The best modeling seems to show it will reduce emissions substantially, getting us halfway to our Paris Agreement goals.”
Among other subsidies, the IRA provides tax credits that companies can earn for producing critical minerals, electrode materials, and batteries, enabling them to substantially cut their federal tax obligations.
But the provisions that are really driving the rethinking of sourcing and supply chains are the so-called domestic content requirements contained in the tax credits for purchasing EVs. For consumers to earn the full credits, and for EV makers to benefit from the boost in demand they’ll generate, a significant share of the critical minerals the batteries contain must be produced in the US, sourced from free-trade partners, or recycled in North America, among other requirements.
This makes the critical minerals coming out of a mine like Talon’s especially valuable to US car companies since it could help ensure that their EV models and customers qualify for these credits.
Mining and refining
Nickel, like the deposits found in Minnesota, is of particular importance for cleaning up the auto sector. The metal boosts the amount of energy that can be packed into battery cathodes, extending the range of cars and making possible heavier electric vehicles, like trucks and even semis.
Global nickel demand could rise 112% by 2040, according to the International Energy Agency, owing primarily to an expected ninefold increase in demand for EV batteries. But there’s only one dedicated nickel mine operating in the US today, and most processing of the metal happens overseas.
A former Talon worker pulls tubes of bedrock from drill pipe and places them into a box for further inspection.
ACKERMAN + GRUBER
In a preliminary economic analysis of the proposed mine released in 2021, Talon said it hoped to dig up nearly 11 million metric tons of ore over a nine-year period, including more than 140,000 tons of nickel. That’s enough to produce lithium-ion batteries that could power almost 2.4 million electric vehicles, Allan finds.
After Talon mines the ore, the company plans to ship the material more than 400 miles west by rail to a planned processing site in central North Dakota that would produce what’s known as “nickel in concentrate,” which is generally around 10% pure.
But that’s not enough to earn any subsidies under the current interpretation of the IRA’s tax credit for critical-mineral production. The law specifies that a company must convert nickel into a highly refined form known as “nickel sulphate” or process the metal to at least 99% purity by mass to be eligible for tax credits that cover 10% of the operating cost. Allan estimates that whichever company or companies carry out that step could earn subsidies that exceed $55 million.
From there, the nickel would still need to be processed and mixed with other metals to produce the “cathode active materials” that go into a battery. Whatever companies carry out that step could secure some share of another $126.5 million in tax savings, thanks to a separate credit covering 10% of the costs of generating these materials, Allan notes.
Some share of the subsidies from these two tax credits might go to Tesla, which has stressed that it’s bringing more aspects of battery manufacturing in-house. For instance, it’s in the process of constructing its own lithium refinery and cathode plant in Texas.
But it’s not yet clear what other companies could be involved in processing the nickel mined by Talon and, thus, who would benefit from these particular provisions.
Talon and other mining companies have campaigned to have the costs for mining raw materials included in the critical-mineral production tax credit, but the IRS recently stated in a proposed rule that this step won’t qualify.
Todd Malan, Talon’s chief external affairs officer and head of climate strategy, argues that this and other recent determinations will limit the incentives for companies to develop new mines in the US, or to make sure that any mines that are developed meet the higher environmental and labor standards the Biden administration and others have been calling for.
(The determinations could change since the Treasury Department and IRS have said they are still considering including the costs of mining in the tax credits. They have requested additional comments on the matter.)
Even if Talon doesn’t obtain any IRA subsidies, it still stands to earn federal funds in several other ways. The company is set to receive a nearly $115 million grant from the Department of Energy to build the North Dakota processing site, through funds freed up under the Bipartisan Infrastructure Law. In addition, in September Talon secured nearly $21 million in matching grants through the Defense Production Act, which will support further nickel exploration in Minnesota and at another site the company is evaluating in Michigan. (These numbers are not included in Allan’s overall $26 billion estimate.)
Talon Metals could receive $136 million in federal subsidies
The math
Allan says that his findings are best thought of as ballpark figures. Some of Talon’s estimates have already changed, and the actual mineral quantities and operating costs will depend on a variety of factors, including how the company’s plans shift, what state and local regulators ultimately approve, what Talon actually pulls out of the ground, how much nickel the ore contains, and how much costs shift throughout the supply chain in the coming years.
His analysis assumes a preparation cost of $6.68 per kilowatt-hour for cathode active materials, based on an earlier analysis in the journal Energies. It did not evaluate any potential subsidies associated with other metals that Talon may extract from the mine, such as iron, copper, and cobalt. Please see his full research brief on the Net Zero Industrial Policy Lab site.
Companies can use the IRA tax credits to reduce or even eliminate their federal tax obligations, both now and in tax years to come. In addition, businesses can transfer and sell the tax credits to other taxpayers.
Most of the tax credits in the IRA begin to phase out in 2030, so companies need to move fast to take advantage of them. The subsidies for critical-mineral production, however, don’t have any such cutoff.
Where will the money go and what will it do?
The $136 million in direct federal grants would double Talon’s funds for exploratory drilling efforts and cover about 27% of the development cost for its North Dakota processing plant.
The company says that these projects will help accelerate the country’s shift toward EVs and reduce the nation’s reliance on China for critical minerals. Further, Talon notes the mine will provide significant local economic benefits, including about 300 new jobs. That’s in addition to the nearly 100 employees already working in or near Tamarack. The company also expects the operation to generate nearly $110 million in mineral royalties and taxes paid to the state, local government, and the regional school district.
Plenty of citizens around Tamarack, however, argue that any economic benefits will come with steep trade-offs in terms of environmental and community impacts. A number of local tribal members fear the project could contaminate waterways and harm the region’s plants and animals.
“The energy transition cannot be built by desecrating native lands,” said Leanna Goose, a member of the Leech Lake Band of Ojibwe, in an email. “If these ‘critical’ minerals leave the ground and are taken out from on or near our reservations, our people would be left with polluted water and land.”
Meanwhile, as it becomes clear just how much federal money is at stake, opposition to the IRA and other climate-related laws is hardening. Congressional Republicans, some of whom have portrayed the tax subsidies as corporate handouts to the “wealthy and well connected,” have repeatedly attempted to repeal key provisions of the laws. In addition, some environmentalists and left-wing critics have chided the government for offering generous subsidies to controversial companies and projects, including Talon’s.
Talon stresses that it has made significant efforts to limit pollution and address Indigenous concerns. In addition, Malan pushed back on Allan’s findings. He says the overall estimate of $26 billion in subsidies across the supply chain significantly exaggerates the likely outcome, given numerous ways that companies and consumers might fail to qualify for the tax credits.
“I think it’s too much to tie it back to a little mining company in Minnesota,” he says.
He emphasizes that Talon will earn money only for selling the metal it extracts, and that it will receive other federal grants only if it secures permits to proceed on its projects. (The company could also apply to receive separate IRA tax credits that cover a portion of the investments made into certain types of energy projects, but it has not at this time.)
Boosting the battery sector
The next stop in the supply chain is the battery makers.
The amount of nickel that Talon expects to pull from the mine could be used to produce cathodes for nearly 190 million kilowatt-hours’ worth of lithium-ion batteries, according to Allan’s findings.
Manufacturing that many batteries could generate some $8.5 billion from a pair of IRA tax credits worth $45 per kilowatt-hour, dwarfing the potential subsidies for processing the nickel.
Any number of companies might purchase metals from Talon to build batteries, but Tesla has already agreed to buy 75,000 tons of nickel in concentrate from the North Dakota facility. (The companies have not disclosed the financial terms of the deal.)
Given the batteries that could be produced with this amount of metal, Tesla’s share of these tax savings could exceed $4 billion, Allan found.
The tax credits add up to “a third of the cost of the battery, full stop,” he says. “These are big numbers. The entire cost of building the plant, at least, is covered by the IRA.”
What Talon’s nickel may mean for Tesla
The math
The subsidies for battery makers would flow from two credits within the IRA. Those include a $35-per-kilowatt-hour tax credit for manufacturing battery cells and a $10-per-kilowatt-hour credit for producing battery modules, which are the bundles of interoperating cells that slot into vehicles. Allan’s calculations assume that all the metal will be used to produce nickel-rich NMC 811 batteries, and that every EV will include an 80-kilowatt-hour battery pack that costs $153 per kilowatt-hour to produce.
Where will the money go and what will it do?
Those billions are just what Tesla could secure in tax credits from the nickel it buys from Talon. It and other battery makers could qualify for still more government subsidies for batteries produced with critical minerals from other sources.
Tesla didn’t respond to inquiries from MIT Technology Review. But its executives have said they believe Tesla’s batteries will qualify for the manufacturing tax credits, even before Talon’s mining and processing plants are up and running.
On an earnings call last January, Zachary Kirkhorn, who was then the company’s chief financial officer, said that Tesla expected the battery subsidies from its current production lines to total $150 million to $250 million per quarter in 2023. He said the company intends to use the tax credits to lower prices and promote greater adoption of electric vehicles: “We want to use this to accelerate sustainable energy, which is our mission and also the goal of [the IRA].”
But these potential subsidies are clear evidence that the US government is dedicating funds to the wrong societal priorities, says Jenna Yeakle, an organizer for the Sierra Club North Star Chapter in Minnesota, which added its name to a letter to the White House criticizing federal support for Talon’s proposals.
“People are struggling to pay rent and put food on the table and to navigate our monopolized corporate health-care system,” she says. “Do we need to be subsidizing Elon Musk’s bank account?”
Still, the IRA’s tax credits will go to numerous battery companies beyond Tesla.
In fact, the incentives are already reshaping the marketplace, driving a sharp increase in the number of battery and electric-vehicle projects announced, according to the EV Supply Chain Dashboard, a database managed by Jay Turner, a professor of environmental studies at Wellesley College and author of Charged: A History of Batteries and Lessons for a Clean Energy Future.
As of press time, 81 battery and EV-related projects representing $79 billion in investments and more than 50,000 jobs have been announced across the US since Biden signed the IRA. On an annual basis, that’s nearly three times the average dollar figures announced in recent years before the law was enacted. The projects include BMW, Hyundai, and Ford battery plants, Tesla’s semi manufacturing pilot plant in Nevada, and Redwoods Materials’ battery recycling facility in South Carolina.
“It’s really exceptional,” Turner says. “I don’t think anybody expected to see so many battery projects, so many jobs, and so many investments over the past year.”
Driving EV sales
The biggest subsidy, though also the most diffuse one, would go to American consumers.
The IRA offers two tax credits worth up to $7,500 combined for purchasing EVs and plug-in hybrids if the battery materials and components comply with the domestic content requirements.
Since the nickel that Talon expects to extract from the Minnesota mine could power nearly 2.4 million electric vehicles, consumers could collectively see $17.7 billion in potential savings if all those vehicles qualify for both credits, Allan finds.
Talon’s Malan says this estimate significantly overstates the likely consumer savings, noting that many purchases won’t qualify. Indeed, an individual with a gross income that exceeds $150,000 won’t be eligible, nor will pickups, vans, and SUVs that cost more than $80,000. That would rule out, for instance, the high-end model of Tesla’s Cybertruck.
A number of Tesla models are currently excluded from one or both consumer credits, for varied and confusing reasons. But the Talon deal and other recent sourcing arrangements, as well as the company’s plans to manufacture more of its own batteries, could help more of Tesla’s vehicles to qualify in the coming months or years.
The IRA’s consumer incentives are likely to do more to stimulate demand than previous federal EV policies, in large part because customers can take them in the form of a price cut at the point of sale, says Gil Tal, director of the Electric Vehicle Research Center at the University of California, Davis. Previously, such incentives would simply reduce the buyer’s federal obligations come tax season.
RMI, a nonprofit research group focused on clean energy, projects that all the EV provisions within the IRA, which also include subsidies for new charging stations, will spur the sales of an additional 37 million electric cars and trucks by 2032. That would propel EV sales to around 80% of new passenger-automobile purchases. Those vehicles, in turn, could eliminate 2.4 billion tons of transportation emissions by 2040.
In a preliminary economic analysis, Talon said it hoped to dig up more than 140,000 tons of nickel. That’s enough to produce lithium-ion batteries that could power almost 2.4 million electric vehicles.
TESLA
The math
The IRA offers two tax credits that could apply to EV buyers. The first is a $3,750 credit for those who purchase vehicles with batteries that contain a significant portion of critical minerals that were mined or processed in the US, or in a country with which the US has a free-trade agreement. The required share is 50% in 2024 but reaches 80% beginning in 2027. Cars and trucks may also qualify if the materials came from recycling in North America.
Buyers can also earn a separate $3,750 credit if a specified share of the battery components in the vehicle were manufactured or assembled in North America. The share is 60% this year and next but reaches 100% in 2029.
The big bet
There are lingering questions about how many of the projects sparked by the country’s new green industrial policies will ultimately be built—and what the US will get for all the money it’s giving up.
After all, the tens of billions of dollars’ worth of tax credits that could be granted throughout the Talon-to-Tesla-to-consumer nickel supply chain is money that isn’t going to the federal government, and isn’t funding services for American taxpayers.
The IRA’s impacts on tax coffers are certain to come under greater scrutiny as the programs ramp up, the dollar figures rise, projects run into trouble, and the companies or executives benefiting engage in questionable practices. After all, that’s exactly what happened in the aftermath of the country’s first major green industrial policy efforts a decade ago, when the high-profile failures of Solyndra, Fisker, and other government-backed clean-energy ventures fueled outrage among conservative critics.
Nevertheless, Tom Moerenhout, a research scholar at Columbia University’s Center on Global Energy Policy, insists it’s wrong to think of these tax credits as forgone federal revenue.
In many cases, the projects set to get subsidies for 10% of their operating costs would not otherwise have existed in the first place, since those processing plants and manufacturing facilities would have been built in other, cheaper countries. “They would simply go to China,” he says.
UCLA’s Clausing doesn’t entirely agree with that take, noting that some of this money will go to projects that would have happened anyway, and some of the resources will simply be pulled from other sectors of the economy or different project types.
“It doesn’t behoove us as experts to argue this is free money,” she says. “Resources really do have costs. Money doesn’t grow on trees.”
But any federal expenses here are “still cheaper than the social cost of carbon,” she adds, referring to the estimated costs from the damage associated with ongoing greenhouse-gas pollution. “And we should keep our eyes on the prize and remember that there are some social priorities worth paying for—and this is one of those.”
In the end, few expect the US’s sweeping climate laws to completely achieve any of the hopes underlying them on their own. They won’t propel the US to net-zero emissions. They won’t enable the country to close China’s massive lead in key minerals and cleantech, or fully break free from its reliance on the rival nation. Meanwhile, the battle to lock down access to critical minerals will only become increasingly competitive as more nations accelerate efforts to move away from fossil fuels—and it will generate even more controversy as communities push back against proposals over concerns about environmental destruction.
But the evidence is building that the IRA in particular is spurring real change, delivering at least some progress on most of the goals that drove its passage: galvanizing green-tech projects, cutting emissions, creating jobs, and moving the nation closer to its clean-energy future.
“It is catalyzing investment up and down the supply chain across North America,” Allan says. “It is a huge shot in the arm of American industry.”
This article is from The Spark, MIT Technology Review’s weekly climate newsletter. To receive it in your inbox every Wednesday, sign up here.
The world is building solar panels, wind turbines, electric vehicles, and other crucial climate technologies faster than ever. As the pace picks up, though, a challenge is looming: we need a whole lot of materials to build it all.
From cement and steel to nickel and lithium, the ingredient list for the clean energy transition is a long one. And in some cases, getting our hands on all those materials won’t be simple, and the trade-offs are starting to become abundantly clear.
My colleague James Temple, senior editor for energy here at MIT Technology Review, has spent over a year digging into the building tensions around mining for critical minerals. In a new story published this week, James highlights one community in rural Minnesota and the conflicts over a mining project planned for the nearby area.
If you haven’t already, I highly recommend you check out that article. In the meantime, I got to sit down with James to ask him a few questions about the process of reporting and writing this feature and chat about critical minerals and the energy transition. Here’s some of what we talked about.
So, what’s the big deal with critical minerals?
To address climate change, “we just need to build an enormous amount of stuff,” James says. And building all of it means a whole lot of demand for materials.
We might need nearly 20 times more nickel in 2040 than the annual supply in 2020, according to the International Energy Agency. That multiple is 25 times for graphite, and for lithium it’s over 40 times the current figure.
Even if people agree in the abstract that we need to extract and process the materials needed to build the stuff to address climate change, figuring out where it all should come from is easier said than done. “We came to realize that mining proposals were creating community tensions basically anywhere they appeared in the US,” James says.
There’s pushback to all sorts of different climate tech projects—we’ve seen very vocal opposition to proposed wind farms, for example. But there seems to be an additional layer to the concerns around mining, James says. Among other reasons, it’s a legacy industry with a particularly checkered past in terms of environmental impact.
Even as communities raise concerns over new mining projects, “you also saw the companies proposing them stressing the potential benefits to cleantech and climate goals,” James says. This combination of clear potential climate benefits with community concerns was worth exploring, he tells me.
What does a proposed nickel mine near a small town in Minnesota tell us about conflict over critical minerals?
The town of Tamarack, Minnesota, has a population of around 70.
Despite its small size, Tamarack could soon be key to a crucial landmark for climate technology, because Talon Metals wants to build a huge mine outside the town that could dig up as much as 725,000 metric tons of raw ore each year. The primary target is nickel, a metal that’s crucial to building high-performance EV batteries.
Talon has been very explicit in claiming that this mine would have benefits for the planet, going as far as applying to trademark the term “Green Nickel.” That’s one of the reasons this particular site piqued James’s interest, he says.
At the same time, local concerns are growing. Drilling could release 2.6 million gallons of water into the mine every day, which Talon plans to pump out and treat before it’s released into nearby wetlands. This part of the plan has caused some of the greatest unease, since local fresh water is crucial to the community’s economy and identity.
The central tension was abundantly clear on a nearly weeklong trip to Tamarack and the surrounding communities, James tells me. He went to Rice Lake National Wildlife Refuge and learned about native wild rice that grows there and its importance to Indigenous groups. He went to see samples of the ore that Talon dug up and spoke to a geologist about the resources in the region. He also attended community meetings that got a little heated, and even had to contend with some local bees.
“We’re talking about a story of two different, very precious resources that have created a really difficult-to-address conflict,” he says. “It’s a tension that’s ultimately going to be very hard to resolve.”
There are rarely easy answers when it comes to the massive task of addressing climate change. If you’re interested in getting a better understanding of this complicated web of trade-offs, take the time to read James’s story. You’ll get all the details about why this particular deposit is such a big deal, and hear more about where things are likely to go from here.
And the story doesn’t stop there. James also has another big project out this week, in which he worked to understand how this one mine could unlock billions of dollars in government subsidies. Dig into that here.
Some truck drivers are falling in love with EVs. Electric trucks are still limited in range, and they make up a small fraction of the trucks on the road, but drivers are starting to see the upside, even as critics say the move to electric is going too fast. (Washington Post)
Gas prices are down in the US, but charging up an EV is still way cheaper. Here’s how cheap gas has to get in every state to compete with EV charging. (Yale Climate Connections)
Old cell phones might provide a much-needed source of rare earth metals. These metals are crucial for motors, including the ones in electric vehicles and wind turbines, and recycling could meet as much as 40% of US demand by 2050. (New York Times)
→ Old personal devices can be a source for other metals, like lithium and cobalt, as I wrote in this story on battery recycling from last year. (MIT Technology Review)
Nobody knows when the next nuclear plant will come online in the US. The former front-runner was a NuScale modular reactor array, but the future of that project is uncertain now. (Canary Media)
Local bans can eliminate nearly 300 single-use plastic bags per person per year, according to a new report. Bottom line: the policies work. (Grist)
Europe will need 34,000 miles (54,000 kilometers) of additional transmission lines to handle the growth in offshore wind power. It could be Europe’s third-biggest energy source by 2050, if infrastructure can keep up. (Bloomberg)
This article is from The Spark, MIT Technology Review’s weekly climate newsletter. To receive it in your inbox every Wednesday, sign up here.
I’ve got nuclear power on the brain this week.
The workings of nuclear power plants have always fascinated me. They’re massive, technically complicated, and feel a little bit magic (splitting the atom—what a concept). But I’ve reached new levels of obsession recently, because I’ve spent the past week or so digging into advanced nuclear technology.
Advanced nuclear is a mushy category that basically includes anything different from the commercial reactors operating now, since those basically all follow the same general formula. And there’s a whole world of possibilities out there.
I was mostly focused on the version that’s being developed by Kairos Power for a story (which was published today, check it out if you haven’t!). But I went down some rabbit holes on other potential options for future nuclear plants too. So for the newsletter this week, let’s take a peek at the menu of options for advanced nuclear technology today.
The basics
Before we get into the advanced stuff, let’s recap the basics.
Nuclear power plants generate electricity via fission reactions, where atoms split apart, releasing energy as heat and radiation. Neutrons released during these splits collide with other atoms and split them, creating a chain reaction.
In nuclear power plants today, there are basically two absolutely essential pieces. First, the fuel, which is what feeds the reactions. (Pretty obvious why this one is important.) Second, it’s vital that the chain reactions happen in a controlled manner, or you can get into nuclear meltdown territory. So the other essential piece of a nuclear plant is the cooling system, which keeps the whole thing from getting too hot and causing problems. (There’s also the moderator and a million other pieces, but let’s stick with two so you’re not reading this newsletter all day.)
In the vast majority of reactors on the grid today, these two components follow the same general formula: the fuel is enriched uranium that’s packed into ceramic pellets, loaded into metal pipes, and arranged into the reactor’s core. And the cooling system pumps pressurized water around the reactor to keep the temperature controlled.
But for a whole host of reasons, companies are starting to work on making changes to this tried-and-true formula. There are roughly 70 companies in the US working on designs for advanced nuclear reactors, with six or seven far enough along to be working with regulators, says Jessica Lovering, cofounder and co-executive director at the Good Energy Collective, a policy research organization that advocates for the use of nuclear energy.
Many of these so-called advanced technologies were invented and even demonstrated over 50 years ago, before the industry converged on the standard water-cooled plant designs. But now there’s renewed interest in getting alternative nuclear reactors up and running. New designs could help improve safety, efficiency, and even cost.
Coolant
Alternative coolants can improve on safety over water-based designs, since they don’t always need to be kept at high pressures. Many can also reach higher temperatures, which can allow reactors to run more efficiently.
Molten salt is one leading contender for alternative coolants, used in designs from Kairos Power, Terrestrial Energy, and Moltex Energy. These designs can use less fuel and produce waste that’s easier to manage.
Other companies are looking to liquid metals, including sodium and lead. There are a few sodium-cooled reactors operating today, mainly in Russia, and the country is also at the forefront in developing lead-cooled reactors. Metal-cooled reactors share many of the potential safety benefits of molten-salt designs. Helium and other gases can also be used to reach higher temperatures than water-cooled systems. X-energy is designing a high-temperature gas-cooled reactor using helium.
Fuel
Most reactors that use an alternative coolant also use an alternative fuel.
TRISO, or tri-structural isotropic particle fuel, is one of the most popular options. TRISO particles contain uranium, enclosed in ceramic and carbon-based layers. This keeps the fuel contained, keeping all the products of fission reactions inside and allowing the fuel to resist corrosion and melting. Kairos and X-energy both plan to use TRISO fuel in their reactors.
Other reactors use HALEU: high-assay low-enriched uranium. Most nuclear fuel used in commercial reactors contains between 3% and 5% uranium-235. HALEU, on the other hand, contains between 5% and 20% uranium-235, allowing reactors to get more power in a smaller space.
Size
I know I said I’d keep this to two things, but let’s include a bonus category. In addition to changing up the specifics of things like fuel and coolant, many companies are working to build reactors of different (mostly smaller) sizes.
Today, most reactors coming on the grid are massive, in the range of 1,000 or more megawatts—enough to power hundreds of thousands of homes. Building those huge projects takes a long time, and each one requires a bespoke process. Small modular reactors (SMRs) could be easier to build, since the procedure is the same for each one, allowing them to be manufactured in something resembling a huge assembly line.
NuScale has been one of the leaders in this area—its reactor design uses commercial fuel and water coolant, but the whole thing is scaled down. Things haven’t been going so well for the company in recent months, though: its first project is pretty much dead in the water, and it laid off nearly 30% of its employees in early January. Other companies are still carrying the SMR torch, including many that are also going after alternative fuels and coolants.
Super-efficient solar cells are on our list of the 10 Breakthrough Technologies of 2024. (If you haven’t seen that list, you can find it here!) By sandwiching other materials with traditional silicon, tandem perovskite solar cells could help cut solar costs and generate more electricity.
Hertz was billing itself as a leader in renting out electric vehicles (remember that Tom Brady commercial?). Now the company is selling off a third of its EV fleet. (Tech Crunch)
A mountain of clothes accumulated in the desert in Chile. Then it caught fire. This is a fascinating deep dive into the problem of textile waste. (Grist)
New uranium mines will be the first to begin operations in the US in eight years. The mines could help bring more low-carbon nuclear power to the grid, but they’re also drawing sharp criticism. (Inside Climate News)
Researchers at Microsoft and a US national lab used AI to find a new candidate material for batteries. It could eventually be used in batteries to reduce the amount of lithium needed to build them.(The Verge)
→ I talked about this and other science news of the week on Science Friday. Give it a listen! (Science Friday)
Animals are always evolving. A few lucky ones might even be able to do it fast enough to keep up with climate change. (Hakai Magazine)
All that new renewable energy coming onto the grid is helping make a dent in US emissions. Buildout of clean energy cut greenhouse-gas emissions by nearly 2% in 2023. (Canary Media)
The Biden administration will fine oil and gas companies for excess methane emissions. Penalties for emitting this super-powerful greenhouse gas are part of the landmark climate bill passed in 2023. (New York Times)
Texas has had a host of upgrades to its electric grid in the years since a powerful storm devastated the state in 2021. Now experts are watching to see how the grid holds up against cold weather this week. (Washington Post)
For more than a month in total, 12 metric tons of molten salt coursed through pipes at Kairos Power in Albuquerque, New Mexico.
The company is developing a new type of nuclear reactor that will be cooled using this salt mixture, and its first large-scale test cooling system just completed 1,000 hours of operation in early January. This is the second major milestone for Kairos in recent weeks. In December, the US Nuclear Regulatory Commission granted a construction permit for the company’s first nuclear test reactor.
Nuclear power plants can provide a steady source of carbon-free energy, a crucial component in addressing climate change. But recent major nuclear installations have been plagued by delays and skyrocketing budgets. Kairos and other companies working on advanced reactor designs hope to revive hopes for nuclear power by presenting a new version of the technology that could cut costs and construction times.
Kairos’s technology and construction approach are “just fundamentally different” from current commercial reactors, says Edward Blandford, cofounder and chief technology officer of Kairos.
Today, nearly all commercial nuclear plants use the same type of enriched uranium as fuel to generate electricity through nuclear fission reactions, and temperature is controlled with a cooling system that uses water.
But a growing number of companies are working to tweak this formula in an effort to improve on cost and safety. In the case of Kairos, the company plans to use an alternative fuel called TRISO, which is made from tiny uranium-containing kernels that can be embedded in graphite casings. TRISO fuel is robust, able to resist high temperatures, radiation, and corrosion. In addition, the reactor’s cooling system uses molten salt instead of water.
Molten salt could be a huge help in making safer nuclear plants, Blandford says. The cooling system in water-cooled reactors needs to be kept at high pressure to ensure that the water doesn’t boil off, which would leave the reactor without coolant and in danger of overheating and running out of control. It’s technically possible to boil salt, but it could only happen at very high temperatures. So those high pressures become unnecessary.
Molten-salt nuclear reactors were developed in the 1950s but were largely shelved as the industry moved toward water-cooled designs. Now, with a growing need for low-carbon power, “there’s a lot of interest in these technologies again,” says Jessica Lovering, cofounder and executive director of the Good Energy Collective, a policy research organization that advocates for the use of nuclear energy. New reactor technology options could help avoid some of the fears around the safety of water-cooled reactors, and they can also generate electricity more efficiently.
Technology has changed a lot in the past seven decades, and molten-salt reactors never made it to large-scale commercial operation. So there’s still plenty of testing to be done before this kind of cooling system can be put to work in the highly controlled environment of a nuclear reactor. That’s where Kairos’s engineering test unit comes in. It’s the world’s largest system built to circulate Flibe, a fluoride-based salt coolant.
The system uses electric heaters to simulate the heat that would be generated by nuclear reactions in the finished reactor. Tests involve pumping a Flibe mixture through a cooling loop while engineers monitor the temperature throughout the system and the purity of the salt along the way. The company has also tested what it would be like to refuel the reactor, and how power coming out of the system can be monitored and adjusted.
Building an entire cooling system that won’t ever be used in a nuclear reactor is a considerable investment of time, money, and resources, but this approach of taking baby steps could help Kairos succeed in introducing a new nuclear technology—a historically difficult task, says Patrick White, research director at the Nuclear Innovation Alliance, a nonprofit think tank.
“One of the challenges with nuclear is that usually, the first step is to design the reactor on paper, and the next step is build the whole thing,” White says. Kairos is trying a different path, testing out components more along the way to help speed up development and avoid getting stuck in late-stage construction.
Kairos is making progress on construction, too. The company received approval in December from the NRC to build Hermes-1, its first nuclear test reactor. Hermes-1 will produce about 35 megawatts of thermal power (today’s commercial reactors typically produce around 1,000 megawatts of electricity). It’s planned for completion as soon as 2026.
Several other companies are also using molten salt or TRISO fuel in their advanced nuclear designs. X-energy, based in Maryland, is developing a gas-cooled reactor that uses TRISO fuel, and TerraPower and GE Hitachi Nuclear Energy are developing a sodium-cooled reactor that uses molten salt to store energy.
There’s still a long road ahead before Kairos’s design and other advanced reactors can make it onto the grid. The company plans to build at least two more large-scale test cooling systems before putting the pieces together for Hermes-1, Blandford says.
The company will also need to win an operating license for Hermes-1, the second of two major regulatory steps it’ll go through with the NRC. Next comes Hermes-2, which will include two reactors that are similar in scale and design to Hermes-1, plus a system to transform the heat generated into electricity. Finally, the company will move on to larger, commercial-scale reactors.
All of that will take some time, but Kairos and others feel the result will be worth it. “With our technology, it is unique,” Blandford says, “and it does open up unique opportunities to explore spaces that other technologies have not.”
MIT Technology Review’s What’s Next series looks across industries, trends, and technologies to give you a first look at the future. You can read the rest of our serieshere.
It’s a turbulent time for offshore wind power.
Large groups of turbines installed along coastlines can harness the powerful, consistent winds that blow offshore. Given that 40% of the global population lives within 60 miles of the ocean, offshore wind farms can be a major boon to efforts to clean up the electricity supply around the world.
But in recent months, projects around the world have been delayed or even canceled as costs have skyrocketed and supply chain disruptions have swelled. These setbacks could spell trouble for efforts to cut the greenhouse-gas emissions that cause climate change.
The coming year and beyond will likely be littered with more delayed and canceled projects, but the industry is also seeing new starts and continuing technological development. The question is whether current troubles are more like a speed bump or a sign that 2024 will see the industry run off the road. Here’s what’s next for offshore wind power.
Speed bumps and setbacks
Wind giant Ørsted cited rising interest rates, high inflation, and supply chain bottlenecks in late October when it canceled its highly anticipated Ocean Wind 1 and Ocean Wind 2 projects. The two projects would have supplied just over 2.2 gigawatts to the New Jersey grid—enough energy to power over a million homes. Ørsted is one of the world’s leading offshore wind developers, and the company was included in MIT Technology Review’s list of 15 Climate Tech Companies to Watch in 2023.
The shuttered projects are far from the only setback for offshore wind in the US today—over 12 gigawatts’ worth of contracts were either canceled or targeted for renegotiation in 2023, according to analysis by BloombergNEF, an energy research group.
Part of the problem lies in how projects are typically built and financed, says Chelsea Jean-Michel, a wind analyst at BloombergNEF. After securing a place to build a wind farm, a developer sets up contracts to sell the electricity that will be generated by the turbines. That price gets locked in years before the project is finished. For projects getting underway now, contracts were generally negotiated in 2019 or 2020.
A lot has changed in just the past five years. Prices for steel, one of the most important materials in turbine construction, increased by over 50% from January 2019 through the end of 2022 in North America and northern Europe, according to a 2023 report from the American Clean Power Association.
Inflation has also increased the price for other materials, and higher interest rates mean that borrowing money is more expensive too. So now, developers are arguing that the prices they agreed to previously aren’t reasonable anymore.
China stands out in an otherwise struggling landscape. The country is now the world’s largest offshore wind market, accounting for nearly half of installed capacity globally. Quick development and rising competition have actually led to falling prices for some projects there.
Growing pains
While many projects around the world have seen setbacks over the last year, the problems are most concentrated in newer markets, including the US. Problems have continued since the New Jersey cancellations—in the first weeks of 2024, developers of several New York projects asked to renegotiate their contracts, which could delay progress even if those developments end up going ahead.
While over 10% of electricity in the US comes from wind power, the vast majority is generated by land-based turbines. The offshore wind market in the US is at least a decade behind the more established ones in countries like the UK and Denmark, says Walt Musial, chief engineer of offshore wind energy at the US National Renewable Energy Laboratory.
One open question over the next year will be how quickly the industry can increase the capacity to build and install wind turbines in the US. “The supply chain in the US for offshore wind is basically in its infancy. It doesn’t really exist,” Jean-Michel says.
That’s been a problem for some projects, especially when it comes for the ships needed to install wind turbines. One of the reasons Ørsted gave for canceling its New Jersey project was a lack of these vessels.
The troubles have been complicated by a single century-old law, which mandates that only ships built and operated by the US can operate from US ports. Projects in the US have worked around this restriction by operating from European ports and using large US barges offshore, but that can slow construction times significantly, Musial says.
Tax credits are providing extra incentive to build out the offshore wind supply chain in the US. Existing credits for offshore wind projects are being extended and expanded by the Inflation Reduction Act, with as much as 40% available on the cost of building a new wind farm. However, to qualify for the full tax credit, projects will need to use domestically sourced materials. Strengthening the supply chain for those materials will be a long process, and the industry is still trying to adjust to existing conditions.
Still, there are some significant signs of progress for US offshore wind. The nation’s second large-scale offshore wind farm began producing electricity in early January. Several areas of seafloor are expected to go up for auction for new development in 2024, including sites in the central Atlantic and off the coast of Oregon. Sites off the coast of Maine are expected to be offered up the following year.
But even that forward momentum may not be enough for the nation to meet its offshore wind goals. While the Biden administration has set a target of 30 gigawatts of offshore wind capacity installed by the end of the decade, BloombergNEF’s projection is that the country will likely install around half that, with 16.4 gigawatts of capacity expected by 2030.
Technological transformation
While economic considerations will likely be a limiting factor in offshore wind this year, we’re also going to be on the lookout for technological developments in the industry.
Wind turbines still follow the same blueprint from decades ago, but they are being built bigger and bigger, and that trend is expected to continue. That’s because bigger turbines tend to be more efficient, capturing more energy at a lower cost.
A decade ago, the average offshore wind turbine produced an output of around 4 megawatts. In 2022, that number was just under 8 MW. Now, the major turbine manufacturers are making models in the 15 MW range. These monstrous structures are starting to rival the size of major landmarks, with recent installations nearing the height of the Eiffel Tower.
In 2023, the wind giant Vestas tested a 15 MW model, which earned the distinction of being the world’s most powerful wind turbine. The company received certification for the design at the end of the year, and it will be used in a Danish wind farm that’s expected to begin construction in 2024.
In addition, we’ll likely see more developments in the technology for floating offshore wind turbines. While most turbines deployed offshore are secured in the seabed floor, some areas, like the west coast of the US, have deep water offshore, making this impossible.
There’s a wide variety of platform designs for floating turbines, including versions resembling camera tripods, broom handles, and tires. It’s possible the industry will start to converge on one in the coming years, since standardization will help bring prices down, says BloombergNEF’s Jean-Michel. But whether that will be enough to continue the growth of this nascent industry will depend on how economic factors shake out. And it’s likely that floating projects will continue to make up less than 5% of offshore wind power installations, even a decade from now.
The winds of change are blowing for renewable energy around the world. Even with economic uncertainty ahead, offshore wind power will certainly be a technology to watch in 2024.
