A methane-measuring satellite will launch in March that aims to use Google’s AI to quantify, map, and reduce leaks. The mission is part of a collaboration with the nonprofit Environmental Defense Fund, and the result, they say, will be the most detailed portrait yet of methane emissions. It should help to identify the worst spots, and who is responsible.
With methane responsible for roughly a third of the warming caused by greenhouse gases, regulators in the United States and elsewhere are pushing for stronger rules to curb the leaks that spring from oil and gas plants.
MethaneSAT will measure the plumes of methane that billow invisibly from oil and gas operations around the globe, and Google and EDF will then map those leaks for use by researchers, regulators, and the public.
“We’re effectively putting on a really high-quality set of glasses, allowing us to look at the Earth and these emissions with a sharpness that we’ve never had before,” says Steve Hamburg, chief scientist and MethaneSAT project lead at EDF.
Methane experts say, however, that the path from finding a leak to getting a company to plug it will be arduous, and one that the collaboration cannot solve on its own.
Once in orbit, MethaneSAT’s software and spectrometers, which measure different wavelengths of light to detect methane, will pinpoint both concentrated locations for methane plumes as well as the broader areas where the gases diffuse and spread. It will also use Google’s image detection algorithms to create the first comprehensive, global map of the oil and gas industry’s infrastructure, like pump jacks and storage tanks, where leaks most commonly occur.
“Once those maps are lined up, we expect people will be able to have a far better understanding of the types of machinery that contribute most to methane leaks,” says Yael Maguire, who leads geo-sustainability efforts at Google.
This tool could solve a significant stumbling block for methane researchers, according to Rob Jackson, professor of Earth system science at Stanford. There are millions of oil and gas operations around the world, and information about where many of these facilities are located is tightly guarded, and where available, expensive to access. Some countries also block researchers from studying their infrastructure or using low-flying planes to measure emissions. With satellites, that may change.
“I think AI is the future of this field, where we should be creating databases of all these infrastructure types,” says Jackson, as measuring plumes from space sidesteps much of the oil and gas industry’s opaqueness on Earth. “One door that satellites are unlocking is the ability to peer everywhere. There will be nowhere to hide, eventually.”
The MethaneSAT collaboration comes at a time when governments around the world are taking stronger stances on reducing methane leaks. Fueled by the momentum of COP28 in December, the Biden administration announced a new set of rules in December that will require more monitoring and repair of leaks. In January, the administration also proposed a fine against companies for excess methane, though that rule has not been finalized and is being fought by the industry. The European Union also agreed to stricter standards in November.
Once the MethaneSAT collaboration identifies where leaks are coming from, EDF will use the global Methane Alert and Response System from the United Nations, which sends data about methane leaks to governments and policymakers for them to act on. Hamburg from EDF says the first data and images from the satellite are expected in early summer.
Though Jackson is optimistic that more accurate data from Google and EDF will put pressure on companies, he cautions that going from awareness to action is not straightforward. For one, even if a particular oil and gas operation is identified as a bad actor, it’s no small task to figure out who owns that infrastructure, and what tools are available to get them to act. On top of that, some regions and governments are likely to be less responsive to the data than others.
“I’m not confident that simply having this information will mean that companies and countries will switch off methane leaks like a light switch,” he says.
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)
MIT Technology Review Explains: Let our writers untangle the complex, messy world of technology to help you understand what’s coming next. You can read more from the series here.
For more than a century, the prevalent image of power plants has been characterized by towering smokestacks, endless coal trains, and loud spinning turbines. But the plants powering our future will look radically different—in fact, many may not have a physical form at all. Welcome to the era of virtual power plants (VPPs).
The shift from conventional energy sources like coal and gas to variable renewable alternatives such as solar and wind means the decades-old way we operate the energy system is changing.
Governments and private companies alike are now counting on VPPs’ potential to help keep costs down and stop the grid from becoming overburdened.
Here’s what you need to know about VPPs—and why they could be the key to helping us bring more clean power and energy storage online.
What are virtual power plants and how do they work?
A virtual power plant is a system of distributed energy resources—like rooftop solar panels, electric vehicle chargers, and smart water heaters—that work together to balance energy supply and demand on a large scale. They are usually run by local utility companies who oversee this balancing act.
A VPP is a way of “stitching together” a portfolio of resources, says Rudy Shankar, director of Lehigh University’s Energy Systems Engineering, that can help the grid respond to high energy demand while reducing the energy system’s carbon footprint.
The “virtual” nature of VPPs comes from its lack of a central physical facility, like a traditional coal or gas plant. By generating electricity and balancing the energy load, the aggregated batteries and solar panels provide many of the functions of conventional power plants.
They also have unique advantages.
Kevin Brehm, a manager at Rocky Mountain Institute who focuses on carbon-free electricity, says comparing VPPs to traditional plants is a “helpful analogy,” but VPPs “do certain things differently and therefore can provide services that traditional power plants can’t.”
One significant difference is VPPs’ ability to shape consumers’ energy use in real time. Unlike conventional power plants, VPPs can communicate with distributed energy resources and allow grid operators to control the demand from end users.
For example, smart thermostats linked to air conditioning units can adjust home temperatures and manage how much electricity the units consume. On hot summer days these thermostats can pre-cool homes before peak hours, when air conditioning usage surges. Staggering cooling times can help prevent abrupt demand hikes that might overwhelm the grid and cause outages. Similarly, electric vehicle chargers can adapt to the grid’s requirements by either supplying or utilizing electricity.
These distributed energy sources connect to the grid through communication technologies like Wi-Fi, Bluetooth, and cellular services. In aggregate, adding VPPs can increase overall system resilience. By coordinating hundreds of thousands of devices, VPPs have a meaningful impact on the grid—they shape demand, supply power, and keep the electricity flowing reliably.
How popular are VPPs now?
Until recently, VPPs were mostly used to control consumer energy use. But because solar and battery technology has evolved, utilities can now use them to supply electricity back to the grid when needed.
In the United States, the Department of Energy estimates VPP capacity at around 30 to 60 gigawatts. This represents about 4% to 8% of peak electricity demand nationwide, a minor fraction within the overall system. However, some states and utility companies are moving quickly to add more VPPs to their grids.
Green Mountain Power, Vermont’s largest utility company, made headlines last year when it expanded its subsidized home battery program. Customers have the option to lease a Tesla home battery at a discounted rate or purchase their own, receiving assistance of up to $10,500, if they agree to share stored energy with the utility as required. The Vermont Public Utility Commission, which approved the program, said it can also provide emergency power during outages.
In Massachusetts, three utility companies (National Grid, Eversource, and Cape Light Compact) have implemented a VPP program that pays customers in exchange for utility control of their home batteries.
Meanwhile, in Colorado efforts are underway to launch the state’s first VPP system. The Colorado Public Utilities Commission is urging Xcel Energy, its largest utility company, to develop a fully operational VPP pilot by this summer.
Why are VPPs important for the clean energy transition?
Grid operators must meet the annual or daily “peak load,” the moment of highest electricity demand. To do that, they often resort to using gas “peaker” plants, ones that remain dormant most of the year that they can switch during in times of high demand. VPPs will reduce the grids’ reliance on these plants.
The Department of Energy currently aims to expand national VPP capacity to 80 to 160 GW by 2030. That’s roughly equivalent to 80 to 160 fossil fuel plants that need not be built, says Brehm.
Many utilities say VPPs can lower energy bills for consumers in addition to reducing emissions. Research suggests that leveraging distributed sources during peak demand is up to 60% more cost effective than relying on gas plants.
Another significant, if less tangible, advantage of VPPs is that they encourage people to be more involved in the energy system. Usually, customers merely receive electricity. Within a VPP system, they both consume power and contribute it back to the grid. This dual role can improve their understanding of the grid and get them more invested in the transition to clean energy.
What’s next for VPPs?
The capacity of distributed energy sources is expanding rapidly, according to the Department of Energy, owing to the widespread adoption of electric vehicles, charging stations, and smart home devices. Connecting these to VPP systems enhances the grid’s ability to balance electricity demand and supply in real time. Better AI can also help VPPs become more adept at coordinating diverse assets, says Shankar.
Regulators are also coming on board. The National Association of Regulatory Utility Commissioners has started holding panels and workshops to educate its members about VPPs and how to implement them in their states. The California Energy Commission is set to fund research exploring the benefits of integrating VPPs into its grid system. This kind of interest from regulators is new but promising, says Brehm.
Still, hurdles remain. Enrolling in a VPP can be confusing for consumers because the process varies among states and companies. Simplifying it for people will help utility companies make the most of distributed energy resources such as EVs and heat pumps. Standardizing the deployment of VPPs can also speed up their growth nationally by making it easier to replicate successful projects across regions.
“It really comes down to policy,” says Brehm. “The technology is in place. We are continuing to learn about how to best implement these solutions and how to interface with consumers.”
For half a century, climate researchers have considered the possibility of injecting small particles into the stratosphere to counteract some aspects of climate change. The idea is that by reflecting a small fraction of sunlight back to space, these particles could partially offset the energy imbalance caused by accumulating carbon dioxide, thereby reducing warming as well as extreme storms and many other climate risks.
Debates about this idea, a form of solar geoengineering called stratospheric aerosol injection (SAI), commonly focus either on small-scale outdoor research that seeks to understand the physical processes involved or on deployment at a climate-altering scale. The gulf between these is gigantic: an experiment might use mere kilograms of aerosol material whereas deployment that could substantially slow or even reverse warming would involve millions of metric tons per year—a billionfold difference in scale. Appreciably cooling the planet via SAI would also require a purpose-built fleet of high-altitude aircraft, which could take one or two decades to assemble. This long lead time encourages policymakers to ignore the hard decisions about regulating deployment of SAI.
Such complacency is ill-advised. The barrier between research and deployment may be less distinct than is often assumed. Our analysis suggests a country or group of countries could conceivably start a subscale solar geoengineering deployment in as little as five years, one that would produce unmistakable changes in the composition of the stratosphere. A well-managed subscale deployment would benefit research by reducing important uncertainties about SAI, but it could not be justified as research alone—similar research could be carried out with a much smaller amount of aerosol particles. And it would have a non-negligible impact on the climate, providing as much cooling as sulfur pollution from international shipping did before the recent cleanup of shipping fuels. At the same time, the magnitude of the cooling would be small enough that its effects on climate, on a national or regional scale, would be very difficult to detect in the face of normal variability.
While the climate impact of such a subscale deployment would be small (and most likely beneficial), the political impact could be profound. It could trigger a backlash that would upend climate geopolicy and threaten international stability. It could be an on-ramp to large-scale deployment. And it could be exploited by fossil fuel interests seeking to slow the essential task of cutting emissions.
We oppose near-term deployment of solar geoengineering. In accord with the Climate Overshoot Commission, the most senior group of political leaders to examine the topic, we support a moratorium on deployment until the science is internationalized and critically assessed, and until some governance architecture is widely agreed upon. But if we are correct that such subscale deployments are plausible, then policymakers may need to confront solar geoengineering—its promise and disruptive potential, and its profound challenges to global governance—earlier than is now widely assumed.
Obstacles to early deployment
Humans already emit a huge quantity of aerosols into the troposphere (the turbulent lowest layer of the atmosphere) from sources such as shipping and heavy industry, but these aerosols fall to Earth or are removed by rainfall and other processes within about a week. Volcanic eruptions can have a more lasting effect. When eruptions are powerful enough to punch through the troposphere into the stratosphere, the aerosols deposited there can endure for roughly a year. SAI would, like the largest volcanic eruptions, inject aerosols or their precursors into the stratosphere. Given their vastly longer atmospheric endurance, aerosols placed there can have a cooling impact 100 times larger than they would if emitted at the surface.
Getting aerosols to the stratosphere is another matter. Passenger jets routinely reach the lower stratosphere on transpolar flights. But to get efficient global coverage, aerosols are best deployed at low latitudes, where the stratosphere’s natural overturning circulation will carry them poleward and thus distribute them worldwide. The average height of the top of the troposphere is about 17 kilometers in the tropics, and models suggest injection needs to be a few kilometers higher than that to be captured in the upwelling stratospheric circulation. The altitude for efficient deployment is commonly assumed to be at least 20 kilometers, nearly twice the height at which commercial jets or large military aircraft cruise.
Although small spy planes can cruise in this very thin air, they can carry only one to two metric tons of payload. That would be insufficient except for small-scale tests: offsetting a substantial fraction of global warming—say, 1 °C of cooling—would require platforms that could deliver several million metric tons per year of material to the stratosphere. Neither rockets nor balloons are suitable for hauling such a large mass to this high perch. Consequently, full-scale deployment would require a fleet of novel aircraft—a few hundred in order to achieve a 1 °C cooling target. Procuring just the first aircraft in the manner typical of large commercial or military aircraft development programs might take roughly a decade, and manufacturing the required fleet would take several years more.
But starting with full-scale deployment is both imprudent and unlikely. Even if we are turning the global thermostat down, the faster we change the climate, the higher the risk of unforeseen impacts. A country or group of countries that wishes to deploy solar engineering is likely to appreciate the political and technical benefits of a slower start, one with a gradual reversal of warming that facilitates optimization and “learning by doing”, while minimizing the likelihood and impact of unintended consequences.
We envision scenarios where, instead of attempting to inject aerosols in the most efficient way near the equator, a country or group of countries attempt to place a smaller amount of material in the lower stratosphere at higher latitudes. They could do this with existing aircraft, because the top of the troposphere slopes sharply downward as you move away from the equator. At 35° north and south, it is found at roughly 12 kilometers. Adding a 3 kilometer margin, an effective deployment altitude at 35° north and south would be 15 kilometers. This remains too high for airliners but is just below the 15.5 kilometer service ceiling of top-of-the-line business jets made by Gulfstream, Bombardier, and Dassault. The list of countries with territory at or near 35° north or south includes not only rich countries such as the US, Australia, Japan, South Korea, Spain, and China, but also poorer ones such as Morocco, Algeria, Iraq, Iran, Pakistan, India, Chile, and Argentina.
Subscale deployment
How might subscale deployment be accomplished? Most stratospheric scientific studies of aerosol injection assume the operative material is sulfur dioxide (SO2) gas, which is 50% sulfur by mass. Another plausible option is hydrogen sulfide (H2S), which cuts the mass requirement almost in half, though it is more hazardous to ground and flight crews than SO2 and thus might be eliminated from consideration. Carbon disulfide (CS2) gas cuts the mass requirement by 40% and is generally less hazardous than SO2. It is also possible to use elemental sulfur, which is the safest and easiest to handle, but this would require a method of combusting it on board before venting or the use of afterburners. No one has yet done the engineering studies required to determine which of these sulfur compounds would be the best choice.
Using assumptions confirmed with Gulfstream, we estimate that any of its G500/600 aircraft could loft about 10 kilotons of material per year to 15.5 kilometers. If highly mass-efficient CS2 were used, a fleet of no more than 15 aircraft could carry up 100 kilotons of sulfur a year. Aged but operable used G650s cost about $25 million. Adding in the cost of modification, maintenance, spare parts, salaries, fuel, materials, and insurance, we expect the average total cost of a decade-long subscale deployment would be about $500 million a year. Large-scale deployment would cost at least 10 times as much.
How much is 100 kilotons of sulfur per year? It is a mere 0.3% of current global annual emissions of sulfur pollution into the atmosphere. Its contribution to the health impact of particulate air pollution would be substantially less than a tenth of what it would be if the same amount were emitted at the surface. As for its impact on climate, it would be about 1% of the sulfur injected in the stratosphere by the 1992 eruption of Mount Pinatubo in the Philippines. That well-studied event supports the assertion that no high-consequence unknown effects would occur.
At the same time, 100 kilotons of sulfur per year is not insubstantial: it would be more than twice the natural background flux of sulfur from the troposphere into the stratosphere, absent unusual volcanic activity. The cooling effect would be enough to delay global rise in temperature for about a third of a year, an offset that would last as long as the subscale deployment was maintained. And because solar geoengineering is more effective at countering the rise in extreme precipitation than the rise in temperature, the deployment would delay the increasing intensity of tropical cyclones by more than half a year. These benefits are not negligible to those most at risk from climate impacts (though none of these benefits would necessarily be apparent due to the climate system’s natural variability).
We should mention that our 100 kilotons per year scenario is arbitrary. We define a subscale deployment to mean a deployment large enough to substantially increase the amount of aerosol in the stratosphere while being well below the level that is required to delay warming by a decade. With that definition, such a deployment could be several times larger or smaller than our sample scenario.
Of course no amount of solar geoengineering can eliminate the need to reduce the concentration of greenhouse gases in the atmosphere. At best, solar geoengineering is a supplement to emissions cuts. But even the subscale deployment scenario we consider here would be a significant supplement: over a decade, it would have approximately half the cooling effect as eliminating all emissions from the European Union.
The politics of subscale deployment
The subscale deployment we’ve outlined here could serve several plausible scientific and technological goals. It would demonstrate the storage, lofting, and dispersion technologies for larger-scale deployment. If combined with an observational program, it would assess monitoring capabilities as well. It would directly clarify how sulfate is carried around the stratosphere and how sulfate aerosols interact with the ozone layer. After a few years of such a subscale deployment, we would have a far better understanding of the scientific and technological barriers to large-scale deployment.
At the same time, subscale deployment would pose risks for the deployer. It could trigger political instability and invite retribution from other countries and international bodies that would not respond well to entities fiddling with the planet’s thermostat without global coordination and oversight. Opposition might stem from a deep-rooted aversion to environmental modification or from more pragmatic concerns that large-scale deployment would be detrimental to some regions.
Deployers might be motivated by a wide range of considerations. Most obviously, a state or coalition of states might conclude that solar geoengineering could significantly reduce their climate risk, and that such a subscale deployment would strike an effective balance between the goals of pushing the world toward large-scale deployment and minimizing the risk of political backlash.
The deployers could decide that a subscale project might make bigger interventions possible. While scientists may be comfortable drawing inferences about solar geoengineering from tiny experiments and models, politicians and the public may be very cautious about atmospheric interventions that can alter the climate system and affect all the creatures that dwell within it. A subscale deployment that encountered no major surprises could go a long way toward reducing extreme concerns about full-scale deployment.
The deployers could also claim some limited benefit from the subscale deployment itself. While the effects would be too small to be readily evident on the ground, the methods used to attribute extreme weather events to climate change could substantiate claims of small reductions in the severity of such events.
They might also argue that the deployment is simply restoring atmospheric protection that was recently lost. The reduction in sulfur emissions from ships is now saving lives by creating cleaner air, but it is also accelerating warming by thinning the reflective veil that such pollution created. The subscale scenario we sketched out would restore almost half of that sunshade protection, without the countervailing air pollution.
The deployers might also convince themselves that their action was consistent with international law because they could perform deployment entirely within their domestic airspace and because the effects, while global, would not produce “significant transboundary harm,” the relevant threshold under customary international law.
The governance implications of such a subscale deployment would depend on the political circumstances. If it were done by a major power without meaningful attempts at multilateral engagement, one would expect dramatic backlash. On the other hand, were deployment undertaken by a coalition that included highly climate-vulnerable states and that invited other states to join the coalition and develop a shared governance architecture, many states might be publicly critical but privately pleased that geoengineering reduced climate risks.
SAI is sometimes described as an imaginary sociotechnical scenario residing in a distant sci-fi future. But it is technically feasible to start subscale deployments of the kind we describe here in five years. A state or coalition of states that wished to meaningfully test both the science and politics of deployment may consider such subscale or demonstration deployments as climate risks become more salient.
We are not advocating for such action—in fact, we reiterate our support for a moratorium against deployment until the science is critically assessed and some governance architecture is widely agreed upon. Yet a sound understanding of the interlinked technology and politics of SAI is hampered by the perception that it must start with a significant effort that would substantially slow or even reverse warming. The example we’ve outlined here illustrates that the infrastructural barriers to deployment are more easily overcome than is commonly assumed. Policymakers must take this into account—and soon—as they consider how to develop solar geoengineering in the public interest and what guardrails should be put in place.
David W. Keith is a professor of geophysical sciences and founding faculty director of the Climate Systems Engineering initiative at the University of Chicago.
Wake Smith is a lecturer at the Yale School of Environment and a research fellow at the Harvard Kennedy School.
We thank Christian V. Rice of VPE Aerospace for performing the payload calculations herein. Please consult this PDF for more detail on our estimates.
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.”
This story first appeared in China Report, MIT Technology Review’s newsletter about technology in China. Sign up to receive it in your inbox every Tuesday.
For people who have been watching BYD for a long time, it won’t be surprising that the company has just ventured into a new field.
The Chinese electric-vehicle maker has been particularly good at expanding into different, related businesses. Not only can it make high-performing and safe batteries for cars, but it also does almost everything in house, from designing car chips to mining lithium and other materials. The fact that it has subsidiaries in every step of the EV supply chain enables the company to keep its costs down and sell cars at more competitive prices.
Now, to pull that off once again, BYD is starting a sea freight business.As I just wrote in a story published today, the company is assembling a fleet of at least eight car-carrier ships that will transport BYD cars from factories in China to sell in Europe, South America, and other markets.
BYD has had a meteoric rise to become the Chinese EV sector’s poster child in recent years, and 2023 was particularly good for the company. It sold 3 million electric cars and plug-in hybrid models last year, up from 1.8 million in 2022. BYD managed to beat Tesla to become the world’s top-selling EV company in the fourth quarter of 2023.
While the majority of those cars were sold in China, BYD’s export business has been expanding significantly. It exported over 240,000 cars in 2023, more than a fourfold increase from 55,000 cars in 2022; and the latter number was itself more than a fourfold increase from 13,000 in 2021.
But one thing has been getting in the way of these bonkers numbers: the lack of car-carrier ships internationally. A bust cycle in the international shipping industry since 2008, the technological challenge of making ships greener, and the fact that existing vessels are often already reserved by automakers in other countries—these factors have collectively resulted in ever-rising costs to hire a ship that can transport Chinese EVs abroad.
So Chinese companies like BYD and SAIC Motor are following in the footsteps of Japanese and Korean automakers: they’re building, chartering, and managing their own fleets of ships. This January, one boat operated by BYD and another operated by SAIC Motor set sail for the first time, between them carrying over 10,000 vehicles toward Europe.
These two massive ships are a symbol of just how competitive and successful China’s EV industry has become. And that’s likely to continue for some time, as other countries and traditional car brands are belatedly playing catch-up.
This is not to say China’s EV industry has nothing to fear. As I’ve laid out in previous articles, there are still factors that could slow down or even derail the export of Chinese EVs. Geopolitics is a major one. For example, in Europe, where many of the new car-carrier ships are heading, there’s already an anti-subsidy investigation against Chinese cars going on, which could end up making it much more costly to sell there.
Chinese companies going into sea shipping should note at least one cautionary tale from recent history. Before BYD, there was another Chinese car company called Chery, which started exporting its cars in the 2000s. In 2007, it acquired a shipbuilding company for the exact same reason: it wanted to increase the capacity to ship cars abroad. But the financial crisis doomed Chery’s burgeoning export business, and it didn’t build its first ship until a decade later.
Chery is still around today. It has made the pivot from gas to electric cars and is competing with BYD both domestically and in the export market. But its ill-fated shipbuilding attempt could be a lesson for other Chinese companies that are now making similar moves: even though the future looks bright, building and maintaining these massive ships is a risky, expensive business if their car sales don’t keep up.
Do you think it’s the right decision for companies like BYD and SAIC Motor to build their own car-carrier fleet? Tell me your thoughts at zeyi@technologyreview.com.
Catch up with China
1. The White House plans to cut off Chinese entities’ access to American cloud services to train AI models. (Reuters $)
2. Some legislators in the US want to reactivate the Justice Department’s China Initiative. (NBC News)
The controversial program was built to protect national security. But it strayed from its focus and ended in 2022. (MIT Technology Review)
3. Another proposed bill in Congress seeks to ban Chinese biotech firms from federal contracts. (South China Morning Post $)
4. After an almost five-year import freeze on Boeing’s 737 MAX, Chinese airline companies have restarted purchasing the controversial jet model. (Reuters $)
5. The Chinese movie market used to be a cash machine for Hollywood blockbusters. Not anymore. (New York Times $)
6. The Taiwanese government is funding efforts to build its own Chinese AI model that’s free of China’s political influence. (Bloomberg $)
Meanwhile, US spies want an AI model of their own to use against China without leaking national secrets. (Bloomberg $)
7. Elon Musk has praised Chinese electric vehicles, again. He says Chinese EV makers will “pretty much demolish” most competitors if there are no trade barriers. (CNBC)
Lost in translation
Another type of device is getting an AI transformation in China: student tablets. Commonly called “learning machines” (though they have no connection to machine learning), these are tablets specifically designed to tutor children in school subjects, supporting functions like electronic dictionaries and virtual classes. According to Chinese outlet IQ Tax Research Center, many of these sorts of products have embraced AI in the past year, including devices made by China’s leading AI companies like Baidu and iFlytek.
However, some parents have found these “AI-powered devices” prone to errors and inaccuracies. For example, one user mentioned that a math problem was solved with different answers each time the AI explained it. Others felt the educational content recommended by the AI was not always suitable for their children’s needs. At the end of the day, these “learning machines” are often still inadequate, despite how they are marketed.
One more thing
Do you stick to reserving dinner at restaurants with 4.5+ stars on Google? In China, some young people have had too many disappointing experiences chasing after viral restaurants with inflated reviews. Instead, they are starting a trend of choosing restaurants with review scores around 3.5. Their justification? “If a restaurant can survive for decades with such a low review, there must be something really special about it,” one comment on social media reads. It’s also about rebelling against the ubiquitous digital platforms that dictate where everybody goes, reports China’s Lifeweek magazine.
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 potential to use old, discarded products to make something new sounds a little bit like magic. I absolutely understand the draw, and in some cases, recycling is going to be a crucial tool for climate technology. I’ve written about recycling for basically any climate technology you can think of, including solar panels, wind turbines, and batteries. (I’ve also covered efforts to recycle plastic waste.)
For my most recent story, I was researching the materials used for the magnets that power EVs and wind turbines. (Read the result here!) And once again, I was struck by a stark reality: there are massive challenges ahead in material demand for climate technologies, and unfortunately, recycling alone won’t be enough to address them. Let’s take a look at why recycling isn’t always the answer, and what else might help.
Mind the gap
We’re building a whole lot more climate technologies than we used to, which means there aren’t enough old, discarded technologies sitting around, waiting to be mined for materials. Obviously the growth in clean-energy technologies is a great thing for climate action. But it presents a problem for recycling.
Take solar panels, for instance. They tend to last at least 25, maybe 30 years before they start to lose the ability to efficiently harness energy from the sun and transform it into electricity. So the panels available for recycling today are those that were installed over two decades ago (a relatively small fraction are ones that have been broken or need to be taken down early).
In 2000, there was a little over one gigawatt of solar power installed globally. (Yes, 2000 was nearly 25 years ago—sorry!) So today’s recycling companies are competing with each other for that relatively small amount of material. If they can hang in there, there will eventually be plenty of solar panels to go around. Over 300 gigawatts of solar power were added in 2023.
This gap is a common challenge in recycling for other technologies, too. In fact, one of the problems facing the growing number of battery recycling companies is a looming shortage of materials to recycle.
It’s important to start building infrastructure now, so we’re ready for the inevitable wave of solar panels and batteries that will eventually be ready for recycling. In the meantime, recyclers can get creative in where they’re sourcing materials. Battery recyclers today will rely on a lot of manufacturing scrap. Looking to other products can help as well—rare earth metals for EV motors and wind turbines could be partially sourced from old iPhones and laptops.
Closing the loop
Even if we weren’t seeing explosive growth for new technologies, there would be another problem: no recycling process is perfect.
The issues start at the stage of collecting old materials (think of the iPods and flip phones in your junk drawer, gathering dust), but even once material makes it to a recycling center, some will wind up in the waste because it breaks down in the process or just can’t be economically recovered.
Exactly how much material can be recovered depends on the material, the recycling process, and the economics at play. Some metals, like the silver in solar cells, might be able to reach 99% recovery or higher. Others can pose harder challenges, including the lithium in batteries—one recycler, Redwood Materials, told me last year its process can recover around 80% of the lithium from used batteries and manufacturing scrap. The rest will be lost.
I don’t mean to be a Debbie Downer. Even with imperfect recovery, recycling could help meet demand for materials in many energy technologies in the future. Recycling rare earth metals could cut mining for metals like neodymium in half, or more, by 2050.
But a robust supply of recycled materials for many climate technologies is still decades away. In the meantime, many companies are working to build options that use more widely available, cheaper alternatives. Check out my story on one startup, Niron Magnetics, which is working to build permanent magnets without rare earth metals, to see how new materials can help accelerate climate action and close the gap that recycling leaves.
The world’s largest EV maker is getting into the shipping business. BYD is amassing a fleet of ships to export its vehicles from China to the rest of the world. Read more about why the automaker is getting creative and what comes next in this fascinating story from my colleague Zeyi Yang.
The world’s largest cruise ship departed on its maiden voyage last week. The whole thing is a bit of a climate fiasco. Taking a cruise can be about twice as emissions intensive as flying and staying in a hotel. (Bloomberg)
A new refinery in Georgia will churn out millions of tons of jet fuel made from plants instead of petroleum. The new facility marks a milestone for alternative jet fuels. (Canary Media)
→ While alternatives are often called “sustainable aviation fuels” or SAFs, some varieties are anything but sustainable. Here’s what you need to know about all these newfangled jet fuels. (MIT Technology Review)
China nearly quadrupled its new energy storage capacity last year. It’s a massive jump for the growing industry, which is key to balancing the growing fraction of renewables on the grid. (Bloomberg)
Huge charging depots for electric trucks are coming to California. Big batteries in big vehicles require big chargers, and new funding from the US government could be crucial in building them. (Canary Media)
→ The three biggest truck makers are calling for better charging infrastructure for heavy-duty vehicles (New York Times)
EV charging can get a bit tricky for those of us who don’t live in single-family homes with a garage to charge in. Here are some solutions. (Washington Post)
The US is the world’s largest exporter of liquefied natural gas, but new exports are on pause. The Department of Energy says it’s trying to work out how to regulate them, and what the climate impact of cutting gas exports might be. (Grist)
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.”
