Nowadays, solar cells are typically found on sunny surfaces on land or aboard satellites in space. A new study suggests photovoltaics can also work below the ocean’s surface, generating useful amounts of electricity underwater even at depths of 10 meters.

“With submerged solar cells, submarines or autonomous underwater vehicles could achieve far greater range and mission endurance than they do today,” says Wen-Hua Zhang, dean of Yunnan University’s school of materials and energy in Kunming, China. Many other underwater electronic devices, such as sensors, cameras, lights, and communications systems “could also benefit from longer operating periods and much broader deployment coverage in the ocean, to support a subsea Internet of Things (IoT) in the future,” Zhang says.

More than 70 percent of Earth’s surface is covered by water, encompassing vast areas where solar cells could potentially be placed. However, water strongly absorbs sunlight with long wavelengths—those greater than 630 nanometers, corresponding roughly to red and beyond to infrared, microwave, and radio wavelengths. This limits conventional solar panels, which can absorb sunlight with wavelengths ranging from roughly 400 to 1,100 nm, or from blue to infrared.

To overcome this challenge, Zhang and his colleagues designed solar cells that could make full use of shorter wavelength sunlight. They fabricated perovskite solar cells that cover the spectrum of light that does filter through 5 to 10 meters of water, which consists mostly of blue-green 400- to 600-nm wavelengths.

The scientists found that while their photovoltaic cells attained a light-to-electricity conversion efficiency of 17.08 percent under the conditions usually found on land, they achieved 34.71 percent efficiency when given the spectrum of light one would expect submerged 10 meters underwater. Most standard land-based solar panels achieve an average efficiency between 20 and 25 percent.

The researchers also integrated their cells into underwater mini-robots equipped with rechargeable lithium-ion batteries, deploying them near Weizhou Island in the South China Sea. They encapsulated these cells in glass, synthetic rubber, and epoxy resin to protect them from seawater. The robots could automatically maintain a fixed depth to help the scientists see how well the cells performed at different distances underwater.

At a depth of 2 meters, 115 square centimeters of these encapsulated cells could generate a modest 1,416 milliwatt-hours over two hours—roughly half the capacity of a rechargeable AA battery; at a depth of 10 meters, these cells could still generate 324 mWh of energy over two hours. The performance of these cells at 10 meters exceeded Zhang’s expectations by about three- to six-fold, he says.

How long can submerged solar cells survive?

Compared to conventional silicon solar panels, perovskite solar cells are cheaper, easier to make, and more efficient, making them a strong choice for underwater applications. But they also often rapidly degrade in performance under intense light and high temperatures. In contrast, the low temperatures and weak light typically found underwater could allow for more durable operation.

The researchers tested this possibility with lab experiments where the new cells were subjected to the kind of light seen underwater at 10 meters. Given the minimal level of degradation the researchers saw at standard operating temperatures of 25 °C—the annual average water temperature near Weizhou Island—they estimated the cells were capable of continuously operating for roughly 5.5 years before degrading to 80 percent of their original efficiency. (In contrast, standard perovskite cells begin to deteriorate after just one year of use on land, although researchers worldwide are investigating ways to significantly extend perovskite cell lifetime.)

“The submerged solar cells show application potential as a real solution for underwater energy,” Zhang says. “Massive deployment of submerged solar cells could extend photovoltaics from land and space into the ocean, addressing the urgent demand for durable offshore energy supply. Ultimately, this could support the growth of the blue economy and may open a new chapter for marine energy.”

Submerged photovoltaics face a number of potential obstacles, Zhang notes. For instance, ocean currents could make it difficult to deploy these devices. Seawater corrosion and encrusting from barnacles and algae could also reduce their long-term performance.

In the future, Zhang would like to see just how deep underwater solar cells can operate. He would also like to integrate them with energy storage devices to create all-in-one units to accelerate practical applications. In addition, standardized testing protocols are needed to analyze submerged photovoltaic performance; these could enable comparisons across different labs to advance the development of these devices, he notes.

The scientists detailed their findings on 11 September in the journal Joule.

Construction underway on a remote island nearly 400 kilometers west of India’s mainland could demonstrate, for the first time, the commercial viability of a vast, untapped renewable resource: the ocean’s thermal layers. Here, on the Lakshadweep Archipelago, surface waters are more than 20 °C warmer than the depths below, and with the right equipment that temperature differential can be exploited to generate electricity.

Known as ocean thermal energy conversion, or OTEC, such power plants can deliver renewable power around the clock. The scale of the opportunity is immense thanks to extensive regions of the world’s oceans with sufficiently large temperature differences between surface and deep waters. In just the waters around the United States, for example, OTEC could satisfy the country’s entire power demand, according to a 2021 report by the U.S. Department of Energy’s National Laboratory of the Rockies.

India’s project will tap 1,000-meter-deep seawater to generate 65 kilowatts of electricity and produce 100,000 liters of potable water per day. Developed by India’s National Institute of Ocean Technology (NIOT), it’s a small project, but a big step toward a commercial breakthrough for OTEC. “What we are doing is scalable in numbers for islands and remote communities. This can be a market strategy,” says Purnima Jalihal, who led the project before retiring last year as head of the energy and freshwater division at NIOT.

The project is part of a fresh wave of enthusiasm behind OTEC. Kilowatt-scale projects have been completed recently in China and the Canary Islands, and more are planned for Hawaii, Taiwan, and Japan. While previous efforts to commercialize OTEC have come up short amidst engineering snafus, efficiency shortfalls, and funding constraints, today’s efforts benefit from advances in key devices and engineering capacity.

Still, far bigger projects are needed before investment in OTEC will take off, says Robert Varley, who led defense contractor Lockheed Martin’s OTEC program from 2006 to 2017. Most OTEC proponents agree, saying the field needs a demonstration of at least a few megawatts, which is an order of magnitude larger than the longest-running projects to date. “Once that happens, I think the world changes for OTEC,” Varley says.

How Ocean Thermal Energy Conversion Works

Earth’s oceans absorb much of the sun’s daily irradiation and excess heat trapped in Earth’s atmosphere. But most of this thermal energy stays within 100 meters of the ocean’s surface. The deep seas remain frigid, dominated by meltwater from Earth’s frozen poles.

Since the 1970s, a few dozen projects have sought to harness that heterogeneity. It’s challenging because the temperature gap the technology aims to exploit is relatively narrow. Even in tropical zones, most OTEC plants will have to make do with a 25 °C difference between the surface waters and the cold waters 1,000 meters below. (By contrast, conventional thermal generators function off of a 400 °C temperature spread.)

To harness the small temperature differential, most groups generate power by heating and cooling a working fluid that naturally boils at a low temperature, such as ammonia. Surface water is pumped into the plant, and its heat is transferred to the ammonia, causing it to evaporate. That vapor then drives a turbine to generate power. Finally, to repeat the cycle, the ammonia’s heat is transferred to cold water piped in from the deep, causing the ammonia to condense.

An offshore, closed-cycle OTEC system requires a heat source and a heat sink. The warm water passes through a heat exchanger (evaporator) that is in contact with ammonia or other working fluid. The working fluid evaporates into a vapor, which expands and drives a turbine. Then the vaporized working fluid enters another heat exchanger (condenser) that is in contact with cold water. This condenses the working fluid back into a liquid, which is then pumped back into the evaporator to complete the cycle. Both the cooled warm water and the warmed cold water are discharged into the ocean, passing through the heat exchangers.NOAA

Squeezing power from a meager temperature delta requires a lot of surface and deep water. A 6.4-MW OTEC plant proposed on Taiwan’s east coast by Taipei-based industrial conglomerate TCC Group Holdings would suck up to 9,500 liters of cold seawater per second from 600 meters below the surface. A 10-MW design Lockheed envisioned for installation in China in 2013 would have processed 40,000 liters of seawater per second, but it was never built.

Pumping on that scale favors placing plants on offshore platforms, which shortens the pipes required since they can extend straight down to reach lower depths. But offshore platforms increase costs, and operating in punishing open ocean conditions increases risk. When filled with water, an offshore OTEC platform’s dangling cold water pipe will weigh tens of thousands of metric tons, and any movement from rough seas will place immense stress on its connection to the platform.

To address one of the risks of being located offshore, London-based startup Global OTEC deployed in the Canary Islands the world’s first platform purpose-built for OTEC and hurricane readiness. The platform, floated in April and paid for by government grants, is a 1:7-scale, non-working model of a 2.5-MW demonstration plant.

Sea Solar Power in Jacobus, Pa., is developing a 25-MW OTEC plant. Sea Solar Power

An operating plant will be required to convince investors of the technology’s reliability. Jacobus, Pennsylvania-based Sea Solar Power, established in 1972 to pursue OTEC, is designing a 25-MW plant that it vows would satisfy investors by paying for itself if its electricity serves an island grid reliant on expensive diesel power. Sea Solar president James H. Anderson Jr. says his firm survived to date thanks to revenues from its manufacturing spinoffs, but he says the company is now seeking a US $5–10 million investment to finish the plant’s “pre-feasibility” engineering design. Building the plant would cost at least US $120 million more.

Islands Seek Renewable Energy from OTEC

India’s project in the Lakshadweep Archipelago aims to show that small OTEC plants can be reliable and cost-effective. The key is using simpler technology and producing more than power.

Rather than adding a cycle that evaporates and condenses a separate working fluid like ammonia, NIOT’s plant will evaporate seawater at low temperature. To achieve that, pumps will create a vacuum, which lowers the atmospheric pressure around a liquid, decreasing its boiling point. This enables the Archipelago’s approximately 29 °C surface water to evaporate more easily. That resulting ‘steam’ will then spin a low-pressure turbine before it is condensed using 7 °C water. Then, instead of returning all of its condensed water back to the ocean, NIOT’s plant will divert some of it to generate fresh water.

NIOT’s technology emerged after a failed bid to go big in 2002. The Chennai-based government lab sought to demonstrate the world’s first 1-MW OTEC process, 40 kilometers off India’s southeast coast. But during construction, workers dropped the project’s 1,000-meter-long cold water pipe, losing it to the depths of the ocean. It was a confidence-shaking accident that Global OTEC founder and CEO Dan Grech calls “the biggest mistake in OTEC history.”

After the incident, NIOT pivoted, adapting its technology to address the needs of Lakshadweep. Like many island communities worldwide, the people of this archipelago rely on pricey imported diesel to generate electricity, and they face mounting water stress due to overdrawn aquifers and rising seas. NIOT initially addressed the drinking water crisis with desalination plants.

These plants use vacuums to evaporate hundreds of liters of warm surface water per second and condense the vapor to freshwater using deep sea cold water. The first plant started up in 2005 in Kavaratti, Lakshadweep’s capital city, ending islanders’ consumption of salty water. Doing so slashed rates of hypertension and gastrointestinal illness. “That was a moment of triumph for NIOT because nobody else had thought of doing this,” says Jalihal, the project’s former leader at NIOT.

But Lakshadweep’s desalination plants still rely on the islands’ expensive diesel-powered grids for electricity. So they’ve turned to OTEC for power. NIOT’s OTEC-enhanced desalination project, now under construction on Kavaratti, will use its low-pressure turbine to generate enough power to operate desalination grid-free.

It’s not technology that will scale up, because the low-pressure turbines require much larger blades. But it could provide a small return on the 500 million rupee (US $5.3-million) installation, saving about 20–30 million rupees (US $210,000–$315,000) per year in annual diesel costs, according to one report.

And the design could be replicated at many of the world’s developing islands. NIOT has discussed sharing the technology with the Maldives and Mauritius. That would be another small evolutionary step for OTEC. But, as Lakshadweep’s experience shows, the local economic and health impact could be impressive.

Dozens of materials today outperform the world’s most common superconductor—niobium-titanium (NbTi). But no competing material can beat niobium-titanium’s capacity to be manufactured at scale and rolled out into usable wire.

Two startups say that AI and robots could help close that gap.

The San Francisco–based Periodic Labs and Cambridge, Mass.–based Quantum Formatics are searching for materials that work at temperatures higher than 10 kelvins (−264 °C), the transition temperature of NbTi, below which it loses all electrical resistance.

Quantum Formatics has several candidate materials for a new generation of superconductors. Company founder Jason Gibson says the company is about a year away from making a prototype wire that can be used in qualification tests to demonstrate superconductor performance.

“We’re trying to get operating temperatures of 10 to 20 K,” says Gibson. “We focus on moderate-temperature superconductors with excellent mechanical properties that lead to good manufacturability. This approach means we can adopt a standard wire-manufacturing process.”

Periodic Labs cofounder Ekin Doğuş Çubuk says his company, established in September 2025, has developed a technique based on X-ray diffraction. XRD, as it’s called, is a method of mapping the atomic structure of a material by bouncing X-ray beams off it.

Periodic Labs’ XRD procedures help the company to study candidate superconductors and automate its superconductor discovery process, says Çubuk.

Periodic Labs cofounder Ekin Doğuş Çubuk says the company has pioneered an AI-powered robot-arm system that can test 1,000 candidate superconductors per day. Richard Morgenstein/Periodic Labs

How Can Robots and AI Help Discover New Superconductors?

Because no human can sift through thousands of XRD patterns a day, the company is developing machine learning algorithms to use XRD and measure the magnetic properties of materials to speed detection of new superconductors.

“We have built robots that can physically use X-ray diffraction machines,” Çubuk says. “Robotic arms load samples, and then the measurement gets done, sent to an LLM. The robot takes a sample out, puts in a new sample, and then the LLM analyzes all the X-ray diffraction patterns to determine if the experiment worked—and if it didn’t work, what to do next.”

Çubuk adds that developing and creating new materials from scratch hasn’t been easy to automate.

“Our biggest bottleneck is being able to make these different materials for the first time,” says Çubuk, who was previously a research scientist at Google DeepMind.

Meanwhile, according to competing teams also using AI to make progress in the field, new superconductor discoveries are hotly anticipated today.

“Magnets could come very fast if we are very lucky and find something very easily,” says Päivi Törmä, the leading physicist of the Super C consortium of European and American universities aiming to make the first room-temperature superconductors by 2033.

New superconductors can boost energy efficiency in data centers and hospital magnetic-resonance-imaging equipment by an order of magnitude, she says.

“I made estimates based on the best data that I could get,” Törmä says. “For sure, it’s 10 times more, but it can easily be 100 or 1,000 times more energy efficient.”

Periodic Labs has been conducting 100 experiments a day, according to Çubuk. The company is also opening a second lab to accelerate testing.

“That’s going to ramp up to 1,000 attempts a day,” Çubuk says. “I think that will be by far the highest-throughput superconductivity research ever done. We want to see by doing 1,000 good attempts a day if we can discover really exciting superconductors.”

Quantum Formatics is using what it calls the System, its proprietary AI-accelerated superconductor-discovery algorithm. The company has published three articles in Nature Computational Materials describing how its automated discovery system works.

Quantum Formatics founder Jason Gibson says AI can assist in the discovery of hardened superconductors for powering strong magnets for nuclear fusion, since existing magnets turn brittle in a reactor’s high-radiation environment.Minks Media

“We realized there was a critical gap between where the research of superconductor discovery was and what actually gets implemented in a device,” says Gibson, the company’s founder. “Dozens of superconductors have been discovered that vastly exceed the superconducting properties of NbTi. However, nearly all have failed to reach large market penetration due to the challenge of manufacturing.”

Gibson points to the importance of ductility—a material’s capacity to be reshaped and, in the case of Quantum Formatics, made into wires flexible enough to be wound into superconducting magnets.

What Technologies Could Benefit From New Superconductor Discoveries?

For comparison, rare-earth barium copper oxides (ReBCO) are a popular superconductor, with transition temperatures in excess of liquid nitrogen’s 77 K boiling point. (A superconductor that’s coolable with inexpensive liquid nitrogen, as opposed to the more costly liquid hydrogen or liquid helium, is an attractive prospect for superconductor researchers.)

The Cambridge, Mass.–based Commonwealth Fusion Systems uses ReBCO tape in two experimental-fusion reactors the company is building in Massachusetts and Virginia.

However, superconducting magnetic tape in a fusion reactor also is exposed to a substantial amount of radiation, which can degrade the tape.

“Radiation is a very challenging thing,” says Dan Brunner, former chief technology officer at Commonwealth. “That’s one of the challenges with the ReBCO class of superconductors. It’s a very fine crystal structure. Because it’s crystalline, it’s brittle, and that makes it hard to engineer into systems.”

Quantum Formatics is working with companies like Commonwealth Fusion and Realta Fusion, based in Madison, Wis. Superconducting magnets account for up to half of the $3 billion cost of a fusion reactor, Gibson says.

“The one challenge we’re really trying to address in terms of ReBCO is its radiation tolerance,” Gibson adds. “It does not perform well under radiation, but it is essentially the only option that produces high enough magnetic fields to allow you to have a compact fusion plant.”

Çubuk says that Periodic Labs is also investigating commercial applications like power transmission for data centers.

“Data centers are getting more power hungry, and they have to use these extremely thick copper wires to bring power into the racks,” Çubuk said. “If somebody could make superconductor tapes work with liquid nitrogen, those tapes could be much thinner and much smaller and could carry much more power without the resistance loss.”

For the foreseeable future, Çubuk says, old-fashioned trial and error will remain an important part of the discovery process.

“From that perspective,” he says, “it’s very interesting to think about how superconductors get discovered—and how they might get discovered in the future.”

In a display case on the lower level of the Faraday Museum at the Royal Institution in London, there’s an unassuming stack of gray metal discs and blotting paper. It’s not at all obvious that this humble object is the starting point of today’s multibillion-dollar global battery industry. The object’s invention in 1799 grew out of a disagreement that Alessandro Volta—the Italian physicist for whom the unit of measurement for electrical potential is named—had with his friend Luigi Galvani over a dead frog.

The Debate Over Animal Electricity

Galvani was a well-respected Italian physician. In the 1770s, he began investigating the use of electricity to stimulate the muscles of dissected frogs. Armed with an electrostatic generator and an early type of capacitor called a Leyden jar, he was able to create a charge, store it, and then zap his animal specimens at will. He was intrigued when the frog legs twitched as if they were still alive. He spent the last three decades of the 18th century studying the phenomenon, and in 1791, he published De viribus electricitatis in motu musculari commentarius (Commentary on the Effect of Electricity on Muscular Motion).

Luigi Galvani spent decades investigating what he believed to be a natural electric force emanating from animals. Universal History Archive/Getty Images

Galvani saw the frog as embodying an “animal electricity,” an innate vital force that activated nerves and muscles, similar to what had been observed in (living) electric eels and torpedo rays. For Galvani, the frog was an electrical machine analogous to a Leyden jar. The brain was the source of the electrical charge; the nerves conducted the electrical fluid; and the muscles stored opposite charges. The illustrations in his 1791 book are fabulous—frog legs spread all over his laboratory table!

Galvani was wrong in thinking that his frogs were electrical machines, but he was right that the muscle contractions were caused by electric signals.SSPL/Getty Images

At first, Volta, chair of physics at the University of Pavia, concurred with his friend. But after beginning his own experiments, he concluded that Galvani was wrong and that the frog generated no electricity at all. He thought of the frog as nothing more than an electroscope, an instrument to indicate the presence of an electrical charge. Volta posited that the source of the charge Galvani observed came from two different metals in contact with the frog. He termed this “metallic electricity.”

Alessandro Volta came to disagree with Galvani’s theory of animal electricity.Apic/Getty Images

To prove his point, Volta created an “artificial electric organ.” He stacked alternating discs of copper and zinc, separated by cardboard, blotting paper, or cloth soaked in brine or acid. When the top and bottom plates were connected, an electric current flowed through the stack. As opposed to a Leyden jar, which is essentially a capacitor that can store an electric charge and release it in a brief powerful discharge, his stack of discs generated its own electricity through a chemical reaction and delivered a sustained low-current output.

Volta didn’t publicly demonstrate or announce his artificial electric organ until after Galvani died in 1798. But when he finally did, in 1799, it immediately began upending science. Just six weeks after Volta wrote to the Royal Society about his invention, the English scientists William Nicholson and Anthony Carlisle used a voltaic pile to run a current through water to separate it into hydrogen and oxygen. They had discovered chemical electrolysis. Humphry Davy later used a large voltaic pile to isolate a number of elements, including potassium, sodium, calcium, strontium, and barium. Early piles petered out after a few hours. Users who stacked up more metal discs to make more powerful piles found the weight of the discs squeezed out the moisture in the paper or cloth.

Invented in 1799, Volta’s “artificial electric organ” (later known as the voltaic pile) was the first battery. Volta presented this one to Michael Faraday in 1814.Royal Institution of Great Britain/Science Source

One of the most enthusiastic users of the voltaic pile was Galvani’s nephew, Giovanni Aldini, who spent much of his career defending his uncle’s ideas. Aldini created spectacles across Europe in which he used voltaic piles to shock the carcasses of livestock and, occasionally, the bodies of recently executed convicts. Vivid descriptions in the popular press, as well as Aldini’s own writings, raised the question of whether electricity could bring the dead back to life. Mary Shelley provided her answer in her 1818 novel, Frankenstein; or, The Modern Prometheus. In an introduction to an 1831 edition, Shelley cites galvanism as one of her inspirations for the monster’s reanimation process.

Beyond Winners and Losers in Scientific Debates

Scientists and historians share a common trait: They like stories with clear winners and losers. The narrative of competition helps drive a narrative of progress that makes it look like humanity is always moving forward. In the case of Galvani and Volta, Volta is usually depicted as the clear winner in the debate over animal versus metallic electricity. The Encyclopedia Britannica goes as far as to write that “with his announcement of the first electric battery in 1800, victory was assured for Volta.”

But both science and history are more nuanced than that. In fact, Galvani and Volta were both partially right and partially wrong. There was no universal force of animal electricity, but Galvani was correct that electrical signals caused muscle contractions, which he discussed in his anonymous 1794 publication Dell’uso e dell’attività dell’arco conduttore nella contrazione dei muscoli (On the Use and Activity of the Conductive Arch in the Contraction of Muscles). Volta was right to push back on Galvani’s animal electricity theory, but he was wrong that electrophysiological effects require two different types of metal, or any metal at all; the circuit in the voltaic pile was closed by the wet paper or cloth.

It seems a little presumptuous for the Encyclopedia Britannica to declare Volta the winner and Galvani the loser. Volta definitely thought his friend was wrong, but he waited until after Galvani’s death to make his views public. It’s closer to the truth to say they were both genuinely curious to understand the nature of electricity. In the process, they unknowingly helped develop different fields of inquiry: electrophysiology for Galvani and electrochemistry and battery science for Volta.

RELATED: Who Really Invented the Rechargeable Lithium-Ion Battery?

Such an outcome is actually quite common in scientific disagreements. For example, Isaac Newton’s dispute with Christiaan Huygens over the nature of light—did light consist of particles, or corpuscles, as Newton termed them, or waves, as Huygens contested—breaks down today into quantum optics and classical optics. Similarly, Louis Pasteur’s and Justus von Liebig’s debate over fermentation (microorganisms versus chemical decomposition) led to two complementary fields: microbiology and biochemistry.

Maybe instead of looking for winners and losers, we would be better off expanding our horizons and considering the multiple paths of inquiry and discovery. Writing in 1816, toward the end of his career, Volta graciously acknowledged Galvani’s pioneering work, saying “it contains one of the most beautiful and surprising discoveries and the germ of many others.” What new revelations are waiting to develop out of today’s scientific debates?

Part of a continuing series looking at historical artifacts that embrace the boundless potential of technology.

An abridged version of this article appears in the September 2026 print issue as “The First Battery.”

References

On 20 March 1800, a year and three months after the death of Luigi Galvani, Alessandro Volta wrote a letter (in French) to Joseph Banks, president of the Royal Society, describing his invention of an artificial electric organ. It was read before the Society on 26 June and published in Philosophical Transactions on the last day of that year as “On the electricity excited by the mere contact of conducting substances of different kinds.”

The Smithsonian Institution Libraries used their rare books in the online exhibit The Body Electric, which has more information on both Galvani and Aldini.

The website of the Whipple Museum in Cambridge, England, has a number of pages devoted to frogs, including a very informative description of the role frogs played in Galvani’s experiments and how those led to Volta’s work.

In a significant policy twist, on 14 August, Spain’s government decreed a three-year extension for a pair of nuclear power plants with combined capacity of about 2 gigawatts. In 2019, the plants at Almaraz, 200 kilometers southwest of Madrid, had been scheduled to shut down in 2027. A phaseout of nuclear power was a major plank of Spain’s coalition government, so the delay has set off a conflict with one of the coalition parties.

The decree blames the extension on “the crisis in the Middle East,” but the decision comes as multiple factors have slowed or reversed several European countries’ policies aimed at phasing out nuclear power. “The Ukraine war, the Iberian blackout, and rising natural gas prices have changed things a lot,” says energy economist Diego Rodríguez Rodríguez of the Complutense University in Madrid, who is also a former board member of the Spanish National Markets and Competition Commission.

“The government could see that the system was going to need a lot of battery storage to catch up to its booming solar photovoltaic capacity, and they have used the Strait of Hormuz thing as cover.”

Europe’s Nuclear Power Policy Shift

Even before Russia’s 2022 invasion of Ukraine, some European Union countries were reconsidering plans to shut down nuclear power plants or even considering how to add nuclear-generating capacity. The invasion raised household electricity prices as EU nations scrambled for alternatives to Russian natural gas. In 2023, Sweden added nuclear to its energy-mix target alongside renewables. In 2025, Belgium voted to repeal its 2003 nuclear phaseout. In 2026, France canceled plans to shut down more than a dozen reactors, called for new reactors, and raised its targets for nuclear’s role in the national energy mix. Poland is planning to build its first nuclear power plants in 2028.

Spain’s nuclear capacity has hovered at around 20 percent of the national electricity mix since a 2019 phaseout agreement. Nuclear power has contributed a relatively price-stable alternative to natural gas and has also provided reliable base load to a grid that incorporates a growing share of time-variable renewable energy sources.

Spain’s long-stated goal has been to use renewables such as wind and solar to replace its most carbon-intensive energy sources; to get there, the government has provided a mixture of incentives. Since 2022, Spain has added more than 20 GW of photovoltaic capacity. As of 2024, wind was contributing about 23 percent, and solar 17 percent of the country’s electricity mix.

All of that added renewable energy has created significant technological challenges. Grid operators must balance reactive power (essentially stored power that is shifted back and forth through the grid) with active power (the power drawn by users) to maintain a steady electricity supply. Outdated grid-management rules exempted solar power plants from the same reactive power control contributions required of legacy plants, potentially exposing the grid to instability.

On 28 April 2025, a series of power oscillations, voltage gaps, and reactive power control failures set off a cascade of disconnections across the Iberian Peninsula. The resulting blackout affected more than 60 million people for about 12 hours. While Spain’s political parties debated how much of the blame belonged to the grid operator or renewables or other factors, the coalition government, with its tiny majority, could not afford another similar hit to the grid. Nuclear power offered a way to increase stability while the country shored up the resilience of its electric grid.

The Almaraz power plant is in Navalmoral de la Mata, in western Spain. Carlos Criado/Europa Press/Getty Images

Spain Buys Time for a Grid Makeover

For now, Spain’s grid lacks sufficient storage and transmission capacity to absorb new PV as quickly as it is being added. Instead, many installers are going behind the meter, building almost one-fifth of the country’s solar PV at industrial sites that can use it themselves, such as at data centers.

But upgrades are coming. In July 2025, Spain’s Ministry for Ecological Transition and Demographic Challenge (MITECO) announced a EUR 750 million (US $874 million) investment in 65 new resilience measures, including synchronous condensers, flexible AC transmission systems, substation improvements, and switching relays. The country is also adding three more interconnections to France to meet European recommendations.

Investment in energy storage is also booming: At the time of the blackout, Spain had only 28 megawatts in battery storage capacity, but that number almost sextupled to 193 MW by April 2026. Spain is funding 2.2 GW in near-term large-scale energy storage projects and has a national target of 22.5 GW (including pumped hydrogen and other nonbattery systems) by the time of the rescheduled shutdown of its Almaraz nuclear plants in 2030.

Slowing down the nuclear shutdowns buys Spain’s embattled electric grid affordable base power with stable voltage and avoids using more price-volatile, expensive natural gas. The Almaraz extension raises the question of which other nuclear plant shutdowns the government might delay, given that several were scheduled to end operations around 2030 as well. “The national consortium for dismantling the plants wouldn’t even be able to dismantle them all at once anyway,” Rodríguez says.

Critics of Spain’s energy-policy pivot have argued that extending nuclear power will unfairly cut into the profits of investors in solar, who will have to curtail their power generation more at peak times. Natalia Fabra, an energy economist at CEMFI, in Madrid, wrote this spring in the Journal of the Spanish Economic Association that “keeping nuclear plants online longer may lower prices and emissions at first, but it can also dampen clean investment incentives and lead to higher prices and emissions later on.”

There is no serious talk of building more nuclear power in Spain, Rodríguez says. He regards the delay more as a realistic move to better amortize the seven existing Spanish nuclear plants while the country invests more in storage and grid resilience. The 14 August decree itself insists that “the requested extension does not compromise the contribution of Spain to the renewables objective.”

There are 17 rare earth elements. While almost all of them have vital industrial uses, you could be forgiven for believing, based on news coverage, that there are only four that matter: neodymium, praseodymium, dysprosium, and terbium.

To be sure, those are the essential ingredients in the powerful permanent-magnet motors that go into electric vehicles, heating and cooling systems, appliances, tools, fighter jets, bombs, and many other systems. But the industrial and national-security importance of rare earth elements goes far beyond magnets. Among the 13 other rare earths are two—erbium and yttirum—whose importance is no less vital, and which are now facing a looming geopolitical deadline this November. Depending on how negotiations play out, the post-deadline framework could erode U.S. national security—or redraw U.S.–China trade relations.

Erbium is used in the amplifiers that boost optical signals in the fiber-optic cables that crisscross the planet. Yttrium is a key component of the thermal barrier coatings that protect turbine blades and other structures from blistering heat in jet engines and in the combustion turbines so in demand to power new data centers.

Yttrium is more broadly used than erbium; besides thermal barrier coatings, it is also used in white LED lights and displays, microwave filters, and solid-state lasers, among other applications. Also, “small quantities of yttrium feed into trillions of multilayer ceramic capacitors that keep our electronics world going, including AI data centers,” notes Thomas Kruemmer, a rare-earths consultant based in Singapore.

Erbium and yttrium, Kruemmer writes in an email, are good examples of how “tiny quantities of rare earths can have an outsized impact by enabling core functionality in their respective applications.” Taken together, all of these rare earths “literally affect almost anything we can switch on and off.”

Chinese dominance of the markets for these two rare earths is essentially 100 percent. Take erbium: “There is no one that I’m aware of, outside of China, that makes erbium oxide on a commercial scale,” says Eric Bender, vice president of strategy and corporate development at Tronox, a mining, processing, and chemicals company headquartered in Stamford, Conn. Erbium oxide is the molecular form that is typically produced by separation facilities and bought by industrial users of the element.

For yttrium, too, industrialized economies are entirely dependent on China. China mines 90 percent of the world’s yttrium, but it processes essentially all of the world’s mined ore into an industrially usable form, such as yttrium oxide.

Yttrium coatings help turbine blades in generators and jet engines survive the heat. Sergii Zhmurchak/iStock

China’s Monopoly and the Yttrium-Erbium Supply Squeeze

Twelve rare earth elements, including erbium and yttrium, are subject to global export restrictions instituted by China in April and October 2025. The restrictions for some of them, including erbium but not yttrium, were suspended for one year in November 2025. Exports of yttrium, and a few other rare earths, have become erratic and sharply reduced. In March 2026, China approved a single, 60-tonne shipment of yttrium oxide to the United States, followed by a 10-tonne shipment in April. But overall, shipments of yttrium to the U.S. are down around 75 percent this year in comparison with 2025.

In November, China is expected to either extend or remove the suspensions for some or all of the 12 rare earths currently under export controls. And yet there is little movement apparent on the part of U.S. and European governments to cope with the possible cutoff of yttrium and erbium supplies. “Very few folks outside of China are talking yet about ‘How do we produce erbium, how do we produce yttrium?’” says Gareth Hatch, managing director of Strategic Minerals Advisory. “We’re lagging behind the geopolitics, the realities, of the day.”

The most important thermal barrier coating is yttria-stabilized zirconia. GE Vernova is one of the world’s largest manufacturers of turbines and a major user of the compound. At an investor day meeting last December, GE Vernova’s CEO, Scott Strazik, said the company had enough yttrium to last into 2026, but did not specify how far into 2026. An emailed request for elaboration, sent to GE Vernova’s media organization, did not elicit a response by press time.

Nevertheless, there are clear signs that the reduced availability of yttrium is having an effect on the industry. Oerlikon Metco is one of the largest of the small group of companies that produce yttria-stabilized zirconia and the equipment that applies it to the blades and other parts of jet-engine and combustion turbines. The erratic availability of yttrium has “thrown us upside down in the last year or less,” says Riston Rocchio-Heller, an engineer and lab manager at the company. Demand for combustion turbines in the United States is now at an all-time high, driven mainly by the need to power new data centers, including huge “hyperscale” facilities for AI training and inference and general cloud computing.

Yttria-stabilized zirconia is a ceramic produced by mixing yttrium oxide with zirconium dioxide. Alternatives to it exist, but some unique advantages of the yttrium-containing version have made it the standard choice, according to Roccio-Heller. Researchers are trying to find better alternatives, he says: “A lot of collaborative work is going on right now,” he reports. But it’s unlikely to come to fruition soon.

The erbium market is dominated by just a couple of applications: the coloring of consumer glass and erbium-doped fiber amplifiers. These amplifiers are spaced along long-haul fiber-optic lines, typically every 80 to 120 kilometers on a terrestrial cable, and every 50 to 80 kilometers for a submarine cable.

The amplifiers consist of a piece of erbium-doped optical fiber, usually between 10 and 30 meters long. The doped fiber is illuminated, or “pumped,” with laser light at 980 or 1,480 nanometers. That laser light excites the erbium atoms into a higher energy state. When a weak optical signal enters the length of fiber, it triggers the excited erbium atoms, which fall to lower energy states and release photons in the exact phase, direction, and wavelength—1,550 nm—of the incoming signal. That wavelength corresponds to the spectral “window” in which silica optical-glass fibers cause the least loss of the signal. That’s why nothing but erbium will do here: It naturally re-radiates at the necessary wavelength.

Engineers are starting to use erbium-doped amplifiers in the free-space optical communication systems that connect low-Earth-orbit (LEO) communications satellites, such as the Starlink satellites, with each other and with ground stations. Groups of these LEO satellites are being launched into orbit on an almost daily basis. Because their signals don’t go through glass, satellites could use a much wider variety of wavelengths. But engineers are using the erbium amplifiers anyway to take advantage of their relatively low cost and the large existing industrial base for the 1550-nm hardware, says Michel Corriveau, a researcher at MPB Communications, in Pointe Claire, Quebec, Canada, a leading provider of erbium-doped fiber amplifiers.

Corriveau says MPB obtains erbium-doped fiber for its amplifiers from a couple of companies, including Lightera (formerly OFS) in Denmark, which is now a business unit of Japan-based Furukawa Electric. An executive at Lightera, Annette Lundby, declined to comment on the company’s ability to secure stocks of erbium.

Project Vault and a geopolitical deadline

Erbium and yttrium, along with 14 other rare earths and a couple of dozen critical minerals, are stockpiled by the U.S. government. This National Defense Stockpile is managed by the Defense Logistics Agency, which does not comment on its specific contents. In February 2026, the Trump administration announced a US $12 billion public-private initiative called Project Vault to stockpile rare earths and other critical materials. The funding includes $10 billion in financing from the Export-Import Bank of the United States—the largest single financing in the bank’s history.

Curtis Stough, a “defense stockpile liaison” at the Defense Logistics Agency, did not respond to a request for an interview. The U.S. Geological Survey, which tracks availability of critical minerals, also declined to make anyone available for an interview. The White House press office, too, did not make anyone available. But spokesman Kush Desai did provide a statement, which read, in part: “The Administration continues to take a multifaceted and nimble approach to reshore critical mineral supply chains back to the United States.”

That approach will surely be tested in the event that China’s 2025 export restrictions take full effect, which could happen on 10 November. But a lot will probably happen before then, says Hatch, making the outcome hard to predict. “This whole thing is ostensibly about dual-use control of materials” that have essential military uses. “But in reality, it’s part of the bigger trade picture.” So Hatch expects a wider discussion, leading up to November, involving leading-edge GPU chips, extreme-ultraviolet lithographic equipment, high-bandwidth memory, design-automation software, and other tech goodies that the United States and its allies are currently denying China.

In a tranquil Boston suburb, on the far edge of a horse farm, where pasture gives way to woods, a crane lowers an enormous electrode into a borehole. The electrode, a half-meter-long cylinder with copper-tipped arms to ensure good contact with the borehole walls, descends—deeper, deeper—through layers of spongy sandstone to the hard, marbled roots of an ancient mountain range hundreds of meters below ground. Here the rock is tight; there are few cracks for water or gases to flow. But that’s about to change.

A stone’s throw away, a second electrode—a twin of the first—has been fixed in another borehole at the same depth. From above ground, a pair of high-voltage generators cabled to the two electrodes fires a series of pulses.

Tsss!…Tsss!…Tsss!…Tsss!…Tsss!….

Each discharge, heard faintly at the surface, is like a miniature, subterranean lightning strike. The rock between the electrodes heats. Pressure builds. Then, suddenly, the rock splits into a spiderweb of fractures.

On a horse farm outside of Boston, a worker sets up the well where Eden’s electrode will be lowered with a winch.Bob O’Connor

Eden GeoPower, the Massachusetts-based startup performing this peculiar field test, calls the technology electrical reservoir stimulation. The company’s tagline: “We break rocks with electricity.”

Eden’s researchers hope their rock-breaking technique will someday aid mineral mining, tap geothermal heat, or create geologic storage areas for carbon. But there’s an even more intriguing use that could create a whole new category of energy production: generating hydrogen underground.

The dream of a hydrogen-powered economy dates back to the 1970s, when petroleum shortages and rising concerns about pollution from fossil fuels sparked visions of cars, ships, planes, and industrial machines running on hydrogen instead of carbon. Hydrogen is often touted as a clean fuel because when it’s burned or consumed in fuel cells, it emits only water and heat. However, it currently takes more energy to make than it yields, and the cheapest and most common way is by reacting steam with methane, a potent greenhouse gas.

How to Break Rocks With Electricity

It’s possible to make zero-carbon hydrogen by splitting water with electrolyzers powered by renewable energy. But in most cases, the process is too expensive to be economical—a reality that burst the hydrogen-hype bubble in the early 2020s. Global demand for hydrogen in 2024 reached approximately 100 million tonnes, containing energy equal to only about 3 percent of the world’s annual energy consumption. Most of it is used as chemical feedstock for petroleum refining and for making fertilizers and plastics.

The frustrations of manufacturing clean hydrogen have convinced many entrepreneurs and scientists to instead seek the element underground. For the past half-decade, dozens of companies around the world have been hunting for buried stores of hydrogen, called natural or geologic hydrogen. But with a commercial-scale operation yet to be proved, Eden and a handful of other startups and research groups are chasing the more audacious scheme of producing geologic hydrogen artificially.

This approach, known as stimulated geologic hydrogen or engineered hydrogen, turns subterranean rock formations into giant hydrogen factories. It typically involves injecting water into iron-rich rock, which oxidizes the iron and releases hydrogen as a by-product. Fracturing the rock, as Eden is doing, creates a network of conduits for the water to reach iron-bearing minerals.

The concept of stimulated hydrogen is so new that few have had a chance to test it. Proponents say that if it works—which is a big “if”—it could provide almost unlimited energy for the indefinite future. There’s one way to find out: Start breaking rocks.

There’s Plenty of Underground Hydrogen

Hydrogen is the simplest and most abundant element in the universe, the stuff of stars and galaxies. Geologists have long known that Earth generates hydrogen gas through natural water-rock reactions, but until recently, the occurrence was regarded as a curiosity. The gas is so light that most experts assumed it all escaped through pores and cracks in Earth’s subsurface and didn’t accumulate in useful quantities.

During a demonstration at Eden’s testing site near Boston, an employee displays a central component of the company’s proprietary electrode. Bob O’Connor

Inklings that they were wrong emerged in the 19th and 20th centuries, when researchers in the former Russian Empire and Soviet Union reported hydrogen seeping from mines and wells. But in the ongoing frenzy for fossil fuels, these observations were largely overlooked or forgotten. Scientists later discovered hydrogen spewing from hydrothermal vents in the seafloor and feeding so-called eternal flames, like those of Türkiye’s Mount Chimaera, where ancient athletes lit torches for the first Olympic games.

Then, in 1987, in the village of Bourakébougou, Mali, people drilling a water well noticed a breeze blowing out of the hole. According to local lore, a worker leaned in for a closer look, a lit cigarette dangling from his mouth. The air instantly ignited, burning a brilliant blue.

The crew capped the well, which stayed sealed for 25 years until, in 2012, a Malian oil and gas prospector confirmed the ground contained a large reservoir of hydrogen. The prospecting company, now called Hydroma, had a small electrical plant constructed to convert the gas into power for the village’s residents. Soon after, startups in Australia, Canada, the United States, and elsewhere began searching for more hydrogen stores. By 2025, large multinational petroleum and mining companies were getting in on the game.

To date, hundreds of exploratory wells have been drilled across the globe. But although researchers have documented widespread hydrogen deposits, none have proved capable of producing the gas at rates and quantities needed for commercialization. “We’ve poked a lot of holes, and nobody has found the gusher—or at least they’re not talking about it,” says Douglas Wicks, a former program director at the United States’ Advanced Research Projects Agency—Energy who now advises companies pursuing geologic hydrogen.

A wellhead guides multiple lines downhole: fluid hose, electric cables, rope, control for a sealing device, and sensor communication. Bob O’Connor

Wicks says that in 2022, while at ARPA-E, he got “dragged into the rabbit hole of geologic hydrogen” by Emily Yedinak, then a Fellow at the agency, who was trying to convince her colleagues to take it seriously. “I was the ultimate doubter,” Wicks says. The astronomical price of electrolyzers had made him skeptical that clean hydrogen was a viable pursuit. Plus, if Earth really did contain vast pools of hydrogen, then surely humanity, which had been digging for natural resources for thousands of years, would have found them by now, he reasoned.

But after talking with geologists—who pointed out that people historically hadn’t found hydrogen because they hadn’t been looking for it—Wicks changed his tune. “I got the epiphany that geologic hydrogen is not just an accumulation; it’s a chemical reaction,” he says. “And if it’s a chemical reaction, then it can be stimulated.”

Finding large accumulations of geologic hydrogen entails stumbling on a Goldilocks set of conditions. You need iron-rich source rocks that have already produced or are producing bountiful hydrogen. You also need porous reservoir rocks that can hold sizable quantities of gas migrating from the source rocks. And you need solid cap rocks above the reservoir that trap the gas underground.

To stimulate hydrogen, however, you don’t need this just-right geology. All you need are iron-rich rocks, and then you can generate the hydrogen yourself.

“These rocks are everywhere,” Wicks says. “If you look at the amount of iron that’s within drilling range of Earth’s crust, you’re talking about quadrillions of tons of hydrogen being accessible. If we’re 1 percent successful just in the United States, we could power the economy for thousands of years.” A back-of-the-envelope calculation convinced him that the cost of stimulated geologic hydrogen could easily compete with hydrogen made from methane. “If we get the technology right,” he concludes, “this could be huge.”

Wicks wasn’t the first person to propose the idea, but he was the first to allocate major funding. In 2024, under his leadership, ARPA-E awarded US $20 million to 16 teams aiming to advance stimulation technologies and research. Winning ideas included fracturing rocks with fluid pressure or mechanical stimuli, exposing them to catalysts to speed hydrogen-generating reactions, and manipulating native microbial communities to enhance production. Eden’s rock-breaking project, the lone electricity-based approach, received $900,000.

Eden GeoPower’s Underground Rock Fracturing

Paris Smalls, Eden’s CEO, founded the company in 2017 as a 23-year-old graduate student at MIT. For his Ph.D. in civil and environmental engineering, he was studying the effects of electricity on rock strength and became interested in enhanced geothermal systems, which require fracturing hot, dry rocks to circulate water through them for extracting heat. This is typically done by hydraulic fracturing, or fracking—a technique borrowed from the oil-and-gas industry that involves injecting high-pressure fluids.

Fracking is controversial because it can cause earthquakes and groundwater contamination, and many regions have banned the practice. From an engineering perspective, it’s also imprecise. The fractures it forms are large and difficult to control. “You can’t get enough fractures where you want because the water ends up just going through the same cracks,” Smalls explains. Electricity, he knew from his Ph.D. work, could create more extensive and finely tuned fracture networks, enabling geothermal systems to produce more heat with less environmental risk.

To determine how permeable its fracture networks are, Eden measures fluid pressure downhole and flow rates at the surface. Bob O’Connor

Smalls immediately grasped that the same rock-breaking strategy could be used for mineral mining, carbon sequestration, and extending the life of oil and gas wells. But he hadn’t considered using it to make hydrogen. So when Wicks invited him to apply for the hydrogen program at ARPA-E, he was confused. “I didn’t get it at all,” Smalls says. “I’m like, ‘I break rocks. How am I going to generate hydrogen?’”

Not long after, Smalls met Alexis Templeton, a geomicrobiologist at the University of Colorado Boulder who had become an expert in geologic hydrogen by studying microbes that consume the gas and the mineralogical transformations that create it. “There was a lot of early interest in whether or not you could engineer the production of hydrogen from rocks,” Templeton recalls. “And the rocks with some of the best potential have all the right chemistry, but they need water. Nobody was excited to do hydraulic fracturing. So everyone was wondering, ‘Well, how are we going to get the water in?’”

Eden’s technology, Templeton understood, could be the answer. She agreed to join the company part-time as its lead geochemist, a position she held from 2023 to 2025. During that time, Eden ran its first pilot experiment, in an oil field in Oman, near where Templeton was already doing her own hydrogen research. The initial setup used DC power to send a steady flow of tens of kilowatts between electrodes in two wells. When Smalls’s team tested it in a petroleum reservoir made of soft, chalky carbonate, the rock fractured readily, increasing oil production by 30 percent.

But when they did the same test in hard rocks, like those needed for hydrogen and geothermal systems, they didn’t fracture much at all. So the team went back to the drawing board and came up with a fix: pulsed power.

Using Pulsed Power for Rock Fracturing

The idea of breaking things using pulsed power—short, concentrated bursts of electrical energy—originated with a mid-20th-century experiment in Soviet-era Russia. As the story goes, a physicist and inventor named Lev Yutkin was out in a thunderstorm when he saw lightning strike a log underwater. Rather than burn, as it would in air, the log exploded, as if blown up by dynamite. Intrigued, Yutkin tried to reproduce the spectacle in his lab. He placed a dinner plate in a water tank, dipped in two wire electrodes, and released a high-voltage pulse. The ensuing spark, he discovered, instantly ionized the water molecules between the electrodes into a plasma channel, which then rapidly expanded, creating a shock wave that shattered the plate.

Yutkin described the phenomenon in his 1955 book Electrohydraulic Effect. He later proposed numerous fanciful uses for it, such as cleaning pipes or breaking up kidney stones, which inspired real tools in use today, including electrohydraulic drills and rock-crushers, and a kidney-stone-busting medical device called a lithotripter. The following decades saw advances in pulsed-power systems and experimental techniques to better understand the complex physical processes involved. By the 2020s, when Smalls’s team began investigating it for subterranean rock fracturing, the technology seemed ripe for use, although that particular application had been little explored outside the laboratory.

“We essentially generate a plasma channel in the rock itself,” says Rafael Villamor-Lora, vice president of R&D at Eden. “This channel then expands very, very rapidly,” fracturing the rock with a shock wave. Bob O’Connor

Eden’s scientists first experimented with pulsed power on thumb-size hard-rock cylinders. Instead of submerging each sample in water, however, they placed a pair of electrodes at opposite ends of the cylinder and delivered pulses directly to the rock. Using this dry-pulse method, drawn from Smalls’s and others’ research, the team found they could form plasma in tiny, moist pockets between mineral grains. “We essentially generate a plasma channel in the rock itself,” explains Rafael Villamor-Lora, Eden’s vice president of research and development. With enough pulses, the fast-swelling channel, as in Yutkin’s investigation, induces a shock wave that fractures the rock.

To bring the technology to the field, Eden needed voltage high enough to break through meters of solid rock. The obvious solution was a Marx generator, which converts low-voltage DC power into high-voltage bursts by slowly charging and then rapidly discharging multiple capacitors in parallel. (Marx generators are commonly used in high-energy physics experiments and to simulate lightning strikes on power lines.) Eden custom-built two devices—named Zeus and Thor after the gods of thunder—which together can release a surge of several hundred kilovolts.

This time, the plan worked. In 2025, in an abandoned gold-and-silver mine in Colorado, Eden used Thor to successfully fracture a hard, igneous column, increasing its permeability tenfold.

Ezra Frank, a mechanical engineer at Eden, works on Zeus, Eden’s custom Marx generator. Bob O’Connor

In March this year, the company began setting up the test site on the Massachusetts horse farm to refine its systems and gather more data on how the technology performs in different geologic environments. Its engineers are also designing more powerful generators to discharge stronger and faster pulses. Because Zeus and Thor consume very little power—akin to running a toaster or two—it takes about a minute to store enough energy to fire a maximal pulse. It then takes around 100 pulses to penetrate around 10 meters of hard rock. So fracturing over longer distances or at multiple depths can take hours to days. That means Eden’s biggest cost is labor, not energy.

Smalls says Eden signed an agreement with a geologic hydrogen startup—he declined to say which one—to demonstrate electrical fracturing in a field pilot of stimulated hydrogen, which could begin late next year. Eden will need to prove its technology can help coax the gas from the ground at a profitable rate and cost.

“It’s no question whether we can produce hydrogen,” Villamor-Lora says. “The question is whether we can produce it fast enough to be economical.” In the lab, Eden researchers found they could generate up to four times more hydrogen from rock samples using the pulsed-power technique, compared with the amount found in unfractured samples. But that may not be enough to make stimulated hydrogen commercially viable without some additional technology.

Other Approaches to Stimulated Geologic Hydrogen

One of the biggest challenges in stimulating hydrogen is that there’s no obvious go-to recipe. Beyond the basic ingredients of water and iron, many factors affect how much hydrogen is generated and for how long, and fractures are only one factor. Laboratory studies have shown, for example, that the ideal temperature for maximizing hydrogen production is around 200 to 300 °C. Acidity, rock and water chemistry, and microbial inhabitants are other important considerations.

Making the puzzle more complex, each rock formation is different and may require different stimulation techniques or a combination of them. “There isn’t a single solution that will work everywhere,” says Alexei Tcherniak, CEO of the hydrogen startup GeoKiln. “You have to know the geology you’re operating in.”

Some promising rock formations, he points out, may already be fractured or porous enough to become saturated with water but too cool to make ample hydrogen naturally. To solve this problem, his company, based in Houston, uses a system of underground heaters originally developed for improving flow in heavy oil reservoirs and converting solid organic matter in young shale rock into extractable oil and gas. The heaters, which are commercially available, can be installed in boreholes drilled into hydrogen source rocks, similar to Eden’s electrodes. Tcherniak says that GeoKiln is ready to start field testing as soon as it can raise the capital.

Other researchers are exploring the use of catalysts—metal or chemical salts that speed hydrogen-generating reactions—which, they say, could replace or complement fracturing or heating to increase hydrogen production at less cost. Vema Hydrogen, for instance, is betting on a mixture of boiler-heated water and proprietary catalysts. “What I can say about our catalysts is basically what they are not, which is not toxic, not expensive, and not dangerous,” says Florian Osselin, Vema’s chief science officer. The company, also headquartered in Houston, has begun drilling pilot wells in Canada to test its mysterious brew. By injecting it into semi-permeable rock, Vema expects to achieve commercial production rates without fracturing. “We’ve done field-scale numerical simulations that give us a lot of confidence,” Osselin says.

Another stimulation method, proposed by the Denver-based startup Koloma, aims to expose more rock surface for generating hydrogen by mimicking natural weathering. The technique involves adding carbon dioxide to water and injecting the fluid at specific times to control for factors like acidity and gas concentrations. The carbon dioxide reacts with the water to form an acid that breaks down mineral chains in rock pores, thereby increasing the pores’ surface area, explains Tom Darrah, the company’s CTO, who studied and patented the method as a professor at Ohio State University. “I call it micro-pitting because the texture goes from smooth to rough,” he says. As with fracturing, more surface area means more hydrogen production—if you can get the formula right.

Rita Esuru Okoroafor, an energy resources engineer at Texas A&M University, is studying the effects of various stimulation approaches, including fracturing, catalysts, and carbon-dioxide injection, on hydrogen generation. Her data, based on laboratory tests of rock samples from around the world and numerical models of stimulated geologic hydrogen systems, suggest that none of these approaches alone will sustain hydrogen production at rates needed for long-term commercial development. “We’re still fine-tuning our models, but they’re telling us that we’re going to need a lot of fracturing, we’re going to need catalysts, and then we’re going to need restimulation,” she says.

The process of generating hydrogen, Okoroafor explains, will eventually consume all the readily available iron in exposed rock surfaces, causing production to plummet. By accelerating hydrogen generation, catalysts also accelerate its decline. “When these reactions happen very fast, they also die very fast,” she says. They also leave behind mineral precipitates that can clog existing cracks. In a recent study, she found that hydrochloric acid helps clear the debris, expose fresh rock surfaces, and reopen water pathways to restore production.

It’s too early to know which technologies will win out in the race for geologic hydrogen and if stimulation will even be needed to make it a viable industry. What’s more, production is just the first step toward commercialization. Many questions remain. Once hydrogen is flowing from the ground, how will the gas be purified? How will it be stored and transported? How will the industry be regulated? What are the environmental risks, and how will they be mitigated? What will be the cost?

“With all these wars and gas prices going up, we need to be preparing for the future,” Smalls says. But as is often the case with nascent technology development, life gets in the way. At the horse farm, fracturing started in June after being delayed for months, first by a snowstorm and then minor equipment failures and other logistical snags. “Everything takes longer than you think,” Smalls says. Still, he’s unfazed, ever the optimist. “I like to go after things that other people are afraid to.”

This article appears in the September 2026 print issue as “How To Get Hydrogen From a Stone.”

New York isn’t particularly inundated with new data centers, but it just became the first U.S. state to ban them. In an executive order on 14 July, Governor Kathy Hochul imposed a moratorium of up to a year on data centers that consume 50 megawatts of power or more.

The ban arose from concerns about data centers’ power and water use and effects on residential electricity bills. Such worries have risen sharply across the U.S. over the last year as more developers propose projects and request grid connections. Data-center energy use in the country is expected to exceed 650 billion kilowatt-hours by 2050, doubling to quadrupling today’s consumption.

Virginia, Texas, and California have received an onslaught of data centers, sparking public backlash and sending grid operators scrambling to keep up. But in New York that’s not the case. Electricity margins in the state’s grid are running thin and power bills are rising, but data centers aren’t to blame—for now.

“I don’t think we’ve actually seen those fights in New York,” says Daniel Zarrilli, who most recently served as the chief climate and sustainability officer at Columbia University and was previously New York City’s chief resilience officer and chief climate-policy advisor. “We’re seeing the anticipation of those fights, which is what I imagine led to the moratorium.”

So the governor’s move is preemptive—and it alone won’t fix the state’s energy woes. “Anytime you open the paper, figuratively speaking, these days, there’s all this discussion about data centers,” says Kevin Lanahan, senior vice president of external affairs and corporate communications at New York Independent System Operator (NYISO), which runs the state’s power grid. “But the increase in demand that we have experienced and been tracking really has not been attributable to data centers yet.”

Rather, Lanahan says, New York’s razor-thin electricity margins are mostly a result of the increasing electrification of the state’s building and transportation sectors. That is only expected to continue, and Lanahan says it will drive forecasted grid strain alongside new manufacturing facilities in NYISO’s territory.

“We have some modern manufacturing and some traditional manufacturing in the queue that promises to increase the demand going forward,” Lanahan says. For example, he cites a Micron semiconductor plant under construction near Syracuse that could consume over 1 gigawatt when complete.

Making matters more difficult, NYISO’s aging grid infrastructure isn’t up to the task of meeting new demand. “What we need is new dispatchable generation,” he says. “Hard stop.”

Why New York’s Power Grid Is Vulnerable

New York’s move is an indicator that the U.S.’s burgeoning anti–data center movement has gained traction. Bans on the power-hungry facilities have proliferated over the past year at the county and municipal levels, but this marked the first statewide prohibition. Texas on Monday followed suit in the form of a directive by Governor Greg Abbott ordering the state’s grid operator to pause new data-center connections until it completes an audit of proposed facilities.

The New York ban comes just a month after NYISO announced that New York’s grid wouldn’t have much headroom this summer. Only 417 MW of extra power is available during typical peak demand, NYISO estimates—the lowest summer reserve margin since 2017. Additional pressure on the grid, such as from extreme temperatures, could make margins even thinner and force the use of higher-polluting backup plants.

Since 2019, 2.9 GW of power generation have been added to New York’s grid, but 4.4 GW have come offline, according to a NYISO report published in June. The retired facilities were largely fossil-fuel powered and have been taken out of the system because of factors such as mechanical issues and performance decline.

As a result of the mismatch, summer reserve margins have decreased by 1,810 MW since 2019. “We have what we assess to be the oldest-generation fleet in the country,” Lanahan says. During heat waves, like one that occurred over the July 4 weekend, NYISO must turn on some of those old facilities. “We’re relying routinely…on old steam, peaking units that were built sometimes 70 years ago,” he says.

Meanwhile, the requests for new connections to the grid keep coming. In total, about 14 GW worth of large electricity load await review in NYISO’s grid interconnection queue. Twelve of those gigawatts come from data centers and crypto-mining facilities spread across 40 projects. All but two exceed the moratorium’s 50 MW threshold. NYISO will need to study the requests to see how they’ll impact its system before allowing them to connect. Lanahan says the agency is planning for only about 3 GW to come to fruition within the next 10 years, because projects routinely withdraw from the process or are subject to delays.

“Together we’ve got these two bookends: the increased poor performance of the system because we’re relying on aging infrastructure, and then that future challenge to meet,” Lanahan says.

Solutions such as demand response to manage the increased load aren’t enough, he says. Some facilities could build their own power generation—something NYISO is developing rules around in accordance with a Federal Energy Regulatory Commission directive issued earlier this summer.

IEEE Spectrum reached out to Hochul’s office to determine what the state government is doing to address New York’s shrinking reserves and aging fleet. Senior energy and environment communications advisor Ken Lovett says that the state is prioritizing renewable energy such as wind and solar, plus a nuclear reliability initiative that will add a backbone of 5 GW to the system. “Governor Hochul will never sacrifice the reliability of the grid,” Lovett says.

Large manufacturing facilities, such as a Micron semiconductor plant currently under construction in upstate New York, are a major factor driving future electricity demand in the state.Mike Groll/Office of Governor Kathy Hochul

New York’s Data Center Ban Buys Time

So New York’s ban on data centers is addressing only part of the problem, and a largely future one at that. It will have no effect on NYISO’s interconnection queue, Lanahan says, as the executive order only bans environmental permitting of data centers, not their grid connection. “Projects are still there,” he says. Project developers are “still working with us on the exchange of information that’s requisite to complete what’s called a system impact study. That’s the responsibility we have in that process.”

New York’s moratorium is set to lift when the state’s Department of Public Service completes an assessment of the impact of data centers. Governor Hochul called for using the time, which could last up to a year, to build a regulatory framework that protects the state’s electricity supply, utility bills, and the environment.

Zarrilli, formerly at Columbia University, says that it’s “hard to imagine” the moratorium being extended beyond a year. The governor “continues to support AI and the data centers that drive it,” Lovett says.

Asked about the usefulness of the moratorium, Zarrilli says he’s “hopeful” that the pause can give the state time to plan for the future grid issues posed by data centers. Still, he says there’s the possibility that a year is simply not enough time.

“There’s a scenario for sure where the state takes this time and comes up with a thoughtful path forward for managing the growth and strengthening the grid, and doing it in a way that’s affordable for New Yorkers,” he says. “And then there’s clearly a possible scenario where the time runs out and we haven’t done those things, and then it’s a scramble to figure out what to do next. That latter option would be tragic.”

Today’s U.S. electrical grid, among the largest, most complex systems ever built, is operating at its limit. The combination of rapid industrial growth, more frequent extreme weather, and a record surge in electricity use has pushed the grid to its breaking point, according to the U.S. Department of Energy.

Built decades ago for a more predictable world in which power came mostly from centralized coal or gas plants and electricity use grew at a steady pace, the grid faces unanticipated strain due in part to growing demand from data centers. The jobs of professionals managing the infrastructure have evolved from traditional engineering tasks to complex, fast-moving challenges.

Industry reports show that millions of modern digital sensors, smart meters, and grid monitors are generating nonstop waves of information. The sheer volume of data requires instant, automated computer analysis because human operators cannot process it fast enough.

Pressure on utilities stems from two sources: a spike in electricity demand and a shift in how power is generated.

An example of the operational strain can be seen at the regional level. With the recent deployment of artificial intelligence tools and high-performance computing, data centers require immense amounts of energy to operate. The largest power transmission utility in Texas recently reported a staggering 220 gigawatts of new connection requests, driven largely by a surge in AI and cloud-computing facilities, according to a CNBC report.

Alongside the rise in regional demand, global energy networks are absorbing an unpredictable variety of weather-dependent renewable energy such as wind and solar. The switch creates a volatile operating environment wherein supply and demand are balanced, second by second, to prevent blackouts.

The challenges are compounded by the vulnerability of the grid’s physical and digital framework.

More-frequent severe weather events cause costly disruptions, such as the devastating winter freeze that crippled the Texas grid and record-breaking heat waves that have overloaded transformers.

Simultaneously, the energy networks’ digital architecture faces threats. As utilities replace outdated analog equipment with smart meters and control systems, they are increasingly vulnerable to cyberattacks.

To overcome physical and digital vulnerabilities, grid reliability organizations, such as those conducting North American security simulations like GridEx, emphasize that the grid must become smarter, more agile, and completely automated. Energy researchers are noting that the key to this change lies in integrating AI across every layer of utilities’ operations.

The AI imperative

According to energy industry experts, using AI to manage power systems is no longer a futuristic research project; it has become a baseline operational necessity. Grid analysts emphasize that traditional grid-planning methods are too slow to handle rapid energy dynamics or to balance volatile renewable energy in real time within decentralized power systems such as microgrids.

AI can fill the gap by processing vast amounts of data instantly. Machine learning algorithms can quickly analyze information from thousands of sensors, historical usage patterns, and weather forecasts to predict issues before they happen.

An industrial digitization study conducted by McKinsey & Co. indicated that integrating advanced data and automation across infrastructure networks could reduce system design errors, decrease equipment downtime by up to 50 percent through predictive maintenance, and extend the lifespan of power machinery by up to 40 percent.

From forecasting energy spikes to automatically fixing localized voltage drops, AI acts as the digital backbone of a self-healing grid, experts say. Deploying the complex systems requires a new workforce: power engineers who understand data science, as well as data scientists who understand electricity.

Upgrading the Workforce

To bridge the gap between groundbreaking AI research and practical field deployment, IEEE Educational Activities, in partnership with the IEEE Power & Energy Society, has launched the online Artificial Intelligence for Power and Energy Systems course program.

The program explores core challenges threatening modern utilities. Rather than treating AI as an unverified black box that operates without human supervision, the curriculum focuses on safety, asset preservation, and strict reliability standards.

The curriculum is designed to educate power system engineers, utility managers, and data scientists tasked with modernizing the grid. The program was developed by Fangxing “Fran” Li, professor of electrical engineering and computer science at the University of Tennessee in Knoxville and chair of the IEEE Working Group on Machine Learning for Power Systems.

Five learning modules

The program breaks down the technical transition into five modules that bridge high-level theory with real-world solutions:

AI fundamentals. This module teaches engineers how basic machine learning models apply to power grids. It discusses how specialized neural networks solve complex power-flow calculations and how AI models can safely transition from computer simulations to physical, high-voltage equipment.

Accelerating grid control. Learners are taught to leverage deep reinforcement learning, an AI approach that uses trial and error, to accelerate automated grid adjustments during emergency power events.

Forecasting and data analytics. Using predictive modeling, engineers learn how to predict sudden demand surges, variable wind and solar outputs, and fluctuating wholesale electricity market prices to keep power affordable and available.

Physics-informed and safe AI. To address trust—a barrier to utility AI adoption—this course covers AI models hard-coded to obey the laws of physics. The approach is designed to ensure that automated algorithms never make erratic choices that damage grid equipment.

Generative AI and next-generation tech. Learners can explore the frontier of utility technology, including graph neural networks and large language models. This module highlights how generative AI can process complex, interdisciplinary data to streamline utility planning, emergency responses, and regulatory reporting.

The algorithmic literacy and practical execution tools provided by the course program can help convert systemic risks into grid resilience.

For individual access, visit the IEEE Learning Network. If you are looking for customized organizational options, contact a content specialist to discuss volume pricing.

Despite setbacks in sodium-ion battery development in the U.S., the startup Peak Energy says it can be the one to finally achieve the ambitious application of using the tech to store energy for the grid.

When U.S. start-ups Natron Energy and Bedrock Materials shut down sodium-ion battery operations last year, they joined an ignominious list of more than dozen failed Western battery companies.

CATL, based in China and the world’s largest battery company, then dropped a bombshell in April, announcing it would supply 60 gigawatt-hours of sodium-ion cells to the grid storage provider HyperStrong. The largest sodium-ion battery order in history suggested China was on its way, as with lithium-iron phosphate in previous years, to dominating yet another promising chemistry.

The Colorado-based Peak Energy insists it can succeed where companies like Natron failed. Company executives say its sodium-ion tech can compete directly with low-cost lithium-iron phosphate (LFP) batteries, which currently dominate grid storage. Unlike Natron, which ran out of money and investors’ patience, Peak Energy has a giant in its corner: General Motors. Like Tesla and other automakers, GM is moving aggressively into grid storage to keep massive battery factories humming in the wake of slumping EV demand.

Peak Energy has formed a partnership with the automaker to ultimately deploy sodium-ion batteries at grid scale. In July, the company announced it will build a US $71 million, 17,000 square-meter factory near Sacramento, with capacity to produce 4 GWh of sodium-ion batteries annually, enough to power 4 million homes.

Sodium-Ion vs Lithium-Iron Phosphate Batteries

As with other sodium-based designs, Peak Energy’s cells can’t yet match the energy density of LFP batteries. Company executives from Peak Energy and GM, which has partnered with Peak to codevelop and manufacture the batteries, freely admit they can’t currently compete with current LFP prices on a per-cell basis.

Yet Peak Energy says its passively cooled storage system will still cost operators 20 percent less over its lifetime compared with LFP storage. Cameron Dales, Peak Energy’s cofounder and chief commercial officer, says the company’s GS1.1 system will store energy for 20 years, over roughly 20,000 cycles, and still retain 80 percent of its capacity. For LFP, a basic durability benchmark pegs them at 70 percent capacity after 8,000 cycles.

Peak Energy’s case is helped by a booming market for energy storage, to back up AI data centers and to store excess solar and wind energy. Volatile lithium prices have major players looking for a steady alternative.

Incumbent LFP batteries, Dales says, were initially designed for EVs, where cell costs and energy density are critical for driving range and affordability. But utilities and storage operators are focused on entirely different metrics. They want batteries that last the longest, at the lowest overall cost, to maximize returns and justify massive capital investments.

The company’s technical edge, Dales says, is that its stable cells that can operate safely at temperatures roughly double the typical operating temperatures of LFP, which performs best at or near room temperature.

“You need to keep an LFP cell at 25 °C, give or take, or it will rapidly degrade,” Dales says.

The generous temperature tolerance of Peak Energy’s cells allows a passive cooling system with no pricey, trouble-prone fluid cooling loops or moving parts such as fans or pumps. That makes the modular system well-suited for data centers or grid support in desolate areas, where operators are finding abundant cheap land, high potential for solar energy, and a low risk of natural disasters.

“You don’t have to power a refrigerator in the desert for 20 years to keep the system operating properly,” Dales says.

The GS1.1 system stacks slender prismatic cells into modules roughly the size of a king-size mattress. A 36-module system stores 3.1 megawatt-hours. Large-scale projects might combine dozens or hundreds of units, generating enough juice to power a small city.

Proponents note that sodium is the sixth-most abundant element on earth, roughly 1,000 times as abundant as lithium. And unlike lithium, which must be sourced from far-flung regions fraught with environmental or human-rights issues, the world’s largest, purest deposits of trona are found in the Green River Basin in Wyoming. Trona, which is composed of sodium carbonate, sodium bicarbonate, and water, supplies the United States with 90 percent of its soda ash, which is the basis for battery-grade lithium carbonate salt. However, analysts note that while the raw material may be plentiful, its processing is dominated by China.

“The supply chain tends to get overlooked, but it’s just a massive issue,” says Varnika Agarwal, a battery research analyst at Benchmark Mineral Intelligence.

Agarwal says sodium-ion tech holds promise. But a lot has to go right for sodium ion to carve out a viable niche in the U.S. Benchmarks project that less than 1 percent of newly deployed storage in the United States will be sodium ion this year, less than 4 percent by 2030, and 5 percent globally.

For now, she notes, Peak Energy is buying its commercial cells via contracts with Chinese suppliers, which dominate both processing of its raw materials—however cheap-and-abundant they may be—and cell production. The U.S. is basically just getting started, with Peak Energy’s California factory slated to come online in 2027.

NFPP Cathodes in Sodium-Ion Batteries

Natron was banking on long-shot “Prussian Blue” electrodes, a form of blue pigment that acts as a sponge to soak up and release sodium ions. Peak’s batteries, however, rely on sodium iron pyrophosphate (NFPP) cathodes, which are chemically and structurally similar to lithium-iron phosphate in an LFP battery, known for superior safety and long cycle life.

NFPP is fast becoming an industry standard. CATL has also settled on NFPP for its core chemistry. This helps make Peak Energy’s cells largely “drop in,” able to be manufactured at existing battery plants such as GM’s—a huge advantage for market viability.

Kurt Kelty, Tesla’s former battery guru and a globally recognized battery expert, is now vice president of batteries and sustainability at GM. Kelty says GM is backing Peak Energy for several reasons, including his familiarity with and respect for its own former Tesla execs.

Peak Energy executives [from left] Landon Mossburg, Kurt Kelty, and Cameron Dales show off one of the company’s prismatic cell batteries.Lucas Breuer/Peak Energy

GM has been testing Peak Energy’s cells, in 170 and 190 ampere-hour formats, at its Wallace Battery Cell Innovation Center in suburban Detroit, in the same labs where GM is developing its proprietary lithium-manganese-rich battery chemistry. Kelty says the battery life of competing cells, from a full range of global producers, “falls off a cliff” during high-temperature testing. But Peak Energy’s batteries are withstanding extreme testing at up to 55 °C, with notably little effect on their lifespans.

“The cell is kicking butt over everything,” Kelty says. “We can get 20 years of lifetime without a cooling system, and that’s the key.”

The batteries are showing a round-trip efficiency of 96 percent, a significant 2 to 3 percent better than LFP. (“Round trip” refers to the amount of energy a battery discharges, relative to the amount used to charge it).

Eliminating active cooling, Kelty adds, allows a near-silent system that could be used in public buildings. In addition, it ditches the plumbing that’s a potential trouble spot for leaks and maintenance.

“It also reduces parasitic power losses, because you’re not using power to cool the system,” Kelty says.

Peak and GM executives believe sodium-ion cells themselves will reach price parity with LFP around 2028, based in part on discussions with Chinese cathode suppliers. Sodium ion, they say, is just entering its steep slope of cost reductions, where LFP’s savings have largely been realized over 20 years.

Peak Energy’s Sodium-Ion Battery Projects

In March, Peak Energy announced it will join with RWE Americas for another pilot system near Milwaukee. That would become the first-ever use of sodium-ion backup on the Midcontinent Independent System Operator, the regional grid operator for 15 central states and Canada’s Manitoba province.

Peak Energy also plans to begin supplying up to 4.75 GWh of batteries to Jupiter Power, an independent storage developer, through 2030. The deal, worth up to $500 million, includes an initial 720 MWh of storage, including in Texas, the nation’s largest single announced deployment of the batteries to date.

Ask Dales about winners and losers in battery chemistries, and he’ll tell you it’s the wrong question. In a world of planes, trains, phones, drones, and every imaginable device, it makes no sense that one “super battery” would rule them all.

“Sodium ion is just another sister technology to lithium,” he says. “But instead of going higher energy density, it’s going lower energy density, and you’re paying for that with better stability and safety at a lower cost.”

This story was updated on 23 July, 2026 to correct the timeline for Peak’s California facility. It is scheduled to come online in 2027, not 2028 as originally stated.

In the chill of a London spring night, under overcast skies, iconic Trafalgar Square opens around me. Admiral Nelson rises on his pedestal, the National Gallery rests behind, the church of St Martin-in-the-Fields sits nearby. From the 13th century, the site served as the Royal Mews for hawks and then horses. By 1844, it was a public space at the heart of one of the biggest cities in the world.

Despite the square’s presence through that grand sweep of history, it’s not why I’m here. My interest is far more specific: I want to find out what happens to spaces like this when artificial light, specifically from light-emitting diodes (LEDs), intrudes. My companion tonight is Simon Thorp, a local lighting designer, who crouches in the shadows near Nelson’s spire, light meter in hand. “Two lux,” he reports, “and it’s very comfortable here.” Two lux is 10 to 20 times the illuminance of a full moon. We can see each other clearly, and a nearby sign assures us that closed-circuit television (CCTV) is in operation for safety’s sake.

Trafalgar Square captures the relationship between lighting and darkness that exists in almost every city, suburb, small town, and village around the world. The lighting here is a mishmash of old technologies and new, of shadow and glare, the ornamental gas lamps fronting the National Gallery all but washed out by the LEDs inside modern versions of traditional “brass and glass” fixtures a few meters away—21st-century technology housed in 19th-century designs.

The ugly truth of artificial lighting today is that in parts of London, as in many cities around the world, lighting levels are excessive, with unshielded illumination blasting in all directions. And the irony is that too much light invites danger: It creates shadows, impedes our vision, and gives the illusion, without the reality, of safety. Thorp notes that modern CCTV cameras are “pretty great” even at low-light levels, while harsh light makes it hard for both human eyes and digital sensors to see.

“The more bad light we add, the more bad light we think we need,” says Thorp. “We can’t see because of the light we’ve added. And it makes areas that were perfectly okay seem darker.”

Among the costs of this excess, the most alarming may be its toll on human health (and that of other animals) by disrupting circadian rhythms, impeding the production of melatonin, and contributing to sleep disorders that are tied to every major modern disease. New research shows that increased exposure to blue light from LEDs is having “substantial biological impacts” such as suppression of the sleep hormone melatonin and an increased risk for obesity, certain cancers, and type 2 diabetes.

A panoramic view from the Eiffel Tower looks down the Pont d’Iéna and the Palais de Chaillot [in the center], with the imposing silhouette of the La Défense business district visible on the Parisian skyline.

Luigi Avantaggiato

I have come to London and Paris—which led the way in the expansion of public street lighting in the 19th century—because they embody both the current enormity of the problem as well as a future certain to be lit by trillions of chips: controllable, tunable, and energy-efficient LEDs.

Living with artificial light at night

The standard justification for nighttime illumination is public safety. Lighting experts’ term for the phenomenon is “artificial light at night.” While people won’t often admit it, the desire for light at night seems to stem from a primal fear of the dark. Darkness is where the bad guys hide. And if dark is bad and light is good, then more light can only be better.

This assumption has guided our use of nighttime light for hundreds of years. And yet, high-lumen output doesn’t necessarily correlate to a reduction in crime, research has found. In other words, if we relied on the data as much as we do our primal anxieties and paused those anxieties long enough to learn how light and darkness interact, our nights would almost certainly be lighted differently—especially now that we have the extraordinary technology that is the light-emitting diode.

A 19th-century gas lamp [white square] manufactured by William Sugg & Co. next to a pedestrian path in Trafalgar Square, along with the architectural floodlighting on the neoclassical facade of the National Gallery, showcase the interplay between modern and historic lighting systems.

Luigi Avantaggiato

The first visible red light-emitting diode was invented by Nick Holonyak in 1962, but LED lighting technology took several decades to develop, before exploding in recent years. Just a decade ago, LED streetlamps were rare. By 2019, more than half of U.S. streetlights were LEDs, and that number is predicted to top 90 percent by 2030. Similar uptake has occurred around the world, even in developing countries, where inexpensive Chinese-made LED fixtures are increasingly common.

This rapid global migration to LEDs represents a shift in the fundamental physics of how we illuminate our world. From oil lamps and candles to gas lamps, early examples of artificial light at night relied on a burning wick, an incredibly inefficient way to create light. An incandescent bulb is effectively a heater that happens to produce light as a by-product, so it squanders nearly all of its energy as heat.

By contrast, LEDs use semiconductors to convert electricity into light. Through this process of electroluminescence, LEDs use up to 90 percent less energy than incandescent bulbs do, which has enabled municipalities to realize an immediate energy savings of 50 percent or more. This fact alone has fueled the technology’s worldwide adoption.

But LEDs aren’t just more efficient and less expensive. The use of solid-state technology gives the lights an extraordinary life-span, often measured in decades rather than years. This significantly lowers the maintenance costs, as city workers spend far fewer hours replacing broken or burned-out lights. Even more striking, by manipulating the properties of the semiconductor material, engineers can dictate the precise color and intensity of the output, something that gives LEDs incredible versatility. For a lighting designer like Thorp, LEDs offer countless possibilities.

Digital control for smarter lighting

Wandering from Trafalgar Square along the edge of St. James’s Park, Thorp and I find ourselves near Westminster Bridge, one of nine city bridges that in 2021 were part of the Illuminated River project, meant to make the Thames more beautiful at night. Each bridge now features a new LED lighting scheme that moves and changes color and intensity to create a coordinated work of art. But Thorp is frustrated that the project did nothing to correct the often glary lighting on the riverbanks. “Why don’t you pay the money to correct all of this bad lighting instead of adding new lighting?” he says. LED technology, he points out, has the potential to fix that problem.

The Illuminated River artwork for Blackfriars Bridge uses a color scheme that closely complements the red pillar supports that remain from the original Blackfriars Railway Bridge.

Luigi Avantaggiato

In fact, this may be the most meaningful potential of LEDs: the ability for a community to control when, where, at what levels, and in which colors its lights shine. A public space like Trafalgar Square could be lit more brightly during rush hour, then dimmed as the night progresses, the lights not only connected to one another but to the surrounding streetlights and commercial lights. Anywhere in the world, LED streetlights could be programmed to rise and fall in brightness depending on the time of night or time of year. They could even be turned off during bird migrations, to reduce the number of birds that are disoriented by the lights and ultimately killed in collisions with reflective and illuminated windows.

Up to now, LED public lighting has largely not been part of any comprehensive plan to curtail and control nighttime illumination. Most LED installations have simply replaced older, inefficient “dumb” electric lighting with newer “dumb” LEDs and thus made light pollution worse. The main reason? Because LED lighting is cheaper, we tend to use more of it—a literally shining example of the Jevons paradox. Even as awareness of light pollution grows, we aren’t yet taking advantage of LED technology’s full potential.

The good news is that we could start tonight. At DarkSky International, the world’s foremost organization fighting light pollution, CEO and executive director Ruskin Hartley tells me the organization has five principles for responsible outdoor lighting: It should be useful, targeted, low level, controlled, and warm-colored. “They’re enabled because of the capabilities of LEDs,” Hartley says.

The technology to control LEDs will be part of the solution. In the olden days of the analog era, a streetlight was either on or off. To change a lighting schedule, you had to physically rewire a circuit. Today, the Digital Addressable Lighting Interface (DALI) protocol turns each luminaire into part of a network, with its own digital address and a driver that reports to a central server. With DALI, the lighting is managed through software rather than physical switches.

Unfortunately, most LED streetlights have been deployed without this technology because it costs more. But Paul Drosihn, general manager of the DALI Alliance, says that using such controls makes the LEDs much easier to maintain. Before the new digital protocol, it took an average of nearly three visits to identify, diagnose, and repair a defective luminaire. “Now it’s one,” Drosihn says. “Saving the cost of sending two guys on a cherry picker to replace those [lights] is immeasurable. What I just described to you is pretty much all the utilities need to know.”

The intricate cast-iron understructure of Westminster Bridge glows in vibrant green and teal light as part of the Illuminated River public art project, a color palette selected to echo the green benches of the nearby House of Commons.

Luigi Avantaggiato

What’s more, DALI allows the tuning of the lights’ spectrum so that they become warmer and less disruptive as the night progresses. Digitally connected, full-spectrum luminaires allow cities to transform the nocturnal experience—saving money, increasing health and safety, and creating a warmer and more appealing atmosphere at night.

This digital intelligence is equally transformative for the “bleed lighting” that spills from building interiors, Drosihn says. “You don’t think of night lighting as coming from inside buildings, but it does,” he says. “Particularly in the States, you drive through any major city and all the lights are on, on every floor of every high-rise, even if no one is home.”

Already, the use of digital controls for interior lighting has become commonplace in some European cities, Drosihn says. By integrating DALI with occupancy sensors and building-management systems that monitor HVAC, electrical systems, and security networks, a skyscraper can become a dynamic participant in the urban environment—dropping a floor’s interior lights to zero the moment the last person leaves. As a result, electronic controls combined with LEDs can act like a dimmer switch for a city’s entire skyline.

White light blights the night

With all the possibilities from LED technology, why are our nights too often lit with harsh and clinical light, casting glare and creating shadows, disrupting human and ecological health, erasing the stars from our skies? The answer starts with the color of LEDs. At first glance, an LED streetlight looks like a collection of small white bulbs, but it’s not. To produce a light we perceive as white, most manufacturers coat a blue semiconductor core with a yellow phosphor material that absorbs a portion of that high-energy blue light. The problem is that this “white” light is still heavily blue, which is exactly the color no species has evolved to expect at night.

And because blue light is the second most energetic part of the visible spectrum (violet is the most), it doesn’t just illuminate our streets and invade our homes. Blue light also scatters in the atmosphere more easily than any other color, which helps to create the hazy, illuminated fog known as sky glow over every city of any size.

“Cooler” colored LEDs in the 4,000- to 6,500-kelvin range offer the most lumens at the lowest cost, so most early adopters installed these blue-rich white lights. The good news is that LED technology has continued to advance, and a growing number of communities are choosing warmer-colored streetlights that have less blue. (Phoenix, for example, converted 100,000 streetlamps to 2,700 K LEDs in 2020.) And, of course, light pollution isn’t just a result of LEDs. Older lighting technology also adds to the glare—bright white metal-halide lights, especially—and cities are loath to replace something that isn’t yet broken.

But our main failure isn’t a technical one. It’s that we have yet to revise our thinking about lighting at night. We use LED technology just as we did the old sources of light. As a result, we have largely offset the gains that were promised in terms of reducing energy consumption and carbon emissions by making light pollution worse, and have so far let an incredible opportunity go unrealized.

Can the City of Light do it right?

Across the Channel in Paris, the failure to realize the potential of LEDs feels even more palpable. Unlike London, which suffered heavily from German bombs, the lovely 19th-century Paris that Baron Haussmann created largely escaped destruction in World War II. To nearly 50 million annual tourists, the beautiful uniformity of the architecture is instantly recognizable. But the City of Light’s nocturnal atmosphere is also part of the draw, and extensive attention has been given to relighting its buildings and monuments. When I wander into the Cour Carrée in the Louvre, for example, I’m stunned by rows of amber LEDs that together create a warm glow along the palace facades. When I see the Eiffel Tower, first from a distance walking along the Seine and then up close, I find myself staring as I would at a campfire, the structure’s metalwork amber-lit with more than 336 high-pressure sodium bulbs.

Still, the city’s night lighting is far from perfect. With millions of residents, thousands of stores and restaurants, and 300,000 streetlights, the city overall is among the world’s brightest. Even at the base of the Tower, bright white LED lamps illuminate the African émigrés selling cheap berets and Eiffel Tower trinkets. And the city has been replacing its old sodium streetlights with new LEDs, swapping the warm yellow tones for which the city has long been known for bright white lamps no one wants to look at.

Street vendors display souvenirs at the foot of the Eiffel Tower. Their merchandise is lit by harsh white LED systems, which starkly contrast with the warm golden sodium-vapor light illuminating the tower above.

Luigi Avantaggiato

Nonetheless, the potential is here. In 2019, France introduced a nationwide law to reduce levels of light pollution, setting rules about both public lighting (preventing light from being projected above the horizontal) and private lighting such as stores, which are required to turn off their exterior and shop window lights after 1 a.m. In addition, an increasing number of French communities dim or turn off municipal lights after midnight to save energy and reduce carbon emissions. Although light pollution worldwide continues to increase by nearly 10 percent per year, France has managed to reduce its overall level. Chloé Beaudet, a researcher at Université Paris-Saclay, documented local light-reduction measures and found people generally agreed with the notion of dimming or turning off the lights, mainly for energy savings and ecological concerns.

“What I find is that people living in urban areas, they accept this kind of policy,” she tells me. “They’re like, okay, I don’t really use public space at night as a pedestrian, so what’s the point of having lights on?” For her, a key takeaway is that one lighting level does not fit all areas. “I think there is really a need for policy that is differentiated according to the neighborhood.”

In another positive development, the country has been minimizing artificial light to create ecological corridors designed to protect nocturnal species such as birds, bats, and insects. These corridors are connected and dark, mitigating the disruption to the 30 percent of vertebrates and more than 60 percent of invertebrates that are nocturnal. Even for city dwellers, this trame noire (“dark infrastructure”) helps to raise awareness of why controlling light pollution is important for life on Earth. Nationwide laws to control light pollution, the ability to light different parts of a city differently, dark corridors to protect biodiversity—these are exactly the kind of changes made possible with LEDs.

The iconic I.M. Pei Pyramid glows softly at the center of the Cour Napoléon at the Louvre Museum, its warm LED illumination flowing through the geometric glass-and-metal structure with a symmetrical framing of the surrounding historic pavilions against the night sky.

Luigi Avantaggiato

That’s not all. Almost until 1920, astronomers at the Paris Observatory were still gazing at the Milky Way. That’s impossible nowadays, but it could happen again. Despite the bright white LED streetlights now lining so many Paris streets, networks of LEDs using controls could lower lighting levels enough each night, so that the Milky Way could once again be visible over the French capital. And in the process, Paris could become the City of Light in ways that would set an example for other parts of the world.

New lighting demands new thinking

“I think we should aspire to have cities that see the stars,” Simon Thorp says when I mention this view of Paris. “You just need everything to be coordinated.”

Nearing the end of our London walk, having turned from the river and back up toward the Strand, Thorp brings me down narrow Carting Lane behind the Savoy Hotel, to where a gas fixture tops a thick lamppost, an original from 1870. A small plaque reads, “The last remaining sewer gas destructor lamp in the city of Westminster.” Thorp explains that the thick pole hides a tube that allowed methane from the sewers to get burned off at the mantle. “An early example of renewable energy,” he jokes.

The fire-orange flame is pleasing to the eye. But even here, on a narrow lane with no vehicle traffic, in a touristy area of the city, the flame is overwhelmed by a nearby, unshielded LED security light. Thorp shakes his head. “It’s stunning that someone could put in a light like that and think, ‘Great, nice job.’”

Here is the crux of contemporary artificial lighting at night. We know how to light well, and LEDs give us the ability to do so. But while our technology is 21st century, too often our thinking about light and darkness, safety and security, is stuck in the past. We could be doing so much more with this technology than we are. We could relight our nights in ways that would not only reduce energy and maintenance costs but also bring a slew of benefits, including healthier nights for humans, safer skies for nocturnal creatures, and a restoration of the stars.

In 2026, the tale of these two cities and their artificial light at night is that of a brilliant technology that we’ve engineered but haven’t yet learned to master. In short, we have yet to change the way we think about artificial light at night and to use it more thoughtfully and carefully—as we might, as one hopes we will.

This article appears in the August 2026 print issue as “The Wrong Way To Light a City.”

The stroke of a pen in Utah set off a solar chain reaction across the United States. Last March, the Western state legalized plug-in photovoltaic: solar panels small enough they can plug into a typical household outlet, helping power the house. Dozens of states followed suit shortly thereafter. Balcony solar, as the tech has become known since it could be deployed on the balcony of an apartment building, is now legal in states such as Colorado and Virginia. By July 2026, balcony solar bills had passed one or both houses of the legislatures states including New York, New Jersey, and California.

The U.S. embrace of this technology happened so fast that legalization has raced ahead of regulations needed to make sure it works safely. No panels meet newly created certification standards, though one microinverter announced last week does. The country still must solve a suite of legal and technical problems, said Craig Morris, the CEO of the German plug-in solar trade association Bundesverband Steckersolar. “If you get the law,” he said, “then your work begins.”

Morris knows the growing pains because Germany is where balcony solar came of age. In the 2010s, tinkerers realized they could use newly available microinverters, from large solar arrays, to send AC power from a single, affordable panel to a household plug. Balcony solar took off in popularity there as a clean and affordable energy solution after the 2022 Russian invasion of Ukraine sent natural gas prices soaring. Now, Germans can buy plug-in panels at Aldi or Ikea, and the country has more than 2 gigawatts of balcony solar deployed.

In December 2025, Germany finalized a regulatory standard to ensure these devices could safely send electricity back into a home power outlet and even the grid. Germany’s balcony solar law forbids net metering, in which grid operators pay customers who return electricity to the grid, because it creates so much uncertainty for grid managers. Morris’s organization got German firefighters to agree the technology isn’t dangerous. German law also protects renters whose landlords don’t want them to mount solar panels for aesthetic reasons. Property owners need a legitimate reason to oppose a resident’s request, such as necessary repairs to the balcony.

Coming to America

Ken Boyce watched all this from afar. Boyce is vice president of principal engineering at UL Solutions, the firm that creates testing and certification standards for a wide variety of electrical technologies, which now includes balcony solar. The speed of U.S. adoption of balcony solar caught him by surprise. “That Utah legislation passed and we said, “Oh, how about that?” Soon after, Boyce and a cadre of engineers got to work. By the end of 2025, UL Solutions had developed a basic framework for UL 3700, its attempt at a U.S. testing and certification standard for balcony solar.

The standard addresses numerous concerns about the safety of plug-in PV. The simplest problem is that household wiring simply wasn’t designed to handle power flowing into the outlet from a plug. Unlike plugs on ordinary appliances, a solar panel’s plug can be electrically conductive with the device unplugged, which may surprise unwary customers. Plug-in panels inject power into the home electrical system downstream of circuit breakers and other overcurrent protections, making those safeguards blind to the extra load. Electricity flowing backward through the GFCI (ground fault circuit interrupter), the electrical safety device built into power outlets, could cause GFCIs to fail. “There’s this kind of insidious aspect to it,” Boyce said, “and now you’ve bypassed that protection that’s required to protect consumers from electric-shock hazards.”

All of these factors make a plug-in solar panel much different from household appliances, such as a toaster or refrigerator, says Nadav Enbar, a program manager at the nonprofit Electric Power Research Institute (EPRI). Nevertheless, he says it’s crucial that regulators treat the balcony solar panels like an appliance. Its ability to plug in and just work—without the owner needing agreement from a utility, permits, or an electrical upgrade—is central to the technology’s mass appeal and its ability to get solar into so many more homes.

Making Balcony Solar Safe to Plug and Play

So, UL3700 addresses those dangers. In addition to specific requirements such as the thickness of insulation, it also requires manufacturers to account for other known risks–for example, by using wiring methodologies that lend additional overcurrent protection or by using GFCIs built to withstand bidirectional current. Plug-in solar must also power down in the case of a local blackout. This addresses one of the chief concerns cited by power utilities: that plug-in PV, were it to send power onto the grid during an outage, poses a danger to linemen.

How plug-in PV manufacturers satisfy those rules is up to them. But because UL3700 and balcony solar panels are so new, no panels have achieved the standard so far. Enbar notes that the UL standard is a high bar to clear, and, in fact, some of its requirements may not be solvable at this moment. For example, the bidirectional GFCI disconnect is not yet commercially available.

Balcony solar is momentarily caught in limbo: with one recent exception, the systems now available, and going online in states like Utah, are either not certified or cite some other electrical certification that wasn’t written for plug-in PV, according to EPRI.

The last piece of the puzzle is transparency. David Eisenhauer, a representative of the power utility SoCal Edison, told IEEE Spectrum that while Edison supports its customers gaining access to plug-in solar, “it’s really important that customers notify us before they start to think about or install plug-in or balcony solar. That’s going to help us ensure that they’re installing certified equipment, help us track connections so that we can balance and operate the grid.”

This may be easier said than done: EPRI’s research shows that even in industry leader Germany, unregistered balcony solar panels outnumber registered panels two to one. Some customers simply don’t want to do the extra homework to register a purchase, while others, Morris says, might not want to publicize their plug-in PV or let landlords know about it. Given the likely rise of unregistered “guerilla” solar, plug-in PV just has to work safely, every time, no matter how many people set up a solar panel on their balcony or in their backyard.

This story was updated on 21 July 2026 to reflect the fact that a microinverter announced during the story’s reporting does meet UL 3700. Thanks to eagle-eyed reader Stephen Mayer for pointing this out. It was updated again on 24 July 2026 to correct UL Systems to UL Solutions. We apologize for the error.

Data center developers and hyperscalers are experimenting with 800 volt direct current (800 VDC) inside their largest data centers. It enables them to pack more compute power in much smaller spaces to run the latest AI applications; 800 VDC also reduces waste heat from electric wires, lowers cable weight, and eliminates equipment needed in multiple AC to DC to AC conversions.

The Large Load Working Group (LLWG) of the Electric Reliability Council of Texas (ERCOT) is evaluating how to accommodate several 800 VDC facility designs. Data center power infrastructure provider Dimaag, for example, presented in April a way to protect the grid from AI’s massive load variations, which can switch from almost nothing to hundreds of megawatts and back again several times per second. DiMaag’s system also enables data centers to stay connected to the grid, or “ride through,” during short drops in voltage. This ability is known as Low Voltage Ride Through (LVRT).

“Grid infrastructure wasn’t built for the large load oscillations from AI data centers and large load disconnections due to voltage dips,” says Sadha Kameswaran, vice president of business development at Dimaag.ai.

Dimaag’s solution comprises batteries and control software that work with devices that switch electricity from AC to DC called rectifiers. This system, located between the grid and an AI data center, isolates DC load fluctuations from the grid and delivers LVRT support that can respond to demand shifts in real time at scale. Further, it lowers the number of AC to DC conversions required. Hyperscale data center developers are now evaluating this approach, Kameswaran says.

A power system study conducted by Electric Power Engineers (EPE) on behalf of Dimaag evaluated the technology in a simulated data center environment with regard to load smoothing, LVRT compliance, provision of backup power, and demand response. EPE concluded that this approach was an “effective solution for addressing the power quality and stability challenges inherent in modern data center operations.” The Dimaag module was found to be effective in buffering extreme DC-side power fluctuations and delivering LVRT response.

“Voltage ride through is key to maintaining balance between power generation and load,” said Woody Rickerson, COO of ERCOT during a panel at the Data Center World conference.

Power Electronics Alternatives

Companies are developing other ways of helping large loads integrate into the grid. The National Laboratory of the Rockies (NLR), for example, has tested ON.energy’s AI Uninterruptible Power Supply against ERCOT’s large electronic load (LEL) ride-through requirements. Another alternative from Ramboll acts as a shock absorber for the grid, helping utilities and grid operators to add more renewable energy sources while lowering risk, preventing outages, raising resilience, and lowering development costs.

One of Ramboll’s innovations is to address reactive power, a component of electricity that does not perform useful work but is essential in maintaining electrical and magnetic fields and controlling voltage levels. Ramboll have developed a Static Synchronous Compensator (STATCOM) that adds more controls than traditional STATCOMs that provide damping capabilities to detect and neutralize any voltage oscillations by absorbing energy from the oscillations and converting it into useable power.

Protecting ratepayers and the grid

This work to address data center load variability comes at a time of mounting public and governmental pressure. The Governor of Texas just ordered the Public Utilities Commission (PUC) and ERCOT to safeguard residential and small business ratepayers from added costs due to the expansion of AI data centers and to require that data centers fund any new electric infrastructure their operations require.

That was followed by the PUC approving ERCOT’s proposal on how to connect large electricity users such as AI data centers while protecting the reliability of the grid via provisions for LVRT and load smoothing. As well as incurring the costs for additional substations, transmission, and power electronics equipment for their new facilities, large load customers are encouraged to agree to curtail power usage at times of local transmission constraints. This comes at a time when ERCOT has 438 GW of large load interconnection requests, almost all from AI data centers.

“Texas is experiencing an energy transformation unlike anything we have seen before,” said ERCOT President and CEO Pablo Vegas in a press release. “This new process represents a fundamental shift in how ERCOT manages the significant growth of large load interconnection, providing a structured, transparent path forward that protects reliability for Texans while supporting the state’s continued economic growth.”

AI versus grid pace

Nvidia, AI hyperscale developers, and their supply chain partners are pressing ahead with their plans for 800 VDC data centers. Nvidia envisions that 800 VDC facilities will begin appearing in 2027 to support its forthcoming GPU design. However, these organizations are moving at a pace that is far in advance of the power industry.

ERCOT is known as one of the most progressive grid operators in the nation. Texas has more solar energy, wind power, and battery energy storage systems (BESS) than any other state, but it is far from ready for 800 VDC. The LLWG continues to evaluate 800 VDC.

For now, ERCOT continues to review a variety of 800 VDC, but no decisions are imminent on the preferred approach.

“There are a lot of solutions out there if you are listening for them, as help can come from many areas,” said Rickerson.

This article was updated on 17 July 2026 to add several paragraphs in the opening section inadvertently omitted from publication.

On the nights after Hurricane Maria ravaged Puerto Rico’s power grid in 2017, former Puerto Rican energy regulator Javier Rúa-Jovet remembers watching the sky warp along the horizon as thousands of fossil fuel-powered generators spewed emissions into the atmosphere. The “whole society” was running on this carbon-intensive backup power at the time, says Rúa-Jovet. Now, nearly a decade later, at least one of Puerto Rico’s microgrids is getting a clean upgrade.

On the small island of Vieques, 10 miles east of mainland Puerto Rico, a team of Cornell University researchers is deploying a first-of-its-kind clean hydrogen-enabled microgrid on a local farm. The project will include a solar-plus-battery system that will provide electricity for on-site hydrogen production. The hydrogen will then be compressed and stored in on-site gas cylinders for later use in fuel cells that can power the island’s essential services during grid outages.

The architecture builds on existing hydrogen-based microgrids, like a 293-megawatt-hour (MWh) one installed in California’s rural wine country in August 2025 by the utility Pacific Gas and Electric (PG&E). That system runs on batteries and hydrogen fuel cells, but doesn’t include on-site solar power, and involves trucking in the hydrogen rather than producing it there.

Vieques’s system, meanwhile, will use an on-site, solar-powered electrolyzer to produce hydrogen that can then be used in fuel cells. The hydrogen part of the microgrid can provide power when the solar array can’t—such as during the periods of low solar output that are common following storms. The plan is to use the system to power essentials like a health clinic, refrigeration, and drinking water pumps.

If the strategy works in Vieques, the idea is to apply it to other communities, says Cornell’s Héctor Abruña, the Puerto Rican researcher leading the project. “It’s eminently deployable just about anywhere, and so we make a point that this solution should be scalable and particularly good for isolated communities—which are almost always also forgotten,” Abruña says.

While the economics of hydrogen production have historically rendered the technology unviable in most cases, a community like Vieques is one specific instance where the costs might just balance out.

Puerto Rico Tests Hydrogen Microgrid

Backup power generation has long been a part of Puerto Rico’s culture. Storms and a legacy of disinvestment in the territory’s grid infrastructure have led to frequent blackouts that leave residents without electricity for days at a time. This has forced residents to turn to gasoline or propane-fired generators—and increasingly to solar-plus-storage.

Vieques, a community of around 8,000, receives power from Puerto Rico’s grid via undersea cable from the main island and does not have its own source of baseload power generation. This leaves the community particularly vulnerable to outages. When storms roll through, days of cloud cover often reduce solar output from the island’s existing microgrid, forcing residents to rely on diesel generators to power basic services, including water and refrigeration for food and medicines.

The microgrid’s batteries can keep the community’s essential services running for a few days without sunshine, but hydrogen fuel cells would extend that up to 10 days, Abruña says. In early 2027, the team plans to deploy a Nel Hydrogen electrolyzer to produce hydrogen. During outages, the farm’s owners will be able to move the fuel cells around the island to where they’re needed for critical services, providing up to 2.5 megawatt-hours of additional power. (When the island is not experiencing outages, the owners of the farm, La Finca de Hamberto, use some of the solar and battery power to keep food from spoiling in refrigerated containers.)

To prepare the microgrid to power the electrolyzer sufficiently, Abruña’s team is planning to double the island’s installed solar capacity from 50 to 100 kilowatts and scale up its battery storage. When the sun is shining, the electrolyzer will run on solar-plus-storage to build up a reservoir of clean hydrogen ahead of hurricane season.

“If your power’s out for more than a few hours, and your battery runs out of power, then you can switch over to a fuel cell and run off of all that stored hydrogen,” says Kathy Ayers, senior vice president for research and development at Nel Hydrogen and a member of the scientific advisory board for Abruña’s lab at Cornell.

Despite hydrogen’s high startup costs, Cornell’s researchers are confident that Vieques’s unique situation makes the economics feasible. Diesel is pricey on Vieques due to the 1920 Jones Act requirements mandating that goods shipped between U.S. ports are transported on U.S.-made ships manned by U.S. crew. Making the hydrogen on-site eliminates these transport costs. Over the microgrid’s 20-year lifetime, hydrogen installation and maintenance costs will be less than the cost of using diesel generators during the same timeframe, estimates Cornell’s Paul Mutolo, a strategic advisor to the microgrid project.

Hydrogen is also cheaper than adding more batteries onto the island’s existing microgrid. Most batteries scale in specific increments, making them less efficient in terms of physical space. “For hydrogen, you have the tanks, which are completely separate from the fuel cell. You don’t have to scale up the fuel cell to get more energy. All you do is scale up the tanks and add more tank volume,” Mutolo says. The hydrogen setup becomes a cost-competitive alternative to batteries as grid outages extend beyond a few hours, Mutolo and Ayers say.

Keeping costs low is a priority in Vieques. Power prices across Puerto Rico are among the highest in the U.S., with residents paying 28 to 29 cents per kilowatt-hour, according to Rúa-Jovet, who is now chief policy officer at the Solar and Energy Storage Association of Puerto Rico. And those prices could increase: On 1 July 2026, residential customers saw their monthly fixed charge jump from US $4 to $8, and it will double again to $16 next year, per the Puerto Rico Energy Bureau’s recent rate case ruling. Small commercial customers are seeing similar increases.

The kilowatt-hour prices on Vieques are higher than other parts of Puerto Rico because the island relies on power from the territory’s mainland via the undersea cable. Abruña’s goal is to get electricity prices down to 15 to 16 cents per kilowatt-hour for a 50 percent reduction from the state-run utility prices.

Still, the upfront costs of setting up a microgrid could make it challenging to replicate elsewhere, even if the costs eventually level out over time. The Vieques project is supported by settlement funds from Volkswagen’s 2019 class-action lawsuit, and the Cornell team is looking for funding to procure the necessary components to enable hydrogen production, storage, and fuel cells.

U.S. Dabbles in Hydrogen Backup Power

Several U.S. national laboratories have been working to prove the viability of hydrogen-enabled microgrids for years. In November 2024, the National Laboratory of the Rockies launched a demonstration project on the lab’s Arvada, Colorado, campus with Southern California Gas Co. and GKN Hydrogen. Then, in March 2026, the U.S. Army’s Construction Engineering Research Laboratory (CERL) installed a hydrogen nanogrid after a year-long demonstration at the White Sands Missile Range in New Mexico.

In small-town Calistoga, California, the utility PG&E unveiled a hydrogen-enabled microgrid last August alongside battery storage company Energy Vault and hydrogen maker Plug Power. Like Vieques, the community of Calistoga, population 5,200, is vulnerable to grid outages due to wildfires in the region that force preemptive power shutoffs for safety.

PG&E chose Calistoga as a host because historically the community has had one of the highest frequencies of power shutoffs in the utility’s service area. In April 2023, the California Public Utilities Commission (CPUC) allocated US $46.3 million for the development and commissioning of the hydrogen microgrid over a decade. PG&E has only built one such hydrogen microgrid so far because the utility hasn’t yet identified additional locations that meet the CPUC’s requirements for vulnerability, says Renata Bakousseva, a manager for PG&E’s design and microgrid delivery team.

So far, Calistoga hasn’t had a reason to turn to its microgrid for a real-life event, but the system underwent a fresh round of performance testing in April, Bakousseva says.

Soon, the battery system supporting Calistoga’s microgrid will be able to export power to PG&E’s grid outside of planned power shutoffs. The installation is awaiting a change to its interconnection that will allow this, says Craig Horne, Energy Vault’s CTO. That will help alleviate some of the installation’s cost burden, he says.

Despite the upfront cost, Horne echoes what Abruña’s team is trying to prove in Vieques: That in the long term, hydrogen can be more efficient than adding batteries. “Today, the cost of hydrogen is expensive, but you know that cost is coming down, as is the cost of fuel cells,” Horne says. “So all those things really are showing that this is a superior solution.”

Spent batteries from older electric vehicles are starting to pile up, but a handful of companies are repurposing them in a novel way: as energy storage for the grid.

These batteries are retired from EVs after their capacity falls to 70 to 80 percent; that’s too low to satisfy drivers, but leaves enough juice for many stationary-storage applications. With some clever engineering, hundreds of retired battery packs can be assembled into megawatt-scale energy-storage systems.

June was a busy month for this nascent industry in the United States. On 4 June, Los Angeles–based B2U Storage Solutions announced it would repurpose used batteries from Waymo robotaxis for stationary grid storage. Two weeks later, Carson City, Nev.–based Redwood Materials unveiled a plan to combine about 100 used batteries from General Motors vehicles to provide 1.5 megawatts to one of the automaker’s plants in Michigan. And a week after that, Vancouver-based Moment Energy completed construction of what it says is the world’s largest EV battery-repurposing facility.

The efforts address two significant needs in the energy industry: Grid operators need somewhere to store valuable excess energy from renewables, and the auto industry needs somewhere for old EV batteries to land. Second-life battery companies could satisfy both needs, if they can get the engineering worked out.

Second-Life EV Batteries Back Up the Grid

The first mass-market all-electric vehicles arrived in the early 2010s, and those batteries are starting to retire in increasingly large numbers. In 2012, 130,000 EVs were sold globally, and that’s since skyrocketed to more than 20 million in 2025.

Sending spent batteries to landfills wastes valuable materials and years of remaining electrochemical life. Recycling—recovering metals such as lithium, nickel, cobalt, and copper to manufacture new batteries—is one option, but researchers have long argued that many batteries could provide additional value in less demanding applications, like second-life stationary storage, before being dismantled.

Stationary-storage batteries cycle more predictably and can tolerate slower charging and discharging rates, and a lot less current runs through them. Second-life uses include commercial backup power, microgrids, EV charging infrastructure, and increasingly, grid-scale energy storage, such as storing excess renewable energy for later use and reducing demand during expensive peak hours.

Over the last decade, the second-life EV-battery industry has been trying to move beyond small pilot projects and demonstrations into commercial deployment. But progress was slowed by a lack of retired batteries, labor-intensive testing and engineering, and uncertain economics that often made recycling or investing in new batteries more attractive.

In the last few years, diagnostic tools and testing procedures for evaluating battery health have improved, allowing companies to identify suitable batteries faster, more accurately, and at lower cost. On top of that, demand for grid-scale energy storage is soaring, driven mainly by the need to bank excess wind and solar power. This combination of forces has prompted companies to invest big in battery energy storage systems (BESS) from second-life EV batteries.

This confidence “was not there three or four years ago,” says Simona Onori, a professor of energy science and engineering at Stanford University. Much of the confidence stems from field data showing that the remaining capacity of retired lithium-ion EV batteries is sufficient for other uses. “Batteries retired with 70 to 80 percent of their original capacity...can be excellent candidates for grid storage,” she says.

That’s true as long as the batteries show no signs of abnormal degradation, have low internal resistance (meaning the battery can still charge and discharge efficiently without generating excessive heat), and limited cell-to-cell variability (so that individual cells within the battery pack perform similarly rather than some degrading much faster than others).

How Is EV Battery Health Tested?

Turning a car battery into a grid asset is more complex than just giving it a stationary address. Different chemistries, architectures, and usage histories leave batteries in varying states of health. They have to be tested and analyzed to make sure they’re fit for repurposing, then must be wired together so they can be managed as one system.

One of the first steps is determining a battery’s remaining capacity. A battery’s age “by itself is a weak signal,” of its capacity, says Anurag Srivastava, a professor of electrical engineering at West Virginia University. “Two battery packs that are the same age can have very different states of health depending on their depth of discharge history, fast-charging frequency, and temperature exposure in their EV life,” he says.

To evaluate the health of a battery, B2U follows UL 1974, the standard for safely repurposing EV batteries. It directs engineers to look at remaining capacity, internal resistance, consistency among cells, and signs of damage or abnormal degradation.

“We inspect the battery itself, making sure visually, structurally, and mechanically it has integrity,” says Freeman Hall, B2U’s president, who walked IEEE Spectrum through the company’s process. Company researchers then establish communication with the battery management system (BMS), an onboard computer that records operating data like voltage, temperature, charging history, and fault conditions.

The most surefire way to know a battery’s state of health is through direct capacity testing, which runs batteries through controlled charge-discharge cycles to see how much charge they can still hold. The problem with this method is that it’s slow; a full cycle can take hours, which gets unwieldy and expensive when dealing with thousands of batteries.

B2U CEO Freeman Hall [left] and technician Donte Terrell inspect battery cabinets at a facility in Lancaster, Calif.Awarded Goods

However, engineers can combine BMS data with rapid tests such as electrochemical impedance spectroscopy, which sends a small alternating electrical signal through a battery and measures how it responds. Advances in data analytics and machine learning let researchers build models that can estimate battery health faster and more consistently.

Batteries Combine for Grid-Scale Energy Storage

After testing and weeding out incoming batteries, the next step is to integrate them. A stationary storage system combines dozens or hundreds of battery packs that need to work together as one. That means grouping batteries with similar chemistries and performance characteristics, connecting them electrically, and integrating them with battery-management software, cooling systems, and other controls that monitor their operation.

B2U uses a matrix architecture, where batteries of the same chemistry are wired together in parallel strings inside shipping-container-size enclosures called cabinets. Each cabinet has voltage and temperature limits tailored to the chemistry of the batteries it contains. B2U sets the high-end voltage threshold below the optimal operating voltage level for safety. “The weaker batteries will hit their upper voltage limits earlier, and then they can disconnect and not inhibit the stronger batteries from reaching their higher voltage limit,” says Hall, adding that “there’s a lot of software required to do that well.”

Once the system is brought online, a new challenge arises: every battery needs to be monitored continuously in real time for performance and safety. “We’re monitoring voltage and temperature not just at the pack level, but at the cell level,” Hall says. The matrix architecture makes it easy to disconnect a battery if there are any issues; with over 500 batteries in a system, one or a few coming offline doesn’t affect the performance of the site. “We make sure everything is healthy, then reconnect it the next time those batteries come through at the right voltage level,” Hall says.

At its facility in Lancaster, Calif., B2U receives retired EV battery packs, evaluates their condition, and reconfigures suitable batteries into containerized energy storage systems for deployment on regional power grids. The company’s operating projects in California and Texas use hundreds of second-life battery packs to provide grid-scale storage.

Will EV Batteries Get Repurposed or Recycled?

While the supply of second-life EV batteries is sure to grow in the coming years, so will the quality of the competition. The cost of new batteries is falling, and second-life systems will have to deliver enough savings to offset the expense of testing and integrating them. And some types of second-life batteries are more valuable if they’re recycled. Recent research by Onori and her colleagues suggests that iron-based lithium iron phosphate batteries are often better candidates for repurposing, while batteries containing larger amounts of nickel and cobalt may generate more value through recycling.

“I do expect a much larger wave of batteries to become available over the next several years as more EVs reach the end of their automotive life,” says Onori. “At that point, whether a battery is repurposed or recycled will come down to its condition and the economics.”

For now, second-life batteries are a small part of the storage market—Srivastava estimates they account for just 2 to 3 percent of deployed capacity. However, he believes they could “become 20 to 25 percent of deployed capacity in the next decade, if recycling stays expensive and diagnostics keep improving.”

This article is brought to you by Melbourne Convention Bureau (MCB) supported by Business Events Australia.

As artificial intelligence accelerates global demand for compute, a parallel constraint is emerging with equal urgency: energy.

From hyperscale data centers to electrified industries, AI is driving a step change in electricity demand. This is not a future challenge, it is a present, system-level issue requiring coordinated action across energy, infrastructure, and engineering disciplines.

Around the world, the question is no longer whether AI will scale, but whether energy systems can scale with it.

Melbourne, Australia is moving beyond participation to become a globally connected leader helping define how these challenges are addressed.

A national challenge with global implications

Australia’s ambition to lead in artificial intelligence is sharpening focus on the infrastructure required to support it. Data centers are projected to account for up to 11 percent of the nation’s electricity consumption by 2035, placing increasing pressure on generation, transmission, and system reliability.

At the same time, insight from the IEEE Power and Energy Society (PES) highlights that meeting energy demand from AI and digital infrastructure is one of the most significant challenges facing engineers over the next decade.

The implications are clear. In addition to computing challenges, AI poses major energy systems challenges.

“As artificial intelligence continues to scale globally, the challenge is no longer just computational power, it is the energy systems required to support it” —Professor Thas (Ampalavanapillai) Nirmalathas, University of Melbourne

Why Melbourne is leading on the global stage

Victoria has developed one of the most advanced and integrated energy ecosystems in Australia and globally, spanning renewable generation, battery storage, grid modernization, and advanced materials.

What distinguishes Melbourne globally is how these capabilities are connected and applied at system scale.

The city brings together world class engineering research, a rapidly evolving clean energy sector, advanced digital infrastructure, and strong alignment between government, industry, and academia. This convergence is critical in the AI era, where energy, networks and computing systems must be designed together.

Victoria’s coordinated investment across these areas is positioning Melbourne not only as a national leader, but also as a reference point in the global energy system transformation.

Engineering the systems behind the AI economy

The challenge ahead is that generating more power won’t be enough, as engineers need to design systems that respond dynamically to new patterns of demand.

Three priorities are emerging globally:

• Aligning data center development with grid capacity and renewable supply
• Embedding flexibility through storage, demand response, and system optimization
• Balancing digital growth with decarbonization and long-term reliability

Addressing these priorities requires engineering expertise to be embedded earlier in planning ensuring energy systems, digital infrastructure, and policy are designed in parallel.

Melbourne’s strength lies in its ability to integrate this expertise across research, infrastructure, and real-world application.

Melbourne Connect is a University of Melbourne–led innovation precinct, supported by government and industry, designed to bring together research, business and policy to deliver real-world solutions.Atlantic Group

Research leadership shaping global solutions

At the centre of this capability is the University of Melbourne, where interdisciplinary research is advancing the systems required to support AI driven energy demand.

Through the Melbourne Energy Institute, for example, researchers are examining how energy technologies interact across entire systems from generation and networks through to end use.

“As artificial intelligence continues to scale globally, the challenge is no longer just computational power, it is the energy systems required to support it,” says Professor Thas (Ampalavanapillai) Nirmalathas, Dean of the Faculty of Engineering and Information Technology at the University of Melbourne.

“This is driving a new level of convergence between digital infrastructure and power systems engineering, where integrated, system level thinking is essential.”

Converging energy, networks and AI

Melbourne’s leadership is further strengthened by world-class interdisciplinary facilities such as the Smart Grid Lab in the Department of Electrical and Electronic Engineering, which enables real-time simulation of power systems, allowing engineers to test how solar, batteries, electric vehicles and other distributed resources interact within future grids. This supports the design of more resilient, efficient energy systems before they are deployed at scale.

Melbourne’s Smart Grid Lab in the Department of Electrical and Electronic Engineering enables real-time simulation of power systems. University of Melbourne

These capabilities will become increasingly important as data centers are integrated into the grid.

“AI driven demand is not only increasing computing requirements, but also placing new pressures on underlying energy systems,” says Glen Farivar, Senior Lecturer in Power Electronics at the University of Melbourne. “Designing these systems together is essential to achieving both performance and sustainability outcomes.”

This reflects a critical shift. Future infrastructure must be co designed across energy and digital systems, not developed in isolation.

A living ecosystem delivering real-world outcomes

Victoria’s broader energy ecosystem is translating these insights into practice.

Investment in renewable energy, grid infrastructure and storage is enabling higher levels of clean energy while maintaining reliability. Battery deployment is supporting the flexibility needed to manage both renewable variability and growing AI-driven demand.

At its core, Melbourne offers an integrated environment where research, industry and government collaborate to solve complex system challenges.

Why engineering collaboration matters

Solving the energy demands of the AI era cannot be achieved in isolation.

It requires engineers, researchers, utilities, and policymakers to work together earlier and more often. More than ever, engineering collaboration is a critical enabler of future energy systems.

Environments that bring together global expertise are becoming essential to how solutions are designed and delivered.

“Developing future energy systems that are affordable, sustainable, and resilient is a truly grand challenge” —Professor Pierluigi Mancarella, University of Melbourne

In this context, the University of Melbourne is co-leading, alongside Johns Hopkins University and Imperial College London, one of only seven Global Centres in Climate Change and Clean Energy. Through the Electric Power Innovation for a Carbon Free Society (EPICS) Centre, the University is also the Australian technical lead in advancing future energy systems, with EPICS the only Global Centre focused on future energy infrastructure.

The new Electric Power Innovation for a Carbon-Free Society (EPICS) Centre will address challenges in clean energy production and storage.University of Melbourne

“Developing future energy systems that are affordable, sustainable, and resilient is a truly grand challenge,” says Professor Pierluigi Mancarella, Chair Professor of Electrical Power Systems at the University of Melbourne and Australian director and international co-director of EPICS.

“As electricity grids are increasingly becoming the backbone of future energy systems, optimizing their interactions with other sectors, including AI and digitalization, and fostering interdisciplinary and international collaborations are essential,” he adds.

Global conferences as part of the solution

International conferences are increasingly recognized as critical platforms for advancing engineering solutions at scale. Melbourne’s ability to convene global expertise is central to its leadership.

In 2027, the city will host the IEEE PES Generation Transmission and Distribution (GTD) Asia 2027 Conference and Exposition, bringing together engineers, utilities, researchers and policymakers from across the world to address the challenges shaping the future of power systems.

IEEE PES GTD Asia 2027 Melbourne Committee (left to right): Dr. Mehdi Ghazavi Dozein (Monash University), Dr. Glen Farivar & Professor Pierluigi Mancarella (University of Melbourne) , Dr. Mohammad Mohammadi (Australian Energy Market Operator (AEMO)).MCB

“Melbourne offers a unique environment where world-class research, industry capability and policy leadership come together,” notes the IEEE PES GTD Asia 2027 Local Organising Committee, which includes Professor Pierluigi Mancarella and Dr. Glen Farivar from the University of Melbourne, as well as Dr. Mehdi Ghazavi Dozein of Monash University and Dr. Mohammad Mohammadi of the Australian Energy Market Operator.

“Hosting this event creates an opportunity to advance global collaboration on the systems and technologies required to deliver the energy transition at scale.”

These forums enable knowledge exchange, standards development and interdisciplinary collaboration, accelerating progress on complex engineering challenges.

Attendees view a digital installation at AIME 2025 at Melbourne Connect.MCB

Why Melbourne, and why now

As AI, electrification and digital infrastructure converge, the future of global energy systems will depend on the ability of engineers to collaborate and innovate at scale.

Melbourne provides a proven platform for that collaboration, combining world-class research, a rapidly evolving energy ecosystem, and the infrastructure to connect global expertise.

Melbourne Convention Bureau, IEEE Communications Society, and University of Melbourne Representatives.University of Melbourne

For IEEE members, hosting a conference in Melbourne is more than an event decision.

It is an opportunity to engage with a globally connected engineering community and contribute directly to solving one of the most significant challenges facing the profession today.

Through the support of the Melbourne Convention Bureau, professionals can access tailored, free support to bid for and deliver international conferences, bringing global expertise together in a city actively shaping the future of energy systems.

To explore hosting your next conference in Melbourne, contact the Melbourne Convention Bureau at info@melbournecb.com.

Off-grid coastal communities that rely on weather-dependent solar and expensive diesel to meet their energy needs may soon have a new addition to their power production portfolio: tidal energy. Researchers from SRI International, a research institute in Menlo Park, Calif., are testing a buoyant kite that flies underwater to determine whether it can squeeze enough power from intermittent, often slow-moving tidal currents to provide clean energy to small coastal communities.

The rise and fall of Earth’s tides draws water through straits and channels each day with impeccable predictability, driving currents that can carry significant kinetic energy. And marine energy is power dense: It provides more power per swept area, compared to a similar wind field. “Underwater kites can be smaller because water is so much denser,” says Evan Variano, professor of civil and environmental engineering at UC Berkeley.

Hydrodynamic lift causes a wing-shaped kite to “fly” in moving water in a similar manner to a kite in the air on a windy day. These underwater kites can autonomously fly figure-of-eight paths with the help of modern sensors and onboard robotics or electronics, allowing them to swoop across tidal currents much faster than the water itself is moving. Couple that movement to a generator, and the system can harvest useful amounts of electricity, even close to slack tide—the tidal cycle’s slowest flows. That’s something other strategies for harvesting power, like a fixed seafloor turbine placed in a channel, can’t do.

Kites are beginning to find their wings. The furthest along has installed a megawatt-scale demo system that delivers electricity from a sheltered bay to an electrical grid. Others, aiming for kilowatt-scale systems, are starting to show what they can do in real-world settings. They’re measuring efficiency in different conditions and preparing pilot-trials of their gear in remote communities.

Tidal Kite Power Generators

In one kite design, a generator sits at the base of the tether, either on a boat or an anchored mooring. The pull from the kite as the tide moves it extends the tether and spins the generator, producing power. Then, like a giant yo-yo, the generator reels it back in using a fraction of that power, thanks to the much lower force on the kite while it’s in its most streamlined position.

The Manta project from SRI International adds a special twist. The Manta kite uses a twisted-string tether rather than a static tether to spin the generator without needing high-ratio gearing. That makes for a less-expensive system that’s simpler to maintain, more compact, and more efficient.

But any underwater kite faces the same fundamental challenge, says Chris Vermillion, a mechanical engineering professor at the University of Michigan. “It must be continuously flying. That periodic motion requires substantial control.”

That means that kites require an autopilot that constantly adjusts flight path in response to generator load. It’s an intricate dance: There are six degrees of freedom on the kite itself, and three more on the tether. The kite’s pose in the water is stabilized via a rudder, an elevator, and aileron-like blades that control pitch. The wing’s angle of attack relative to the current is established to achieve a balance between speed and force on the tether. And the kite must maintain speed while the generator’s load changes. “Control algorithms are where rubber meets road,” says Variano.

Manta Kite Tidal Energy Performance

In 2025, Variano and his colleagues tested a model kite system with a 1-meter wingspan. Attached to a boat in the San Francisco Bay, it could indeed spin a small generator rated up to 2 kilowatts, and drew over 100 watts at the bay’s typical peak tidal flow of 1.5 meters per second. “The power we generate depends on the flow we have and the control algorithm we’re using,” says Variano. The team has now begun testing a pilot-scale system with a 2-m wingspan and a 15-meter-long tether, which simulations indicate should be capable of generating 1 kW of average power over a full tidal cycle, including flow speeds below 1 meter per second.

Each San Francisco Bay test uses a small fishing vessel, anchored to ensure the only flow the kite experiences is from tidal currents. The researchers place the kite in the water, start the autopilot, and watch the kite sweep back and forth like a wakeboarder. Each sweep takes the kite away from the generator, untwisting the tether. “We see the generator gathering power, pausing, expending a little energy to reload the string, then repeat,” says Variano.

Across hundreds of sweeps, the researchers tracked the power generated during different parts of a tidal cycle. They conducted additional tests while towing the kite to create a steady 1 m/s flow. In July and August, they’ll run longer trials, capturing a full tidal cycle at once. Then they’ll crunch the numbers to tease out how efficiently Manta generates power.

The team will complete their analysis near the end of 2026. For a sense of the numbers, however, Variano points to Manta’s contract with the U.S. Department of Energy’s hydrokinetic technology program, which stipulates a production of 1 kW at less than US $0.09 per kilowatt-hour. “If we were far off, we wouldn’t still be trying,” he says.

Minesto’s underwater kite carries an onboard turbine that harvests tidal energy for local grids.Minesto

Minesto’s Megawatt Tidal Power Kite

One kilowatt might sound small. The largest kite produced by Minesto, located near Gothenburg, Sweden, has a 12-m wingspan and drives a 1.2-megawatt generator to deliver electricity to the grid in the Faroe Islands in the Atlantic Ocean. Minesto’s design, unlike Manta, carries its generator on the wing itself, and an undersea cable transmits power to shore.

“When you study tidal flows of the world’s oceans, you realize low to medium flows are in abundance,” says Martin Edlund, the CEO of Minesto.

Edlund posits that harvesting energy from a mean peak flow down to 1.5 m/s has economic potential. Minesto has succeeded in that “we’re grid connected and we attract capital,” he adds. “But calling us commercially ‘successful’ is a bit ahead of ourselves.”

For off-grid homes, however, kilowatt-scale energy meets basic needs. Many remote communities in Alaska rely on diesel generators to supplement wind and solar. The team behind Manta plans to test the system in Alaska’s Alexander Archipelago with the Metlakatla Indian Community, using traditional knowledge they’ve shared of the narrow straits that funnel the tides to create strong flows. “We’re small, portable, and could provide clean power to people in these remote coastlines,” says Variano.

BladeRunner Energy, based in Bend, Ore., is already testing a tethered system in Alaska—but using river currents and a “kite” that’s more akin to a corkscrew than a wing. The 2-meter-diameter rotor generates 5 kW of power in flows between 1.8 and 2 m/s, as demonstrated at the University of Alaska’s Tanana River hydrokinetic test site. If tests using a new 11-kW generator go well, BladeRunner will ship out to the native village of Napaimute in western Alaska. “We want to integrate with the Napaimute microgrid system and replace 100 percent of the diesel they consume,” says Moriel Arango, the co-founder and CEO.

Compared to other renewables like wind and solar, tidal energy offers consistency and predictability year-round. But in contrast to those more mature technologies, marine energy (which also includes wave energy systems) is at a much earlier stage.

But even if the technology still has a ways to go, tidal kites are well-positioned to succeed, according to the University of Michigan’s Vermillion. “If you compare underwater kites to other marine technologies, I don’t see them being behind the eight ball at all,” he says. “I don’t buy the idea that kites are nascent and high risk.”

This article appears in the September 2026 print issue as “Underwater Kites Harvest Power From Tides.”

Next month, when summer heat and winter cold near their peak in each of Earth’s hemispheres, grid operators will face their highest electricity demands of the year. Space heating and cooling make up about 50 percent of all energy end uses worldwide, putting enormous strain on grids and sometimes forcing utilities to use more expensive, polluting plants.

But it doesn’t have to be that way. To take some of the load off during peak demand, manufacturers are pairing batteries with residential air conditioners and heat pumps. The batteries charge when power is plentiful and discharge, running the heating or cooling system, when the grid is strained.

A company offering this service in New York City is the startup Every Electric. The company distributes briefcase-size, 2-kilowatt-hour portable power banks that connect to plug-in air conditioners. It then uses software to aggregate those units into a virtual power plant (VPP).

The strategy of reducing power demand at key times of the day, known as demand response, enables individual electricity customers to partake in good grid citizenship. It also turns what have been traditionally energy-guzzling machines into grid assets.

Every Electric’s program makes “watts drop off the face of the Earth” during peak grid use, says Andrew Wang, co-founder and CEO of the company. “The air conditioner plugs into the power bank, the power bank plugs into the wall, and then as a company, we essentially manage whether the electrons come from the wall or come from the power bank to keep the air conditioner powered while helping reduce strain on the grid,” Wang says.

Residents can request a power bank for each plug-in air conditioner in their home at no cost or for a refundable deposit. Every Electric further incentivizes participation in the program by giving back to residents a portion of its earnings, which it draws from partnering with New York’s electric utility, Con Edison. Wang says the total yearly rebate for a home amounts to a typical July or August electricity bill.

Over 10,000 of Every Electric’s batteries have been requested by New York City residents, but only about 1,000 have been shipped, resulting in a waitlist, says Wang. Last month, he told the Associated Press that his company planned on shipping about 2 megawatts worth of power banks this summer. But now he says the company has already exceeded that figure. Fulfilling all requests this summer would mean Every Electric would provide over 20 MW of flexibility to the grid—enough energy to power a few thousand homes.

“I think people really feel the air conditioning hit their bills,” Wang says of the response to the program so far.

Air conditioners become grid assets

Heating and cooling systems that respond to grid needs are just one element of VPPs—a term that describes the aggregation of small power contributions or load shedding from the grid in a decentralized way. VPPs might include residential solar panels, battery storage systems, grid-friendly EV chargers, or a combination of all of these and other elements.

Heating and air conditioning have been incorporated into VPP programs previously, but those usually involved using smart thermostats to throttle heating or cooling during peak hours. That works to curb energy use but can mean sacrificing comfort.

“Air conditioning has been used for a couple of decades that way, in that it has been used as a demand response resource,” says Ron Domitrovic, senior program manager at the nonprofit energy research institute EPRI. “When there’s a grid need through some sort of dispatch…air conditioners were asked or told to turn off or to cycle,” he says. An air-conditioning program that integrates battery storage could be more appealing, because residents wouldn’t be subject to unwanted temperature shifts.

Programs like Every Electric’s also enable demand response at a hyperlocal level. Wang says Con Edison can tell the company if a particular neighborhood needs more energy freed up, and Every Electric can then instruct the power banks in that area to switch on and temporarily cut off air-conditioning units from the grid. The company’s current power banks can power a plug-in air conditioner for up to four hours, depending on how efficient the unit is.

Every Electric is actively planning pilot programs with new utilities outside of New York City, especially in New Jersey, Massachusetts, and other areas of the Northeast where plug-in air conditioning units are dominant.

Carrier builds battery-enabled heat pumps

In other regions of the United States, central air conditioning is much more commonplace. In response, the global heating, ventilation, and air-conditioning (HVAC) provider Carrier, based in Palm Beach Gardens, Fla., last year launched a pilot program of residential heat pumps with batteries built directly into the units. Carrier’s machines, which provide both heating and cooling, can switch between grid power and stored energy, depending on demand.

The Carrier pilot began in 50 homes but has now expanded to a number of cities across the U.S. in partnership with several utility companies. Domitrovic, whose institute is collaborating with Carrier on the program, declined to disclose the locations of the trials or the preliminary results.

“What I can say is that [the test units are in] a cross-section of climates, both cold and warm, in order to gauge effectiveness and usefulness,” Domitrovic says. The trials collected data this past winter and are currently in the process of collecting summer data. Carrier’s innovation in HVAC made news a couple of years ago when the company tested cold-climate heat pumps that aimed to perform at 100 percent capacity at -15 °C.

Wang says Every Electric is not in the business of creating new units with built-in hardware like Carrier’s. He says his company’s value is instead in its ability to tap into both new and legacy air-conditioning units, some up to 20 years old. Portable batteries also offer flexibility for city living and renters.

On the downside, plug-in air-conditioning units don’t use as much power as heat pumps and only operate during warm months, so the positive impact of turning them into demand response machines is less than it is with heat pumps. Plus, adding a 50-pound battery to your home adds bulk to smaller spaces.

“I think what’s valuable for us is understanding, fundamentally, how do people use electricity, and how does having the ability to shift that create value, both for the grid and for them—the people who pay for their electricity,” Wang says.

The United States’ top energy regulator has ordered grid operators to either overhaul how they connect data centers to the grid, or justify their current strategy. The highly anticipated set of directives, issued 18 June by the U.S. Federal Energy Regulatory Commission (FERC) targets six regional transmission grid operators that together supply a majority of national electricity demand.

FERC’s move aims to alleviate the backlog of data centers waiting to connect to power grids while safeguarding consumers from electricity price hikes. Both have become problems in some regions of the U.S., and major political issues.

The challenge is that connecting data centers and other large electricity users often requires significant grid planning and investment in new power generation and transmission. This takes time and money, resulting in years-long connection queues for data centers and the potential for utilities to pass on those costs to other customers. With demand for data centers escalating, and electricity prices already climbing for other reasons, energy analysts and the public have made clear that something must change.

“FERC is telling regional operators that the old methods aren’t good enough anymore for customers with larger, more concentrated loads that seek faster connections,” says Costa Samaras, an engineering and energy policy researcher at Carnegie Mellon University and former energy policy staffer at the White House Office of Science and Technology Policy.

“FERC’s orders appear to deftly thread the needle between the needs of large load customers (especially fast-emerging data centers) for better defined pathways to faster grid interconnection and speed to power, on the one hand, and growing public concerns about the potential for large load growth to increase electricity costs for everyone else on the other,” wrote Jeff Dennis of Washington, D.C., consultancy Coefficient Policy Experts in an analysis of the orders.

Data center industry group the Data Center Coalition “thanks the Federal Energy Regulatory Commission for its continued focus on speeding large load interconnections,” says Aaron Tinjum, vice president of energy at the Coalition.

Chipmaker Nvidia, which supplies most major American data centers, called the FERC orders “a pro-growth, pro-affordability, and pro-reliability policy. … FERC has taken an important step forward, and Nvidia welcomes this leadership.” And the Edison Electric Institute, which represents investor-owned utility companies, told Politico that the commission was advancing shared goals.

What’s still unclear is whether FERC’s approach is bold enough to bring about the change it’s seeking.

FERC reforms data center policy

FERC’s orders give grid operators two ambitious deadlines. First, they must report within 30 days how they ensure adequate power generation for existing and anticipated demand. Then, within 60 days, they must either explain how they can meet large load connection requests within their existing rules and prices, or else change the way they do things.

For those who choose the latter, FERC suggested specific reforms tailored to each grid operator. One reform would ensure that grid operators make agreements with new large load customers to recover the cost of interconnections. The hope is that this would help prevent costs from getting passed elsewhere. Many large data center operators have tried to assuage public concerns about electricity prices by promising to pay for such upgrades, but those promises are not legally binding.

The transparency required in these cost recovery agreements is helpful, Samaras says. “It’s essential that policymakers ask, ‘Who pays and who benefits?’ If a network upgrade is built to accommodate a data center, the consumer should know how much that’s going to cost,” he says.

However, the directives may not go far enough in requiring transparency around the cost of new data center connections, and may be watered down in practice, says Ari Peskoe, electricity policy researcher at Harvard Law School. “I think when it’s implemented it will be less transparent than FERC would like,” he says.

Even if operators have to report the costs of connecting a new data center, many states, which have historically led transmission grid management, have no way of preventing residential customers from paying the bill. Congress has tried to give FERC more authority over transmission facility permitting with limited success.

FERC also affirmed the value of several new technologies that better utilize grid power that’s already available. For example, the commission says grid operators should examine tools that maximize the current and optimize power routes in transmission lines. These measures could allow grid operators to offer more power in the medium term, while they build enough capacity to meet future demand.

And FERC recognized that power-flexible data centers—a concept enabled by a suite of novel technologies—could speed interconnection because they can be responsive to grid needs. Some emerging data centers can move compute workloads to different locations along transmission routes that have more power available, for example. It’s in the grid operator’s interest to encourage that kind of user to participate in the grid, rather than install their own independent power sources and treat the grid only as emergency backup, Samaras says.

Faster data center grid connection

The directives come eight months after U.S. Secretary of Energy Chris Wright urged FERC to take more control over making sure AI data centers got connected to the grid faster. But rather than taking control, the commission’s new orders take a more flexible, tailored approach that allows grid operators and FERC to approach the problems in dialogue with each other.

Still, the commission didn’t shy away from addressing a wide range of complex issues in the orders, including attempting to correct a perverse incentive that has dogged the industry for years: speculative requests. Data center developers can shop around for a quote, both in terms of price and schedule, by requesting connection from multiple regional grids. Those requests are time-consuming and costly for grid operators to assess. The redundancies may also cause grid planners to overestimate demand.

So, to shift the incentive, FERC proposes that grid operators offer increasing amounts of planning information in phases, called escalating readiness, after data center builders are financially or otherwise more committed to a particular grid connection point. In other words, “they should wait until there’s more steel in the ground,” Samaras says.

Another measure to speed up the preparatory studies proposes that when a power plant operator and a large load customer of a similar size both apply for access to the grid, only one study of the impact of both players joining should be conducted, rather than sequential studies. “So long as they are electrically proximate, you can combine studies before connecting and it goes quicker,” Samaras says.

Other reforms include developing an efficient transmission service application process and accommodating large load customers who bring their own power, known as co-located or behind-the-meter generation.

If FERC is unsatisfied with any operator’s responses, it could initiate a slower process to make new rules, typically two to five years. Such rule-making is subject to more public comment and likelier to provoke legal challenges.

While data centers may dominate today’s political discussions, they will not be the only large, concentrated loads in the future, Samaras says. Grid operators must prepare for the next big wave of electrification, which will involve industry redesigning some factories to use electricity, residential consumers replacing gas heating and cooking with electric, and charging more electric vehicles. “These types of policies from FERC will hopefully pave the way for growth in electrification in those sectors, too,” Samaras says.

This story was updated on 24 June 2026 to include comments from the Coefficient Policy Experts and the Data Center Coalition.

By most accounts, the United States appears poised to fall woefully short of meeting new electricity demand over the next five years as data centers and domestic manufacturing proliferate.

Ian Magruder

Ian Magruder is the founder of Utilize Coalition and previously served as director of market mobilization at Rewiring America, an affordable electrification advocacy group.

Building new power plants and transmission lines may seem like the obvious solution, but there are other options, says Ian Magruder, founder of Utilize Coalition, a nonprofit based in Washington, D.C. The U.S. uses only about half of its grid capacity, and a lot more power could be tapped by deploying a spate of newly available technologies.

Backed by Google, Tesla, HVAC systems manufacturer Carrier, and several other companies, Utilize Coalition advocates for more thorough use of grid capacity through policy change and new technologies. Magruder spoke with IEEE Spectrum about those efforts.

Why does the United States use only half of its grid?

Ian Magruder: Most studies have found that average utilization rates are between 40 and 55 percent across different geographies. And the reason is that we’ve built our grid to meet peak demand. We have to ensure that on the hottest summer day or the coldest winter morning we have enough power. But in many parts of the country, we really only hit peak a few days a year, and it’s really only a few specific hours within those days.

It didn’t used to be this way. What’s changed?

Magruder: Over the last 20 years we’ve seen the gap between average use and peak use grow wider. There are a variety of reasons for that. Grid operators have become more conservative following major blackouts and reliability events. And with more variable-generation sources such as wind and solar, grid operators are building in more capacity. But this also presents us with an incredible opportunity to get more out of the grid using new technologies.

What technologies are being deployed to address the problem?

Magruder: Pairing battery storage with energy generation is a key part of this, as are other kinds of distributed energy resources, like managed [electric vehicle] charging and smart thermostats. I would also say that transmission technologies that safely maximize the current in power lines, increase conductivity, and optimize power routes all play a critical role here. And then there’s demand flexibility, which is when utility customers adapt their power use to accommodate the grid during peak hours. Some really good work is being done around flexible data centers.

Is grid underutilization also happening elsewhere in the world?

Magruder: It’s a global phenomenon, but it varies widely by country. European grids face similar dynamics as [those in] the U.S., and in some places utilization is even lower. But Australia and the United Kingdom are further ahead in measuring and managing utilization with new technologies.

What’s the downside to overbuilding our grids?

Magruder: Mainly cost. Electricity rates have gone up, and we [at Utilize Coalition] think it’s because utilization has gone down. A report that we released earlier this year shows that a 10 percent increase in grid utilization could save Americans over US $100 billion over the next decade.

A half century ago, a scrappy crew at the University of Massachusetts Amherst erected a wind turbine on Orchard Hill, the highest point on campus. It was a frugal production, cobbled together from the rear axle of a Ford truck, a donated generator and microcontroller, a steam pipe, and various handcrafted steel and fiberglass parts, including its 4.5-meter blades.

The team of UMass engineering grad students, faculty advisors, and one precocious undergrad built it to prove that wind energy could keep rural homes toasty in New England’s frigid winters, as a way of trimming U.S. oil dependence—a national imperative in the aftermath of the 1973–1974 energy crisis. To illustrate the point, they also assembled a modular home there on Orchard Hill, and outfitted it with heaters that would be powered by the turbine.

In 1975 and 1976, a crew from the University of Massachusetts Amherst designed and constructed the 25-kilowatt wind turbine that kick-started the U.S. wind industry. Sandy Butterfield

It worked—too well. “We had to open up the doors in the dead of winter. It was just too damn hot,” recalls Michael Edds, who designed the turbine’s electrical system and served as the project’s first resident engineer. Fittingly, they dubbed the turbine the “Wind Furnace.”

The turbine maxed out at 25 kilowatts—puny compared to modern machines that generate up to 26 megawatts, but more than most energy experts expected from wind technology in November 1976. Back then, wind power still conjured up images of quaint Dutch mills and creaky prairie water pumpers. Crafty engineers would soon show that wind power could be so much more. And it all began with the brilliant, commanding, and often polarizing UMass professor leading the Wind Furnace project: William Heronemus.

A retired U.S. Navy captain, Heronemus had joined the UMass faculty in 1967. He’d earned Bronze Stars for valor in World War II, designed and built nuclear submarines, and liaised with the British Royal Navy on the Polaris missile. UMass had recruited Heronemus to do ocean engineering, but the energy crisis and his growing misgivings about nuclear power shifted his attention to renewable energy.

Heronemus, photographed circa 1973, publicly advocated for the buildout of wind turbines, both onshore and off, at immense scale. Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

By 1972, Heronemus was advancing detailed designs to deploy wind turbines at immense scale. That year, at the Marine Technology Society’s annual gathering in Washington, D.C., he presented schemes for building thousands of them across the Great Plains as well as a vast grid of massive floating turbines transecting New England’s continental shelf. Wind power, he contended, could generate nearly a fifth of U.S. electricity needs by the year 2000. Never mind that the technology for such an enormous buildout had yet to be commercialized. Espousing grand schemes made Heronemus a quixotic figure.

He also vigorously attacked the commercialization of nuclear power, creating enemies within electric utilities and U.S. government agencies that saw nuclear technology as the future. They didn’t appreciate his claims that a cleaner energy future via wind was ready to be tapped, and that the push for nuclear power and its radiological risks was unnecessary. As author and energy analyst Peter Asmus put it in his 2000 book, Reaping the Wind: “William Heronemus was a dangerous man suggesting an audacious departure from the status quo.”

The UMass Amherst wind turbine generated most of the energy to heat a modular home through the cold, windy winters on Orchard Hill. Solar thermal panels provided some heat during windless periods. Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

What happened on Orchard Hill in 1976 marked Heronemus’s turn from provocateur to changemaker. The success of the experimental turbine set off waves of technological and industrial developments that forever changed the energy landscape. Within a few years, the students he trained and the entrepreneurs he inspired were building the world’s first modern wind farms and leading the Great California Wind Rush—the market that turned wind craft into an industry that’s still growing fast half a century later.

Globally, annual wind generation more than tripled between 2015 and 2025, according to data from Ember Energy, a think tank based in London. It will best nuclear’s global output by the end of this year, Ember predicts. And it all started with Heronemus, says Robert Thresher, longtime former director of wind research at the National Renewable Energy Laboratory (NREL) in Golden, Colo. (a U.S. Department of Energy lab rebranded late last year as the National Laboratory of the Rockies). “In my mind he was the father of the people that went out and really made the industry what it is today,” he says.

William Heronemus and the History of Wind Power

I got to know Captain Heronemus posthumously, interviewing his contemporaries and sifting through boxes delivered to the UMass Amherst archival research center’s 25th-floor reading room. During three visits there since 2023, I have discovered clues to his life, thinking, and research process amid the writings where he pitched his big ideas to the world. His papers include proposals to governments, utilities, and deep-pocketed philanthropists and investors, including Jane Fonda and Goldman-Sachs. Papers reveal the internationalism and commitment to service that took Heronemus on renewable-energy consulting trips to Pakistan, Cuba, Côte d’Ivoire, and beyond. Records show meetings with corporate powerhouses like Boeing and Grumman Aerospace and calls on politicians, including the senator and presidential hopeful Ted Kennedy. Postcards from former students exude gratitude.

Heronemus sits with a mock-up of a multirotor turbine in his cramped office in Marston Hall, UMass Amherst’s main engineering building. Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

I learned that Heronemus turned his attention from ocean engineering to energy a few years after arriving at UMass, when he saw the growing string of nuclear power plants going up along the Connecticut River, which flows past Amherst en route to Long Island Sound. The U.S. government had picked nuclear power as an antidote to the 1970s oil crises, and Northeast utilities had jumped in big. But Heronemus and other UMass engineers worried that the riverside reactors’ waste heat would threaten the river’s ecosystem and bounty.

The advent of cooling towers to blow off heat into the air addressed the thermal pollution concern but created another: water depletion. (Nuclear plants consume about 60 million gallons of water per day, per reactor, on average.) And Heronemus perceived other nuclear power liabilities, stemming from his experience with nuclear propulsion on Navy ships. As a design engineer and head of construction and repair for a shipyard, he valued the military’s zero-accident standard for reactors but also knew the high cost of adhering to it. He argued that building expanded versions of the Navy’s pressurized water reactors to power cities and factories couldn’t be both safe and economical.

In 1971, Heronemus designed an offshore turbine with three rotors, but the first big multirotor prototype wouldn’t be built for another four decades. Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

He predicted—accurately, as it turned out—that costs would rise sharply as the nuclear industry addressed safety and environmental concerns. “Each plant costs more than its predecessor. The shipyards involved with nuclear reactors came to that conclusion years ago,” he wrote in a 1973 research proposal. He also argued that the risks inherent in nuclear reactors and their radioactive waste were unnecessary given Earth’s abundant solar and wind energy resources. He broadcast those views wherever and whenever he could: before congressional committees, at U.S. Atomic Energy Commission hearings, at academic conferences, in media interviews, and even at Rotary Club luncheons.

At a 1973 licensing hearing for the proposed 820-MW Shoreham Nuclear Power Plant on Long Island, N.Y., for example, Heronemus called affordable nuclear energy a “myth.” He detailed, in its stead, a floating wind power system that could be moored off Long Island and sized to deliver more than four times as much electricity as the Shoreham plant. Each of the 640 floating platforms would carry six rotors and crank out up to 12 MW, some of which would power electrolyzers to generate hydrogen. The hydrogen would be fed to power plants or fuel cells to produce electricity when the wind wasn’t blowing. This seemingly futuristic idea drew on his Navy experience with water-splitting electrolyzers, which supplied the oxygen that enabled subs to remain submerged for months at a time, and NASA’s use of hydrogen fuel cells to power the Apollo missions.

More than five decades later, his vision for offshore wind power is big business. Floating platforms are now widely accepted as the future of offshore wind, as necessity pushes the industry to build in deeper waters. Testing began on the first floating electrolysis platforms in 2023, and multirotor turbine prototypes are in development in China, Norway and Scotland.

The UMass Amherst Wind Turbine Legacy

Photos in the UMass archives invariably capture Heronemus in jacket and tie, usually standing bolt straight. That commanding affect, plus his World War II veteran pedigree, Cold War engineering credentials, and his informed, pugnacious attacks made him a hard target for his adversaries in the nuclear establishment. He certainly wasn’t your typical antinuclear activist.

Wielding his Cold War engineering credentials and often dressed in a suit and tie, Heronemus fought hard against nuclear energy, arguing that wind was a far safer and cost-competitive resource.Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

But brutal candor in public settings probably won him as many enemies as friends. Consider his presentation at the IEEE Power and Energy Society’s 1974 winter meeting, where Heronemus suggested scrapping the utilities’ then nuclear-focused research arm, the Electric Power Research Institute. That stance no doubt created discomfort for the engineers in attendance who were involved in EPRI projects, or who aspired to be.

It’s hard to say whether Heronemus’s campaign slowed nuclear development. The industry was already struggling with cost overruns when, in 1979, a reactor at Three Mile Island in Pennsylvania partially melted down and slammed the brakes on further expansion.

What is certain is that Heronemus spurred investment in wind power. When he started talking up wind in the early ’70s, even fellow travelers in the fledgling renewable energy movement were writing it off. As future White House science advisor John Holdren opined in a 1971 Sierra Club book: “There are few places in the world where the wind is strong enough and steady enough to make harnessing it for the large-scale production of power at all interesting.”

Heronemus dreamed up networks of wind turbines over and along highways after driving down the Garden State Parkway to a conference in Cape May, New Jersey. Ellen Heronemus

Heronemus countered the naysayers by quickly forging expert consensus around wind power’s immense potential, playing a key role as the sole wind expert on a 1972 federal panel on renewable energy. That joint National Science Foundation–NASA panel concluded that, in fact, wind could meet up to 19 percent of projected U.S. power demand by the year 2000.

Congress listened, sort of. After most Persian Gulf states restricted oil shipments to the United States in 1973, congressional appropriators dedicated US $1.8 million to wind-power research and development for 1974—up from zero—and by 1976 it had bumped that to $22 million. (For comparison, Congress gave nuclear power $714 million in 1976.)

Heronemus’s vision for a massive highway wind-power scheme was inspired in part by the wind-power advocate Percy Thomas, who in the 1940s and 1950s “talked a lot about how fresh New Jersey winds are,” he told the New York Times in 1974. “I got to thinking about what Thomas had said and how wind energy could be captured there.” Ellen Heronemus

The bulk of the funding for wind power flowed to big aerospace firms and to NASA, financing an ultimately fruitless attempt to leap straight to megawatt-scale wind turbines. UMass struggled to grab a slice of the leftovers to pursue Heronemus’s offshore wind system. Professors and students who worked with Heronemus told me they felt they’d been blackballed as payback for his activism and antagonism.

UMass finally caught a funding break when Heronemus dialed back his ambitions and proposed the 25-kW unit for Orchard Hill. A $130,000 federal grant landed in early 1975, and $150,000 more the following year. It was a “trivial” sum, according to team member Sandy Butterfield, who would later become chief engineer for wind-turbine testing at NREL. “They gave us just enough to fail,” says Butterfield.

A crane erects the “Wind Furnace” in November 1976. Sandy Butterfield

But the project triumphed, resulting in Wind Furnace 1, or WF-1 (pronounced “woof one”). The young engineers behind it credit their success to the confidence, sense of mission, and structure that Heronemus gave them. The self-described “hippies” called Heronemus “the Captain” out of both affection and respect.

As team member Edds puts it: “What showed in his demeanor and his actions was discipline, and it sort of rubbed off on us. We didn’t always dress like the Captain, but we knew we had to be disciplined, to be prepared, and just do the job.”

From Helicopter Rotor to Wind Turbine

Team WF-1 got a quick start, thanks to earlier, privately financed work by a couple of doctoral students, including Forrest “Woody” Stoddard. Stoddard had been designing helicopter rotors for the U.S. Air Force when Heronemus invited him to come work on wind power in 1972. Stoddard set about adapting helicopter-rotor theory to the closely related wind rotors, and his aerodynamics modeling proved essential to the engineering of the entire machine.

Woody Stoddard [far right, in hat] designed the fiberglass blades with Ted Van Dusen. The team assembled the blades in a campus shop, and when it was time to squeegee epoxy from the blades, it was all hands on deck. Robert S. Cox Special Collections and University Archives Research Center/UMass Amherst Libraries

As WF-1’s de facto chief designer, Stoddard likely supported the team’s early choice to mimic a helicopter’s ability to “pitch” its blades. To fly forward, a helicopter continuously adjusts the lift created by each blade, turning the airfoil on its long axis to reduce lift as it swings past the front of the aircraft. Doing so tilts the nose down and moves the vehicle forward. In WF-1’s case, blades pitched to regulate torque, helping get the rotor spinning in low winds and then easing off to protect the machine in dangerously high winds.

Repurposing a truck axle to mechanically couple WF-1’s rotor and generator was one of several design elements borrowed from engineers at McGill University in Montreal. Production of WF-1’s fiberglass blades got started at UMass in 1974 under the direction of doctoral student Ted Van Dusen. A competitive rower, he had a side hustle making ultralight composite boats—a trade that had stalled his doctoral work at MIT but was an accelerant for WF-1.

The federal funds in 1975 allowed Heronemus to really spin up the project and recruit a squad of students to engineer the balance of WF-1’s components. They made good use of the UMass engineering machine shop and received guidance from faculty, including mechanical engineering professors Duane Cromack and Jon McGowan. But it was the dozen or so students who really cranked out the parts.

Most were master’s students, like Butterfield, who designed the blade-pitching mechanics. Edds, the team’s only electrical engineer, had come to UMass to learn ocean engineering, only to be diverted into handling WF-1’s generator. Louis Manfredi, another ocean engineering student, teamed up with master’s student Jim Sexton on the nacelle housing the generator and drivetrain. Fred Antoon adapted the truck axle. Brian Kuhn did drawings.

WF-1 contained a mechanism that pitched its blades to regulate torque in response to wind speed, a feature that became an industry standard.Sandy Butterfield

An 18-year-old freshman, Dan Handman, came aboard and soon made himself indispensable. When he approached Heronemus to introduce himself, Heronemus handed him three months’ worth of anemometer readings punched into recording paper, and told him to turn it into 15-minute averages. Figuring there had to be a more efficient method for analyzing wind speeds, Handman asked around and found a wind-averaging machine from an earlier student project. A month or so later, he’d installed it in a cabinet near Heronemus’s office and wired it to an anemometer on Orchard Hill.

Handman’s primary role on WF-1 was setting up its computerized control system, which tracked wind speed and sent commands to Butterfield’s pitch mechanism. The controls also tracked the generator’s speed and adjusted the current to its rotor windings, in accordance with calculations by Edds. Tweaking the current ensured that power demand from the electric heaters installed in the home below didn’t stop the rotor in weak winds.

Sandy Butterfield, part of the 1970s “UMass Mafia” team that built WF-1, became a wind-power entrepreneur and a top engineer at the National Renewable Energy Laboratory in Golden, Colo. Sandy Butterfield

The finished WF-1 really cranked up the heat, some of which was stored by heating water in tanks in the modular house’s basement, to be circulated through baseboards in windless periods. It turned out WF-1 was unusually efficient at capturing wind energy because its rotor could change speed with the wind, keeping the blades close to an aerodynamic optimum.

This varying rotor speed meant that the frequency of the electric power WF-1 produced also varied. Turbines linked to power lines must strive for the opposite—a steady output that synchronizes with the grid’s frequency—primarily 50 or 60 hertz. But it suited the home’s low-tech heating scheme just fine. (Electronic converters let today’s turbines have it all by ingesting a variable wave and outputting a new wave that’s synced to the grid.)

The Great California Wind Rush

In 1977, with WF-1’s success in hand, Heronemus projected that 3 million homes like the one on Orchard Hill could soon slash U.S. heating oil demand by 90 million barrels a year. That never happened, but an industry was born, starting with a Burlington, Mass. startup called US Windpower—the first “credible” U.S. turbine manufacturer, according to Thresher, who is now an emeritus researcher at the National Laboratory of the Rockies.

Belgian-made WindMaster turbines erected at Altamont Pass signaled the internationalism of the California wind rush. UMass team member Woody Stoddard conducted engineering analyses of many early designs deployed there.Bettman/Getty Images

Boston-area entrepreneurs Russell Wolfe and Stanley Charren launched US Windpower with Stoddard and Van Dusen after visiting Heronemus in 1974 and liking what they heard. They adapted WF-1’s design to make it suitable for grid-connected operation, building and breaking prototypes before erecting the world’s first grid-connected wind farm in 1980—20 turbines on a mountain in New Hampshire. California’s water authority placed an order for 100 MW of wind power, and in 1981 US Windpower began installing hundreds of turbines in Altamont Pass, east of San Francisco.

As more firms jumped to California, drawn by state government incentives, WF-1’s creators and the next cohort of UMass grads assumed important roles in the nascent market. Seven joined Energy Sciences, a startup cofounded by Butterfield. More joined U.S. Windpower. Stoddard left that company to start a consulting firm and ended up advising some of Denmark’s modern wind pioneers, which rapidly expanded thanks to the California market. Those early Danish firms made relatively simple, sturdy machines that subsequently scaled up and dominated globally for several decades — until China embraced wind power.

The California wind power boom peaked in 1986, after which energy prices collapsed and incentives faded. Most manufacturers were bankrupted by equipment failures and financial challenges, making the 1990s a tough time for wind power’s pioneers. Many UMass wind engineers, like Butterfield, joined Thresher’s operation at NREL, culling everything they could from the California experience.

“An entire generation of U.S. wind engineers got their graduate training, at least in part, using the Wind Furnace.”—Harold Wallace

There, Heronemus’s protégés became known as the “UMass Mafia.” Thresher says it attests to the crew’s impact: “There were others. But that UMass Mafia were really leaders in the field. I think that’s the heritage we got from Bill Heronemus. Those people were so impactful and the education they got [with Heronemus] was the key.” What Heronemus began at the university became the UMass Wind Energy Center, which has awarded over 300 graduate degrees.

WF-1 now rests in the Smithsonian Institution’s collections in Washington, D.C. It earned its place there, as Smithsonian’s only modern wind turbine, because it represents wind energy’s revival, according to Harold Wallace, Smithsonian’s curator for electricity collections. “An entire generation of U.S. wind engineers got their graduate training, at least in part, using the Wind Furnace,” he says.

Heronemus didn’t get to witness the production of the massive offshore machines that he foresaw. He lost his long fight with cancer in November 2002, at the age of 82, even as former students and family members were racing to patent his multirotor and floating turbine designs.

Had he lived longer, the Captain would almost certainly have railed against current U.S. energy policy. The U.S. government has never backed wind power as generously as he’d hoped. Wind supplied 10 percent of U.S. generation last year—that’s half the share in Europe—with offshore turbines providing only a tiny sliver. Federal support for wind power has been in a stop-go cycle since Ronald Reagan’s administration, and it’s hit a low again under President Donald Trump, who has vowed to stop wind power cold. As Trump boasted to oil executives in January: “We have not approved one windmill since I’ve been in office, and we’re going to keep it that way.”

Under Trump, stop-work orders have disrupted offshore projects from Massachusetts to Virginia, contributing to a nearly $600 million loss in 2025 for GE Vernova’s wind business. GE Vernova is the only major wind turbine manufacturer remaining in the United States, and it too can be traced back to Heronemus via a US Windpower patent.

In stark contrast, European and Asian countries have been going big on offshore wind and are now developing floating wind farms to push into deeper waters. China might be the one to finally conjure up Heronemus’s favored wind design: floating platforms bearing massive multirotor machines. In 2024, Zhongshan-based turbine maker Ming Yang Smart Energy Group deployed a two-rotor offshore prototype. The company says its next iteration will generate a whopping 50 MW—a twin-headed beast that would be the world’s most powerful wind machine.

That will be a bittersweet moment for the U.S. wind industry and Captain William Heronemus’s UMass Mafia, for whom such massive machines are a dream come true. Joanne Carroll, a retired member of the UMass Mafia, says she remembers the very moment, her freshman year, when Heronemus’s dream became hers. While he was lecturing in Introduction to Engineering about the hidden costs of coal-fired power, Heronemus walked to the window and said: “‘But out there there’s wind, and you can harvest that energy,’” Carroll recalled. “And I remember thinking: That’s what I want to do with my life.”

The author would like to give special thanks to UMass professor emeritus James Manwell for his assistance with this story.

Nuclear fusion reactors offer the hope of vast, clean energy from the same process that powers stars. But despite decades of research, a fusion reactor that can supply practical amounts of power has proven elusive. Now startup Commonwealth Fusion Systems has revealed in depth what it says is the most complex aspect of the reactor it is constructing—the way the reactor controls the plasma responsible for generating power.

The company says its findings support its vision—a reactor that can generate 1.1 gigawatts of fusion power and deliver 400 megawatts of net electricity to the grid. “That can power about 280,000 average American homes for a year, all using an amount of fuel you could deliver in a pickup truck,” says Brandon Sorbom, cofounder and chief science officer of Commonwealth Fusion Systems (CFS) in Devens, Mass.

The ARC (affordable, robust, compact) fusion reactor that CFS is developing is a tokamak. This is essentially a doughnut-shaped bottle that magnetically traps plasma at pressures and temperatures high enough to force atomic nuclei to fuse. A fraction of the mass of these atoms gets converted into energy. “We’re basically creating a miniature star,” Sorbom says.

High-Temperature Superconductor Magnets

The key innovation of the ARC reactor is the use of high-temperature superconductor (HTS) magnets instead of typical superconducting magnets, which require frigid temperatures near absolute zero to work. Although HTSs still require temperatures in the range of about 20 to 77 kelvins (-200 to -250 °C), the relative warmth in which they operate means they require dramatically less cooling equipment. This makes ARC significantly more compact and simple than previous fusion reactor designs, such as the International Thermonuclear Experimental Reactor (ITER).

RELATED: This Fusion Reactor Is Held Together With Tape

The fusion reactions generate neutrons, whose energy heats a continuously flowing loop of molten salt around the reactor’s magnetic bottle. This blanket of molten salt then heats a fluid to drive a turbine that generates electricity.

CFS researchers collaborated with scientists at MIT, Columbia, the Max Planck Institute for Plasma Physics and other institutions around the world to describe the scientific underpinnings of the ARC reactor. They detailed their research in five peer-reviewed studies published today in the Journal of Plasma Physics.

“We demonstrate that the ARC power plant has a solid foundation in physics,” Sorbom says. “The papers confirm that when we build the ARC fusion power plant, it will work.”

Roughly two-thirds of the 58 authors of the studies come from outside CFS. “These papers are not just the stamp of our validation, but that of the global fusion-science community,” Sorbom says. “And then they underwent peer review from more institutions for independent checks to make sure all our calculations were correct.”

Managing Plasma Disruptions in Tokamaks

The new studies detail how ARC will deal with a major challenge all fusion reactors face. Plasma disruptions occur when instabilities within the plasma flow lead it to spiral out of control and make contact with the reactor wall. These can not only inflict a great deal of damage—the plasma is 150 million °C and carries 12 million amperes of electrical current—but also extinguishes the plasma.

“Plasma physics is really hard,” Sorbom says. “It’s the most complicated part of the machine.”

In the new studies, the researchers describe methods for limiting the impacts of such disruptions, such as rapidly injecting massive amounts of gas into ARC as a cushion to keep the plasma from damaging the reactor. But they also have designed ARC to withstand one disruption per day and to restart the plasma within a minute without interrupting power output, Sorbom says.

“We designed ARC considering that even on the wrong side of all the uncertainties we still face, ARC will still work.” —Brandon Sorbom, Commonwealth Fusion Systems

“Even if the plasma is off, the molten salt doesn’t decrease dramatically in temperature immediately,” Sorbom says. The salt can therefore continue to supply heat for electricity generation until fusion restarts.

ARC will use deuterium and tritium, two hydrogen isotopes, as its fuel. Ultimately, ARC will breed more tritium for future use, as neutrons from the plasma striking the molten salt will transmute some of the lithium within the salt to the rare hydrogen isotope. The tritium can then serve as fuel for the reactor, or help seed other power plants, “enabling the rapid scaling of this technology,” Sorbom says.

ARC Fusion Reactor Lifetime and Maintenance

The projected lifetime of ARC is 25 to 30 years. Its longevity depends on how long the superconducting magnets can survive damage from neutrons escaping the salt blanket. If the researchers want a fusion plant with a longer life, “we can make it slightly larger to put in more shielding between the blanket and the magnets,” Sorbom says.

The new studies explain that the reactor’s plasma fuel is held within a vacuum vessel that erodes over time. “It lasts somewhere between one to two years before it has to be replaced,” Sorbom says.

CFS has designed the vacuum vessel to be swapped out as quickly as possible. The reactor can be opened up and the salt blanket drained away so the company can cut up an old vacuum vessel and place in a new one.

ARC will have to shut down during such times, but Sorbom notes other kinds of power plants often experience outages every few years for routine maintenance as well. The startup hopes ARC will have short maintenance cycles, “a couple of months at most,” he says. The company is now collaborating with a grid operator to plan around such maintenance.

Sorbom adds that between replacements, research and development could design better vacuum vessels. “Every time we replace it, we can upgrade it,” he says. “The first may last a year and a half. The next year, two years. Then after that, 2.5 years.”

All in all, these new studies suggest ARC is going to work, Sorbom says. “We designed ARC considering that even on the wrong side of all the uncertainties we still face, ARC will still work.”

Currently the startup is building a smaller prototype of ARC called Sparc. “Sparc is now more than 75 percent complete,” Sorbom says. The company aims for Sparc to generate its first plasma in 2027, and aims for ARC to begin putting power on the grid in Virginia in the early 2030s.

As thorough as the new studies are, the ARC reactor is still evolving, Sorbom adds. “We will be able to use what we learn from Sparc to make final design tweaks on ARC.”

This story was updated on 12 June to correct some details of CFS’s technology and timeframe related to the ARC reactor.

This article appears in the August 2026 print issue as “Research Validates Commercial Fusion-Reactor Design.”

This sponsored article is brought to you by Black & Veatch.

The biggest challenge facing utilities today isn’t what it seems. It’s not demand, even as load growth accelerates. It’s not extreme weather, even as “major events” become routine. It’s not cybersecurity, even as connections expand across the grid.

The real challenge is this: Distribution systems were designed for a different reality.

Long gone are the days of predictable demand, one-way power flow and isolated disruptions. At Black & Veatch, we see that leading utilities are no longer debating whether to modernize. They’re deciding how quickly they can do it, and how to do it at scale.

Across grid modernization programs globally, three truths consistently emerge. They define what it takes to prepare the distribution system for what’s next:

1. Outage response is not a resilience strategy

Resilience is being redefined in real time. A strategy centered on mobilizing crews and restoring service as quickly as possible is reactive, and increasingly insufficient.

Resilience has to shift upstream into integrated system design. That starts with hardening. Stronger poles, undergrounding and structural upgrades all have a role, particularly in high-risk corridors. We’re also seeing meaningful gains from how the network is configured and how quickly it can respond without waiting on manual intervention.

This is where distribution automation programs can change outcomes. Strategically placed reclosers, automated switches and fault indicators help contain disruptions before they spread. When combined with feeder reconfiguration and updated protection strategies, distribution automation investments allow utilities to set more aggressive recovery targets and achieve measurable reductions in outage duration and customer impact.

2. Future-readiness depends on DERs at scale

Forecasting is less and less reliable. Only 19 percent of utilities report strong confidence in their ability to predict future load growth, according to the Black & Veatch 2025 Electric Report. Distributed Energy Resources (DERs) like solar, storage, EVs and behind-the-meter generation are exciting solutions; but they fundamentally change how the system operates. Power is no longer just delivered. It’s injected, stored and redirected in ways the system was never designed to manage.

At scale, these challenges show up quickly — particularly on feeders where distributed generation is approaching or exceeding hosting capacity. Protection coordination becomes more difficult when fault current comes from multiple directions. Voltage becomes less predictable as generation fluctuates throughout the day. And planning models must now account for highly variable, location-specific behavior.

Distribution modernization is fundamentally changing how the system is designed and operated so it can absorb disruption, manage bi-directional flows and respond in real time.

Adapting to bi-directional power flow requires more than incremental updates. Leading utilities are responding by building flexibility into the system, moving beyond static assumptions toward dynamic hosting capacity and interconnection studies, planning that incorporates DER, EV adoption and localized load growth, and infrastructure aligned with the communications and control needed to manage it.

3. The edge must be intelligent, visible and secure

As system stress and complexity increase, utilities need far greater visibility and control over the network. Historically, utilities relied on customer calls, Supervisory Control and Data Acquisition (SCADA) at the substation level and field crews to understand what was happening on the system. That model doesn’t hold up. You can’t effectively manage a system you can’t see. Plus, the most critical events are increasingly happening beyond the substation — on feeders, laterals, and at the edge where DER and customer behavior are interacting with the grid.

Grid-edge technologies have become essential. Sensors, Advanced Metering Infrastructure (AMI) and automated switching provide the raw data and control needed to move from reactive to proactive operations. In more advanced deployments, utilities are creating centralized control environments that allow operators to see and manage the distribution system in near real time. That capability is enabled by:

• Advanced communications networks to form the backbone of real-time grid visibility
• Distribution Management System (DMS) and Outage Management System (OMS) to enable faster, more coordinated system response
• Analytics, AI and machine learning to improve situational awareness, anticipate system conditions, and support operational decision-making

The same connectivity enabling this real-time visibility and control also introduces new vulnerabilities, blurring the line between physical and cyber risk, yet many utilities manage them separately. Only 22 percent have unified teams in place, even as threats continue to rise, including a 50 percent increase in substation attacks and growing exposure to malware and ransomware, according to the Black & Veatch 2025 Electric Report. Cybersecurity and resilient network design must be embedded into the architecture from the outset—not layered on after the fact.

See what bolder vision looks like

Distribution modernization is fundamentally changing how the system is designed and operated so it can absorb disruption, manage bi-directional flows and respond in real time.

To learn about a successful program, check out Georgia Power’s recent grid modernization program. Black & Veatch partnered with the utility on large-scale infrastructure upgrades. The results? Outages are down 76 percent, restoration times have improved by more than 80 percent and communities across Georgia are powered by a grid built to meet the future head-on.

When the state faced the most destructive storm in the company’s history, Hurricane Helene, Georgia Power deployed a rapid response team that utilized its “smart grid” and restored power to more than 1 million customers within days.

“Not in my backyard” is the rallying cry of citizens everywhere resisting projects proposed for their locality. Whether it’s affordable housing, a waste treatment plant, or a new data center, they may recognize the benefit of the activity. They just don’t want it near them. And the roots of that resistance differ from place to place. When it comes to the ongoing transition from fossil fuels to renewables, companies and policymakers need to know where, exactly, people are coming from.

The Italian island of Sardinia is a textbook example. As IEEE Spectrum’s power and energy editor Emily Waltz discovered when she traveled there last October, Sardinian opposition to wind and solar projects runs deep. It spurred a quarter of the voting population to queue up in public squares in 2024 to sign a petition banning all construction of renewable energy.

Waltz was surprised. She went there to see a promising new grid-scale energy storage system that uses domes inflated with carbon dioxide. While reporting on that project, she interviewed residents, engineers, activists, and professors about their attitudes toward climate change and the Italian government’s grand plans for renewable energy on the island. And Waltz soon learned of Sardinians’ profound antipathy toward renewable energy and its deep ties to a history of invasion, occupation, and exploitation stretching back 2,700 years.

It started with the Phoenicians and then extended through the Romans, the Byzantines, and the Iberians. Sardinia was absorbed into a newly unified Italy in 1861, and it became an autonomous region of Italy in 1948. The island’s population is justifiably suspicious of outsiders, including the Italian government. “When you’re in Sardinia, the weight of history—you can feel it like in the air,” Waltz told me. “And it gets passed down from one generation to the next.”

Now, Italy needs Sardinia to produce even more power to meet the country’s climate goals—something that Sardinians see as Rome’s problem, not theirs. “Sardinia already exports about 30 percent of its electricity. It’s not like they need more,” Waltz says. “So it’s hard to make the case to build, build, build.”

The result of Waltz’s old-fashioned shoe leather reporting is this month’s cover story. She notes that the Sardinians she talked to aren’t climate-change deniers, and they don’t object to renewables per se. They just don’t like the way corporations and Italian policymakers are trying to plug into Sardinia like it’s one giant battery rather than the home of an ancient and proud people.

“I think Sardinians would be more receptive to renewable projects if it was more of a ground-up, grassroots approach,” Waltz says. Indeed, this homegrown approach is already working in some places in Sardinia. She knows of more than 50 projects, called energy communities, where the residents are deploying renewables themselves. The idea also holds promise for other places struggling to get locals to buy into the renewable-energy transition.

The electric vehicle (EV) market in Europe is flourishing, to the point where, in late 2025, nearly 100 percent of new registrations in Norway were EVs. But large electric freight trucks, called electric heavy-goods vehicles (eHGVs), are still as rare as hen’s teeth. Researchers and innovators on the continent are seeking to change this picture, and fast.

Chugging around the European Union are around 4.5 million HGVs, of which only around 14,500, or 0.32 percent, are electric. Figures in the United Kingdom are even more dire. Of the ~625,000 U.K. HGVs, a little over a thousand are eHGVs, making 0.16 percent. Despite diesel prices going through the roof since the start of the Iran war, eHGV sales are not trending upward. In late April, the U.K.’s Society of Motor Manufacturers and Traders (SMMT) reported a drop in eHGV registrations from 1.4 percent last year to 0.9 percent this year. Similarly, the E.U. market is stalling, climbing only from 4.2 percent of new registrations in 2025 to 4.4 percent so far this year. Why?

The long-haul problem

“On the last mile, people are very happy to switch to electric,” summarizes Alex Foote, of Heriot-Watt University, in Edinburgh, who leads the road part of the Transit project, a large-scale research program seeking to holistically decarbonize all U.K. transport—road, rail, maritime, and air—using digital twinning. “It’s long haul where there’s big range anxiety, there are big costs, and then we also have the ‘payload penalty.’” The payload penalty refers to how increasing an eHGV’s range calls for more batteries, whose weight cuts into the payload.

One major improvement would be to speed up charging. A standard CCS2 (Combined Charging System Type 2) rapid charger delivering maximum 350-kilowatt power takes four hours to fully recharge an eHGV with a ~350-kilometer range, a completely impractical amount of time for most long-haul applications.

The new Megawatt Charging System (MCS)—international standards for which were only fully ratified in early 2026—is designed to address this problem. The MCS can deliver over 1 megawatt of power, meaning it can charge a massive HGV battery in 30–45 minutes, perfect for a driver’s mandatory 45-minute break every 4.5 hours of driving.

However, Foote sees practical flaws. “A lot of drivers say that they’re not on break if the vehicle is charging because they have to be there, monitoring it,” he says. “Also, it needs a very reliable and universal booking system, because drivers will need to know there’s a charger there with their name on it that’s not broken or in use.”

On top of this, a truck stop or depot with 10 MCS chargers needs a 10 MW+ connection, equivalent to the needs of about 10,000 homes. Such a massive draw on the power grid could exceed local power constraints, and add massive cost.

Thoughtful eHGV implementation

Instead of installing huge MCS stations in every fleet operator’s depot and at every motorway service station, many researchers and innovators see a more realistic and practical way forward in better combining existing technologies.

The U.K.-based battery innovator Zenobē says that requires thinking holistically. In 2017, a bus company complained that the cost of installing depot charging infrastructure would be more than the cost of the 10-bus fleet itself, and take three years. Zenobē came up with a more tailored solution that reduced this cost to half that of one vehicle, and completed the job in six weeks.

The rear of an iONTRON electric ready-mix concrete truck (eMixer) fitted with a 350-kilowatt-hour battery, part of a trial project with the building-materials supplier Aggregate Industries.Zenobē

“What we see going wrong in a lot of projects is you have ‘margin squirrelers’ across the supply chain, who are all looking for safety buffers because they’re not responsible for the total result,” says cofounder Steven Meersman. “In contrast, we take the attitude that this isn’t a vehicle problem, this isn’t a charging problem—it’s a problem that’s all about optimizing your whole operation.”

Zenobē’s also addresses two other pain points for fleet operators. One is providing private financing options for fleet electrification projects when government grant funding is insufficient or unavailable, reducing initial outlays. The other is removing any risk surrounding battery-life degradation.

Zenobē replaces batteries when their capacity is below a certain threshold, but then uses these old batteries for second-life applications. These batteries might find use as an alternative power source for eHGV charging during peak energy demand, a strategy called “peak shaving,” or they might be used to work alongside a diesel generator on construction sites. These second-life applications have real-world value, which Zenobē can then pass on to their customers. “This means that the [eHGV] customer only pays for what they use,” Meersman says.

Software will drive eHGV adoption

The Swedish freight-technology company Einride offers a somewhat different holistic solution for electrifying fleets.

“Instead of thinking of the transition as a gradual electrification of an existing fleet, we took a step back and asked, ‘Where would full electrification make sense now?’” says electric-mobility general manager David Hallgren. “We wanted to start there and operate more or less entirely with an electric-only fleet from day one.”

Einride’s fully autonomous, driverless, cab-less electric trucks have been operational on public roads since 2019, even completing the world’s first driverless international border crossing in 2025, between Sweden and Norway. But it’s the company’s Saga AI software that sets Einride apart.

This software simultaneously weighs up all of the usual freight-operation factors as well as those specific to eHGVs, such as state of charge, sizes of loads, grid connections, topology, driving style, even the weather. It then learns from real-world data and applies it to future scenarios in order to continuously improve.

Further improving Saga AI, Einride recently partnered with the U.S. quantum-computing company IonQ to help solve a nagging problem in freight logistics. Idle schedule gaps caused by shipment cancellations are difficult to fill optimally using classical optimization techniques. Combining classical techniques with a quantum approximate-optimization algorithm allowed the partners to achieve improvements of up to 12 percent in shipments delivered and a reduction of up to 6 percent in drive distance.

“The number of factors you need to consider and the nonlinearity of how those intersect mean that it becomes impossible to manage an eHGV fleet at scale with any level of manual planning,” says Hallgren. “This is why we’re incorporating AI…and trying to look around the corner at new technologies that will allow us to do this even better.”

This sponsored article is brought to you by Applied Materials.

At pivotal moments in history, progress has required more than individual brilliance. The most consequential breakthroughs — such as those achieved under the Human Genome Project — required a new operating paradigm: Concentrate the world’s best talent around a single mission, establish a common platform, share critical infrastructure, and collapse feedback loops. When stakes are high and timelines are compressed, sequential and siloed innovation simply cannot keep pace.

Today’s AI era is creating an engineering race with similar demands. Every company is pushing to deliver higher-performance AI systems, faster. But performance is no longer defined by compute alone. AI workloads are increasingly dominated by the movement of data: In many cases, moving bits consumes as much — or more — energy than compute itself. As a result, reducing energy per bit can extend system‑level performance alongside gains in peak compute.

The path to energy‑efficient AI therefore runs through system‑level engineering, spanning three tightly interconnected domains:

• Logic, where performance per watt depends on efficient transistor switching, low‑loss power, and signal delivery through dense wiring stacks.
• Memory, where surging bandwidth and capacity demands expose the memory wall, with processor capability advancing faster than memory access.
• Advanced packaging, where 3D integration, chiplet architectures, and high‑density interconnects bring compute and memory closer together — enabling system designs monolithic scaling can no longer sustain.

These domains can no longer be optimized independently. Gains in logic efficiency stall without sufficient memory bandwidth. Advances in memory bandwidth fall short if packaging cannot deliver proximity within thermal and mechanical constraints. Packaging, in turn, is constrained by the precision of both front‑end device fabrication and back‑end integration processes.

In the angstrom era, the hardest problems arise at the boundaries — between compute and memory in the package, front‑end and back‑end integration, and the tightly coupled process steps needed for precise 3D fabrication. And it is precisely this boundary‑driven complexity where the traditional innovation model breaks down.

The Traditional R&D Workflow Is Too Slow for Angstrom‑Era AI

For decades, the semiconductor industry’s R&D model has resembled a relay race. Capabilities are developed in one part of the ecosystem, handed off downstream through integration and manufacturing, evaluated by chip and system designers, and only then fed back for the next iteration. That model worked when progress was dominated by relatively modular steps that could be scaled independently and simply dropped into the manufacturing flow.

But the AI timeline has upended these rules. At angstrom‑scale dimensions, the physics enforces inescapable coupling across the entire stack: materials choices shape integration schemes; integration defines design rules; design rules dictate power delivery; wiring sets thermal budgets; and thermals ultimately constrain packaging scaling. System architects simply cannot wait 10–15 years for each major semiconductor technology inflection to mature.

Representing a roughly $5 billion investment, EPIC is the largest commitment to advanced semiconductor equipment R&D in U.S. history.

A long‑term perspective is essential to align materials innovation with emerging device architectures — and to develop the tools and processes required to integrate both with manufacturable precision. At Applied Materials, together with our customers, we are charting a course across the next 3–4 generations, extending as far as 10 years down the roadmap.

The angstrom era demands that we break down silos and bring together the industry’s best minds — from leading companies to leading academic institutions. If the problem is coupled, the solution must be coupled. If the timeline is compressed, the learning loop must be compressed. It’s not enough to just innovate — we must innovate how we innovate.

EPIC: A Center and Platform for High‑Velocity Co‑Innovation

This is the challenge that Applied Materials EPIC Center is designed to solve.

Representing a roughly US $5 billion investment, EPIC is the largest commitment to advanced semiconductor equipment R&D in U.S. history. When it opens in 2026, it will deliver state‑of‑the‑art cleanroom capabilities built from the ground up to shorten the path from early‑stage research to full‑scale manufacturing. But the facilities are only one component of the model. EPIC is also a platform, an operating system for high-velocity co‑innovation that revolutionizes how ideas move from the lab to the fab.

EPIC is a platform, an operating system for high-velocity co‑innovation that revolutionizes how ideas move from the lab to the fab.Applied Materials

The EPIC model compresses the traditional workflow. Customer engineers work side‑by‑side with Applied technologists from day one — moving beyond isolated process optimization and downstream handoffs. Within a shared, secure environment, EPIC tightly integrates atomistic modeling, test vehicles, process development, validation, and metrology feedback. Constraints that once surfaced late in development are identified and addressed early.

The result is a potentially 2x faster path that benefits the entire ecosystem under one roof:

• Chipmakers gain earlier access to Applied’s R&D portfolio, faster learning cycles, and accelerated transfer of next‑generation technologies into high‑volume manufacturing.
• Ecosystem partners gain earlier access to advanced manufacturing technology and collaboration opportunities that expand what is possible through materials innovation.
• Academic institutions gain opportunities to strengthen the lab‑to‑fab pipeline and help develop future semiconductor talent.

Building on decades of co‑development, we are reinventing the innovation pipeline with our partners across logic, memory, and advanced packaging to deliver the next leap in energy‑efficient AI.

Accelerating Advanced Logic

Logic remains the engine of AI compute. In the angstrom era, however, system‑level gains are increasingly constrained by power and energy. Extending AI performance now depends on architectures that deliver more performance per watt — accelerating the move to 3D devices such as gate‑all‑around (GAA) transistors, which boost density within a compact footprint while preserving power efficiency.

These architectural shifts are unfolding at unprecedented scale, with the logic roadmap already extending beyond first‑generation GAA toward more advanced designs. One key example is GAA with backside power delivery, which relocates thick power lines to the backside of the wafer, reducing resistive losses and freeing front‑side routing for tighter logic cell integration. Another example brings adjacent GAA PMOS and NMOS transistors closer together while inserting a dielectric isolation wall between them to minimize electrical interference. Further out, complementary FETs (CFETs) push density scaling even more by stacking PMOS and NMOS devices directly atop one another.

While these architectures deliver compelling gains in performance per watt and logic density without relying solely on tighter lithography, they significantly raise integration complexity. Manufacturing a single GAA device today can involve more than 2,000 tightly interdependent process steps. At the same time, wiring stacks continue to grow taller and denser to connect these advanced logic devices. Modern leading‑edge GPUs now in development pack more than 300 billion transistors into an area little larger than a postage stamp, interconnected by over 2,000 miles of wiring.

At this level of complexity, the process steps used to create these precise 3D devices and wiring stacks cannot be optimized independently. Design and process must evolve in lockstep, and materials innovation and fabrication methods must advance alongside device architecture. EPIC’s co‑innovation model is designed to accelerate exactly this convergence — enabling logic compute to continue advancing the frontiers of AI at the pace the roadmap demands.

Powering the Memory Roadmap

At the same time, the AI computing era is fundamentally reshaping how data is generated, moved, and processed — making memory technologies, especially DRAM, central to delivering the energy‑efficient performance AI systems require. As models grow larger and more data‑hungry, the DRAM roadmap is shifting toward architectures that deliver higher density, greater bandwidth, and faster access per watt.

At the DRAM cell level, this shift is driving a transition from 6F² buried‑channel array transistors (BCAT) to more compact 4F² architectures, which orient the transistor vertically to boost density and reduce chip area. Looking beyond 4F², sustaining gains in performance per watt will require moving past what 2D scaling alone can deliver. The industry is therefore turning to 3D DRAM, stacking memory cells vertically to add capacity within a constrained footprint. As these structures grow taller and aspect ratios intensify, high-mobility materials engineering in three dimensions becomes increasingly critical to performance and reliability.

Beyond the memory cell array, another powerful lever for DRAM scaling is shrinking the peripheral circuitry, which includes logic transistors and interconnect wiring. One emerging approach places select periphery functions beneath the DRAM array by bonding two wafers — one optimized for the DRAM cells and the other for CMOS logic — using multiple wiring layers.

In parallel, DRAM performance is being extended by leveraging logic‑proven enhancers in the memory periphery. These include mobility boosters such as embedded silicon germanium and stress films, along with wiring upgrades like improved low‑k dielectrics and advanced copper interconnects. Memory manufacturers are also transitioning periphery transistors from planar devices to FinFET architectures, following the logic roadmap to further improve I/O speed. These valuable inflections are central to EPIC’s mission — where they can be co-developed and rapidly validated for next‑generation memory systems.

Driving System Scaling With Advanced Packaging

As data movement becomes the dominant energy cost in AI systems, advanced packaging has emerged as a critical lever for improving system‑level efficiency—shortening interconnect distances, increasing bandwidth density, and reducing the power required to move data between logic and memory.

High‑bandwidth memory (HBM) marks a major inflection along this path. By stacking DRAM dies — scaling to 16 layers and beyond — and placing memory much closer to the processor, HBM enables rapid access to ever‑larger working datasets. This delivers step‑function gains in both bandwidth and energy efficiency.

More broadly, the rise of 3D packages such as HBM underscores why advanced packaging is becoming central to the AI era. Packaging now addresses system‑level constraints that logic and memory device scaling alone can no longer overcome. It also enables a move away from monolithic systems‑on‑chip toward chiplet‑based architectures, as AI workloads increasingly demand flexible designs that combine logic, memory, and specialized accelerators optimized for specific tasks.

A vital technology powering this roadmap is hybrid bonding. With interconnect pitches approaching those of on‑chip wiring, conventional bumps and microbumps run into fundamental limits in density, power, and signal integrity. Hybrid bonding removes these barriers by allowing dramatically higher interconnect and I/O density, supporting a broad range of chiplet architectures — from memory stacking to tighter compute‑memory integration.

As bonded structures like HBM stacks grow larger and more complex, warpage control, die placement, stack alignment, and thermal management become first‑order challenges. EPIC tackles these and other high‑value advanced‑packaging challenges through early, parallel co‑innovation across materials, integration, and manufacturing.

Bringing It All Together

Across logic, memory, and advanced packaging, our industry faces an ambitious roadmap that promises significant gains in energy efficiency for AI systems. But realizing that potential demands breakthrough materials innovation at a time when feature sizes are shrinking, interfaces are multiplying, and process interdependencies are escalating. These challenges cannot be solved on 10–15‑year timelines under the traditional relay‑race model. We must break down silos, align earlier across the ecosystem, and parallelize learning to keep pace with AI’s demands.

In the AI era, progress will be defined by the speed at which lightbulb moments turn into manufacturing and commercialization reality. The only viable path forward is a new innovation model — and EPIC is how we are driving it.

This sponsored article is brought to you by Ampace.

As AI workloads grow to gigascale levels, the global data center industry has hit a hidden physical wall. The real bottleneck is no longer just the thermal limit of the chip or the capacity of the cooling system — it is the dynamic resilience of the power chain.

Modern AI computing clusters, driven by massive GPU clusters, generate high-frequency, abrupt, and synchronized spikey pulse loads. As rack densities soar beyond 100 kW, these fluctuations are amplified into a “power paradox”: while the digital logic of AI is moving faster than ever, the physical infrastructure supporting it remains tethered to legacy response capabilities.

The power usage of these gigascale sites and their drastic, high frequency, abrupt load surges from the AI GPU clusters can trigger transient voltage events and frequency instability, risking the entire local grid. The grid itself is not robust enough to support these loads. This leads to the infrastructure gap: The utility is not robust enough and traditional backup sources, such as diesel generators and gas turbines, simply cannot react to millisecond-level power spikes in output. This will often force operators into a cycle of costly infrastructure over sizing just to buffer the volatility.

AI infrastructure requires energy systems capable of instantaneous response while safeguarding continuity and reliability.

The industry has explored various mitigations — from rack-level BBUs to 800V DC architectures — yet the mature, high volume, traditional UPS system remains the most viable and scalable foundation for gigawatt-level facilities. Consequently, the UPS-integrated battery system has emerged as the critical “physical buffer” to neutralize these pulses at the source.

At Data Center World 2026 in Washington, D.C., Ampace led a pivotal technical dialogue with Eaton during the session “Powering Giga-scale AI.” Their exchange unveiled a fundamental paradigm shift: To bridge the AI power gap, energy storage must evolve from a passive insurance policy into an active, high-speed stabilizer. By aligning Ampace’s semi-solid-state battery innovation with Eaton’s proven system intelligence, we are moving beyond simple backup to solve the physical paradox of the AI era.

To move beyond simple backup and solve the physical paradox of the AI era, Ampace is aligning its semi-solid-state battery innovation with Eaton’s proven system intelligence.Ampace

The “Shock Absorber” physics: semi-solid chemistry for AI pulses

Conventional power systems were designed for steady-state loads, not the rapid heartbeat of a massive AI GPU cluster. When thousands of GPUs synchronize their computing cycles, they generate high-frequency, abrupt pulse loads that can lead to voltage sags, frequency oscillations, and potential interruptions of critical AI training.

Ampace’s PU Series semi-solid and low-electrolyte cells address this challenge by acting as high-speed “shock absorbers.” Leveraging ultra-low internal resistance (DCR) and high cycle capability, these batteries neutralize millisecond-level power spikes at the source, stabilizing the local power loop before disturbances propagate upstream to the grid or on-site generators. These high-rate cells enable 100 kW+ racks to maintain peak performance without transmitting instability across the power chain.

This capability aligns closely with Eaton’s matured UPS architectures, such as double-conversion topologies and advanced power electronics upgrades, which have long prioritized rapid load responsiveness and high system stability.

Together, these approaches embody a shared industry philosophy: AI infrastructure requires energy systems capable of instantaneous response while safeguarding continuity and reliability.

Ampace’s semi-solid state chemistry minimizes liquid electrolyte, greatly reducing the risk of leakage and thermal runaway under continuous AI high-load conditions.Ampace

Algorithmic intelligence: synchronizing energy and control

Hardware alone cannot solve the AI power paradox; the system also requires intelligent coordination between energy storage and power management. Sophisticated battery management systems (BMS) like Ampace’s high-precision design track state-of-charge (SOC) with high-speed sampling, even during rapid, shallow cycling typical in AI workloads.

Complementary algorithmic approaches in modern UPS platforms — such as ramp-rate control and average power management — effectively suppress sub-synchronous oscillations and optimize load smoothing. In large-scale AI training environments, where thousands of GPUs can trigger millisecond-level power pulses, these intelligent layers ensure that batteries buffer high-frequency fluctuations without compromising the mandatory emergency backup reserves.

By transforming energy storage from passive “standby insurance” into active, schedulable assets, the system simultaneously safeguards continuous AI training and maintains the long-term health of the data center infrastructure. In practical terms, this means that even during peak compute bursts, the infrastructure remains stable, training cycles continue uninterrupted, and operators avoid costly oversizing or grid stress.

Eaton’s dual-layer algorithms serve as a valuable benchmark in this space, demonstrating how advanced control logic can achieve similar objectives, reinforcing Ampace’s approach and philosophy within the broader data center power ecosystem.

Economic scalability: optimizing AI infrastructure efficiently

One of the largest costs in deploying AI infrastructure is “oversizing”: procuring transformers, generators, and UPS systems to handle brief peak spikes. This traditional approach inflates the Total Cost of Ownership (TCO) and leads to wasted capital on underutilized hardware.

Ampace’s turn-key cabinet design developed by its independent R&D is engineered for seamless compatibility with mature, high volume UPS systems. By leveraging Eaton’s double-conversion UPS topologies alongside intelligent ramp-rate and average power management algorithms, AI data centers can scale dynamically without requiring costly infrastructure redesigns. This approach allows the UPS and batteries to act as active load-shapers, smoothing AI-driven pulses while strictly maintaining mandatory emergency backup capacity.

By utilizing energy storage as an active, schedulable asset, operators can right-size their infrastructure, avoid unnecessary grid upgrades, and deploy gigascale AI clusters with unprecedented efficiency.

Safety First: Protecting AI Infrastructure While Enabling Innovation

In high-density AI facilities, safety is non-negotiable. Ampace’s semi-solid state chemistry minimizes liquid electrolyte, greatly reducing the risk of leakage and thermal runaway under continuous AI high-load conditions.

Ampace’s turn-key cabinet design developed by its independent R&D is engineered for seamless compatibility with mature, high volume UPS systems. Ampace

At the same time, Eaton’s UPS design emphasizes system-level energy scheduling that never sacrifices mandatory emergency backup reserves, ensuring thermal safety and uninterrupted operation.

This “safety-first” approach ensures that infrastructure can sustain aggressive performance targets without compromising the physical integrity of the facility. Coupled with over a decade of proven high-cycle life operation and design under shallow pulse conditions, these systems can extend operational lifespan, reduce replacement requirements, and provide operators with confidence that safety and reliability remain uncompromised as compute density continues to grow.

To remain the scalable backbone of AI data centers

As AI computing scales over the next two to three years, the industry will face stricter grid requirements and even more demanding pulse load characteristics. This evolution demands a forward-looking design philosophy that harmonizes UPS, battery, and grid compatibility.

Ampace views current low-electrolyte semi-solid technologies as the optimal transitional step toward a fully solid-state future — one that promises ultimate safety and performance.

Ampace remains committed to this long-term technological roadmap. We view current low-electrolyte semi-solid technologies as the optimal transitional step toward a fully solid-state future — one that promises ultimate safety and performance. Whether through rack-level BBU, integrated UPS systems, or containerized storage, the universal core of the AI era remains constant: high-speed response, long shallow-cycle life, and refined energy management.

By engaging in deep technical exchanges with Eaton and leading energy innovators, Ampace ensures that its solutions not only meet today’s AI pulse challenges but also harmonize with broader infrastructure strategies and shared industry best practices.

Ultimately, as traditional diesel generators gradually give way to diversified alternatives, the integrated UPS-plus-energy-storage system will become the fundamental infrastructure standard.

The dialogue has just begun. Ampace will continue to engage in strategic exchanges with global industrial automation leaders and digital energy pioneers, co-authoring the playbook for a safer, more efficient, and more resilient AI-ready world.

The rise of electricity-guzzling data centers has forced the artificial intelligence industry to get creative about finding power. One of the latest ideas: Build micro data centers next to utility substations and operate them in concert, shifting the computation around based on power availability.

That’s the approach Nvidia and its collaborators are taking in a new pilot project they plan to build later this year. They’ll construct about 25 of these small data centers, each ranging from 5 to 20 megawatts, across five utilities in the United States. If one substation is overloaded with power demand, or if there’s an outage, the compute will be shifted to a different data center near a substation that has spare capacity.

To develop the fleet, Nvidia is partnering with data center builder InfraPartners, real estate service provider Prologis, and the nonprofit EPRI (formerly known as the Electric Power Research Institute).

The project aims to demonstrate a new way for data centers to be more flexible and accommodating of electricity availability. It’s also a way for data center developers to quickly secure power from the grid—an increasingly precious commodity, even in small chunks.

“We started looking at how much [unused] power is available at individual substations, and what we found was that on average, like 5 MW is nominally available…max 20 MW,” says Ben Sooter, director of Agentic AI Initiatives and Distributed AI Architecture at EPRI.

That’s too small to interest most data center operators, but building several at that size and operating them as if they’re one larger one is useful, Sooter says. Plus, shifting compute away from overburdened substations to those with more headroom can double the overall available power, he says.

“There are 55,000 substations in the U.S., and if they each have 5, 10, or 20 MW of spare capacity, that number adds up pretty fast,” adds Marc Spieler, senior director of energy at Nvidia.

Building energy flexibility into data centers

Squeezing every spare megawatt out of the grid will become increasingly important as data center construction continues to ramp up. In the United States, where half of all new data centers are being built, data centers could consume 9 to 17 percent of electricity generation by 2030. That’s more than double the current use, according to EPRI’s estimates. Facilities that train AI models are being built at the gigawatt scale, drawing about the same amount of power as a midsize U.S. city.

As grid operators figure out how to accommodate such massive new loads, data center developers sometimes end up waiting up to a decade to get approved for a grid connection. In response, the developers are making incredibly bold decisions around power—moves that would have been unthinkable just two years ago.

Many are building their own gas power plants on site. Some are offering to pay for the cost of new transmission lines and other grid infrastructure. And a few are even investing in startup companies that are developing fusion and next-generation nuclear fission reactors, in the hope of meeting power needs a decade from now.

But there’s a lot more power available on the grid than is used day to day. U.S. grid operators use only about 53 percent of their generation capacity on average, according to a landmark 2025 report from Duke University’s Nicholas Institute for Energy, Environment and Sustainability.

That’s because the U.S. electricity supply was built to meet peak demand—periods of the highest energy use of the year, such as the hottest days of the summer. Those peak loads can be almost double the load on a mild-temperature day and typically occur for less than 200 hours a year. The rest of the time, whole power plants sit idle.

If AI data centers can find a way to reduce or shift power consumption during these periods of peak demand, the extraordinary measure of building on-site power generation may not always be necessary. U.S. grids could provide an additional 76 GW—about 10 percent of peak demand—if large loads like data centers curtailed their power use just 0.25 percent of the time, according to the Nicholas Institute report.

Energy flexibility could also allow data centers to connect to the grid faster because they wouldn’t have to wait for new power plants to be built. And placing small data centers right next to substations reduces the need for new grid infrastructure, such as power lines and poles, and upgraded transformers and switch gear. As a bonus, these substations already have fiber-optic lines for high-speed internet, Nvidia’s Spieler points out. So the small data center can connect to those existing lines.

The inference advantage

The type of flexibility data centers can offer depends, in part, on the workload. The two main types of workload are AI training (the process of developing, say, a large language model or image generation model) and inference (using that model to, say, generate responses to users’ chatbot questions and requests for images).

Training requires huge data centers with tightly interconnected GPUs. For example, Meta’s Llama 3.1 405B model took about two and a half months to train on 16,000 GPUs. During training, adjusting all the model weights at once at each step requires the GPUs to be connected via high-speed links, such as Nvidia’s NVLink and InfiniBand interconnects. It wouldn’t be practical to spread out AI training workloads among a fleet of mini data centers. On the bright side, because training takes months, it’s possible to pause for short periods of time to curtail energy use during peak demand.

Inference doesn’t require as many GPUs or as much fancy networking. Instead of a huge corpus of data, a single user’s query is fed into the model, and the model spits out the answer. No backpropagation is involved—that is, no large-scale coordination between different chunks of input data is needed. And so inference is amenable to smaller data centers. However, timing is key. When you ask an image generator for a picture of your face pasted onto a cute cat, you understandably expect to see the result right away. So rather than briefly pausing compute during peak demand, the energy flexibility can come through creatively shifting the workload to a different location.

“Inference is one of the few workloads that can be dynamically routed,” says Valerie Crafton, senior vice president of strategy and operations at modular data center company Mod42. “Which means that you can align the compute with wherever the power is actually available. That’s one unique piece that’s really driving the push for a lot of these smaller data centers where the power exists.”

Both Nvidia and EPRI have been on a tear to demonstrate different kinds of data center flexibility. They’re calling their substation-based strategy “distributed inference.” Announced in February, the project aims to begin construction of the pilot fleet of small data centers by the end of 2026. Nvidia and EPRI estimate that compute workloads will need to be moved to a different substation only about 0.1 percent of the time.

Going micro in data center size is an idea that’s picking up speed. “We’re in this compute wave currently where everybody’s building these really large data centers—5 gigawatt, mammoth things,” says Sooter. But “there’s a second compute wave coming,” involving much smaller data centers handling inference, he says. Tech companies are “really beating the drum on this because they see demand for inference compute really picking up in 2027,” he says.

This story was updated on 13 May, 2026 to correct the source of the 76-GW figure.

This article appears in the July 2026 print issue as “Small Data Centers Snuggle Up to Grid Substations.”

“Why are you here?” Fabrizio Pilo, an electrical engineer, asks me as we sit in an outdoor café near his home in Cagliari, an ancient city on the island of Sardinia. It’s a fair question. I’m a journalist from the United States. I’d just stepped off my flight 2 hours prior and come straight to this meeting, suitcase still stowed in my rental car.

I’m here to see three intriguing new energy projects under development in Sardinia. I’d heard there’s strong public resistance to renewable energy, and I want to understand why that is. I tell Pilo, who is vice rector for innovation at the University of Cagliari, that I hope he’ll share some insights before I head out on a reporting trip across the island. (My answer seems to satisfy him, and he kindly gives me an hour of his time).

This won’t be the first time that I’m asked to explain my presence on the island. I’d expected it, to some extent; I’m a foreign journalist poking around, after all.

What I didn’t expect was the depth of Sardinians’ distrust, not just of journalists, but of any outsider, particularly ones with authority. Over the last few years, developers of wind and solar projects, most of whom aren’t from here, have been absorbing the bulk of this smoldering, communal wariness.

Activists Maria Grazia Demontis [left] and Alberto Sala, photographed inside the archaeological monument Giants’ Tomb of Pascarédda, have worked to stop the construction of wind farms by organizing protests and taking legal actions through their organization Gallura Coordination. Luigi Avantaggiato

In fact, the resistance is so widespread among Sardinians that over the course of two months in 2024, a grassroots petition to ban new wind and solar projects gathered over 210,000 certified signatures. That’s more than a quarter of Sardinia’s typical voter turnout and represents a cross-party consensus. People stood in long lines in public squares to sign. And it worked: Political leaders responded swiftly with an 18-month moratorium on renewable energy construction.

“I’ve never seen so much engagement for anything” in Sardinia, says Elisa Sotgiu, a literary sociologist at the University of Oxford, who was born and raised on the island. “Sardinia has a bunch of problems like enormous unemployment. There’s lots of emigration because there are no jobs. It’s one of the poorest areas in Europe. The area is just decaying,” she says. “And yet the thing people are demonstrating against is renewable energy.”

And the opposition continues: A network of mayors has mobilized for the cause. Thousands of people show up at organized protests. Activists vandalize grid equipment. Families are passing down these stories of resistance to their children as a point of pride. Local media outlets are egging it on, frequently publishing misinformation tinged with fearmongering.

These aren’t just NIMBY complaints—not in the pejorative sense, at least. The resistance, and the distrust underlying it, is rooted in the island’s complex history, both recent and ancient. It’s based on a past that the Sardinian people carry with them—a past that has seeded a deep sense of suspicion and vulnerability. Resistance, I learn, is part of what it means to be Sardinian.

Fabrizio Giulio Luca Pilo, vice rector of innovation at the University of Cagliari, has been working to help Sardinia transition to cleaner, more reliable energy. Luigi Avantaggiato

“It is a very sad situation,” Pilo tells me. “There are a lot of economic reasons to do the [energy] transition.” It could attract new companies such as data centers, which would create new jobs, he argues. It could reduce Sardinia’s reliance on imported gas and fuel, making the island more independent. New economic activity on the island might help reverse its population decline, he adds.

And while what’s happening on Sardinia is unique, it also represents a larger trend: A growing number of communities around the world are opposing wind- and solar-farm construction, to the consternation of stakeholders. By 2025, nearly one-fourth of the counties in the United States had enacted some impediment to new utility-scale wind and solar energy—up from as few as 15 percent two years earlier, according to a USA Today analysis. In Africa, community pushback successfully canceled major projects such as the 60-megawatt Kinangop Wind Park in Kenya. In India, local pastoralists are challenging the 13-gigawatt Ladakh solar and wind project. And the European Union’s top-down push for renewable energy has created opposition in many communities.

Their reasons vary—land-use preferences, generational ethos, government resentment, property values, economic effects, aesthetics—but all of these struggles have this in common: The resisters are passionate and they are often successful in blocking development.

This is a looming problem for the energy transition. Unlike large, centralized coal and nuclear power plants, renewable energy is geographically spread out, so it touches far more communities. Sardinia offers one of the clearest cases of what can go wrong when renewable-energy developers and authorities fail to consider the complexities of the local situation on the ground.

Why is Sardinia resisting renewable energy?

Roughly the size of New Hampshire, Sardinia juts out of the Mediterranean Sea about 200 kilometers west of Italy’s mainland. Technically it’s part of Italy, but Sardinians are quick to point out their island’s autonomous status—a subtle way of saying, “We do things our way.” Its mountains seem to echo the sentiment. With the highest peaks running in a chain along the east side of the island, Sardinia resolutely turns its back to the mainland.

At first glance, the island looks like the kind of place that’s ripe for an energy transition. Its two coal plants are aging and are targeted to be shut down to meet climate commitments. It has no nuclear power, nor does it produce its own natural gas. Wind and sun, however, are abundant and could easily meet the energy needs of Sardinia’s sparse population of about 1.5 million.

But while the resources may be ready for a transition, the people emphatically are not. When I first arrive in Sardinia and take in its beauty, I assume that the impetus behind the fight against wind and solar farms boils down to how they look. Waves of silicon, metal, and concrete would spoil views of Sardinia’s stunning beaches, rugged mountains, ancient pastures, and idyllic medieval villages, after all.

Residents of the city of Orgosolo in 1969 famously stopped the construction of a military firing range on communal grazing land known as Pratobello. Its village walls are still covered in murals advocating social protest and antiauthoritarianism. Luigi Avantaggiato

But the island’s aesthetic—and the tourism industry that depends on it—are only part of the equation. The far stronger cultural forces at play are rooted in Sardinia’s past. Over millennia, the island has endured successive invasions from outsiders seeking to exploit the land. These incursions, and Sardinians’ rebellious responses to them, have become an integral part of the island’s identity passed down through generations.

The invasions started with the relatively peaceful settlement of the Phoenicians in the 9th and 8th centuries B.C.E. Then came the Romans, the Byzantines, and the Iberians, who conquered with violence, looting, and enslavement. But legend has it that despite the might of these ancient conquerors, pockets of Sardinia sometimes managed to defend themselves. “Not even the Roman empire could conquer the shepherds of the highland regions,” is the oft-repeated tale. Whether that’s true or just an idealization is beside the point; such stories serve as an enormous source of pride and identity.

Sardinia exported about 30 percent of the electricity it generated in 2025, largely to Corsica and the Italian mainland via two existing submarine cables.

The island is “fiercely proud of its identity…especially in the center of Sardinia, which was the most resistant part,” says Andrea Vargiu, a sociologist at the University of Sassari in Sardinia. “This long history of exploitation is still in our DNA, along with a proud sense of autonomy,” he says.

Sardinia’s unification, in the mid-1800s, with what would become the Kingdom of Italy is seen by many as an act of colonization. It didn’t help that Italy then proceeded to exploit Sardinia’s forests and other resources for the benefit of the mainland—a practice that continued through the 20th century, says Vargiu.

Sardinian bandits sometimes fought back with their own sense of justice, settling matters through raids, kidnappings, and violence. Their stories live on in Sardinian lore with an almost mythical quality, the brigands admired for their intractability.

Pasquale Mereu, mayor of Orgosolo, helped organize the Pratobello 24 movement against renewable energy in Sardinia. Luigi Avantaggiato

Italy’s use of the island for military purposes particularly irked locals. In a famous case in 1969, residents of the town of Orgosolo successfully thwarted the construction of a firing range on communal grazing land known as Pratobello. That name has since become synonymous with the defense of one’s territory, and a rallying cry.

“Sardinia has always been a land of conquest,” says Pasquale Mereu, mayor of Orgosolo, who spoke with IEEE Spectrum through an interpreter. “We believe that even today we are still a colony of Italy, and I’m not ashamed to say it even though I represent an institution.”

A longstanding mural on one of his village’s walls reads: “You are in the territory of Orgosolo; here the people rule supreme and the government obeys.”

Sardinia’s History Shapes its Identity

Driving around the island and talking to people, I can feel the weight of Sardinia’s history—and people’s propensity for holding onto it. Elaborate heritage festivals occur nearly every autumn weekend in the island’s interior. They’re well attended, multigenerational affairs that aim to keep old traditions alive. In the medieval town of Belvì, men roast chestnuts—marroni—over an open fire in a frying pan the size of a swimming pool and then serve them to the crowd by shoveling them into troughs. They’re delicious. In an adjacent amphitheater, the crowd sways along to costumed performers leading traditional dances.

Then there are the Bronze Age stone structures, called nuraghi, that are pretty much everywhere. Built before the violent conquests, these conical towers have come to symbolize a romanticized vision of the heyday of Sardinia’s independence. More than 7,000 of them remain, ranging from unremarkable piles of rocks to complex towers, each one carefully documented on an interactive online map. I visit one of the more intact ones that’s fenced off and requires an admission fee. As I take some video with my phone, an employee asks me who I am and what I’m doing and informs me I’ll need to get permission from the government before posting anything online.

This rock hollowed out by erosion and walled up with stones was likely used by shepherds as a shelter near the historic Sardinian village of Tempio Pausania. Luigi Avantaggiato

But in interviews with residents, I’m continually reminded of the darker side of Sardinia’s past. People often bring up painful things that happened 50 or 500 years ago. A middle school science teacher named Giannina Serpi, and her husband, Roberto Moro, meet me at a café in the seaside town of Sant’Antioco. When I ask why people are so opposed to renewable energy, they (like many people I interviewed) point to the 1970s.

Sheep return from pasture in Bonorva, Sardinia, near the Bonorva wind farm operated by EDF Renewables. Luigi Avantaggiato

That decade brought a new kind of exploitation: not by empires or governments, but by technology companies. Petrochemical, aluminum, and other industrial companies from overseas built factories on the island, creating jobs and adjacent businesses. But after a few decades, economic and geopolitical factors led the companies to close the factories, sinking local economies and in some cases leaving behind toxic contamination.

In the northern city of Porto Torres, several petrochemical plants, a thermoelectric power plant, and an industrial harbor employed about 8,000 workers in the early 1970s. But the oil crises of that decade took its toll on jobs, and when environmental contamination became evident in the 1990s, employment plunged further. By 2010, most of the petrochemical plants had closed. Studies show that residents of Porto Torres during that time had curiously high rates of death from cancer, although there is no consensus on the cause.

Similarly, studies have found higher rates of lead in children in the Portovesme area in the southwest, about a 20-minute drive from where I sit with Serpi and Moro in Sant’Antioco. There, the U.S. aluminum producer Alcoa operated a smelter that employed about 500 people and supported an estimated 1,500 adjacent jobs. But the company shut down the smelter in 2012. Three years earlier, Russian aluminum manufacturer Rusal had idled its Eurallumina factory nearby.

The impacts of these events still feel fresh, Serpi explains through a digital translator. She says she teaches this history to her students but doesn’t tell them how to feel about it. “I let them decide,” she says.

Energy Colonialism in Sardinia

Against this backdrop, renewable-energy developers in the early 2010s began sizing up Sardinia. They were drawn by the cheap land, low population, strong wind, and sun that shines an average of about 300 days a year. EF Solare Italia commissioned an 11-MW solar plant in 2010. Rome-based Enel Green Power began construction of a 90-MW wind farm in Portoscuso the following year.

Other developers followed, and they mostly came from elsewhere—mainland Italy, Europe, and later, China. The way many Sardinians saw it, the new plants didn’t bring many long-lasting jobs. Most of the work ended after the design and installation phases, and profits went back to the companies’ headquarters outside of Sardinia, they argued. People called it “energy colonialism” and lauded landowners who refused to sell or lease their property to developers.

Pink granite called Ghiandone Limbara was extracted from the Sinnada quarry in northern Sardinia from the late 1970s to 2011. Luigi Avantaggiato

The uncle of Oxford’s Sotgiu is one of those landowners. She says that a couple of years ago a solar company asked him if he would allow the installation of an array on his family farm in Logudoro in Sardinia’s interior. “From that, he would have gotten something around €150,000 a year, which is more money than he’s seen in his life,” says Sotgiu. The money could have covered his three kids’ college education, she says. “But he refused.”

He had many reasons. For one, switching from sheep grazing to the more passive business of leasing land would have put the fate of his income in the hands of an outsider. “If you deprive a region of any sort of economy that is self-reliant, then it’s really fragile,” says Sotgiu. Her uncle didn’t trust that the income would last, and worried he’d be left with a ruined farm, she says. Plus, his farm has been in the family for generations and one of his sons is interested in continuing the business. “So I understand his pride in saying, ‘No, this is my farm, I don’t care about the money,’” she says.

Sardinia has one of the largest carbon footprints per capita in Europe.

Despite that kind of grassroots resistance, development continued. In 2023, the Italian government authorized the construction of a 1-GW submarine power cable to connect Sardinia to Sicily and the Italian mainland. When completed, the bidirectional cable, called the Tyrrhenian Link, will increase electricity exchange between the regions, bolster grid reliability, and help grid operators efficiently use more renewable energy.

Sardinian activists, however, view the cable as a way to justify even more construction of wind and solar plants, and to export the island’s energy for the benefit of non-Sardinians. The island already exports about 30 percent of its electricity, largely to Corsica and the Italian mainland via two existing submarine cables.

The Florinas wind farm, commissioned in 2004, was one of the earliest wind farms built in Sardinia. Luigi Avantaggiato

And then came the tipping point. In June 2024, in an effort to meet the European Union’s 2030 renewable energy targets, Italy committed to building more than 80 GW of new wind and solar energy capacity over December 2020 levels. The national government divvied up the burden among its regions and told Sardinia to build its portion, 6.2 GW.

The move triggered an onslaught of requests from wind and solar developers wanting to build projects in Sardinia. The queue at one point topped 50 GW of grid-connection requests. That represented more than 700 solar and wind projects, many of which came from companies outside of Sardinia.

The southern newspaper L’Unione Sarda ran wild with the numbers. Almost daily, for months, it published stories about the “wind assault.” The call-to-arms posts urged people to protest. “The Attack on the Landscape Does Not Stop; The Threat From Agrivoltaics Is Growing,” read a July 2024 headline. Unsubstantiated articles tried to link wind and solar developers to organized crime.

“It was scaremongering,” says Sotgiu. “It was a little dishonest, as I saw it, because they kept exaggerating and scaring people into thinking that we were going to be invaded.” (Representatives of the newspaper declined to comment.)

The numbers did scare people. Lost was the fact that a grid-connection request is just the start of a multiyear process that involves permitting and legal review and often ends in withdrawn or downsized projects. Submitting a request is inexpensive, and developers often cast a wide net by entering lots of these queues globally to increase the odds of being accepted. In the end, only a fraction come to fruition. In other words, building all, or even most, of the requested 50 GW was never going to happen.

“I tried to explain this” to the public, says an industrial engineer at the University of Cagliari, in Sardinia, who asked to remain anonymous to avoid any detrimental impacts of speaking out. “I went to the regional television station. But it’s difficult with technical information. And the newspaper communication is so bad, and its impact is so strong in the community, that it’s very difficult to change people’s minds,” he says.

Pratobello 2024 and Anti-Wind Protests

And so the collective angst caused by powerful outsiders, industry, and the state united Sardinians into a singular cause. Faced with what felt like another attempted conquest, they did what their families and community had taught them to do: They resisted. Says Mereu: “This is what we are rebelling against: the idea that Sardinians are few and therefore must put up with everything.”

In a nod to the 1969 resistance in Orgosolo, they dubbed the movement “Pratobello 2024.” Activist groups, called “committees,” organized protests, and created social media campaigns and videos. Thousands of people started showing up at planned demonstrations. A lawyer went on a hunger strike. Vandals unscrewed bolts on wind turbine blades and set fire to grid and construction equipment.

Italy’s transmission system operator, Terna, had to switch to company cars without logos to avoid being targeted. Students studying the electricity system in a master’s program sponsored by Terna were verbally attacked at an airport, according to a professor at their school who spoke with me about the violence.

Celebrities got involved. Italian actress and Bond Girl Caterina Murino met with Sardinia’s president to ask her to reject wind farms. Murino posted on Instagram: “Nobody touch Sardinia!!!!” On Italian national TV, the jazz legend Paolo Fresu performed on trumpet while popular TV host Geppi Cucciari read an impassioned lament about the exploitation of the island.

Sardinian author Erre Push penned a graphic novel titled Fàula Birdi about a protagonist who resisted an imposition from outsiders. He wrote it upon the request of the activist group ReCommon, whose mission is to “challenge corporate and state power responsible for the plunder of territories.” Push hopes the book will inspire more people to follow the protagonist’s lead. “Renewables are another imposition like in the past—not to help Sardinians but to help external people like industry managers or founders of companies,” he told me through an interpreter.

Concerned about the influx of solar and wind farms being built in Sardinia by outsiders, Roberto Pusceddu, under his pen name Erre Push, published a graphic novel that aimed to inspire young people to resist such impositions. Luigi Avantaggiato

Mereu and a network of mayors drafted the petition that gathered so many signatures. The people had spoken. In response, Sardinian politicians passed a law that imposed an 18-month ban on construction of wind and solar projects within 7 km of a nuraghe or other archeological site. It wasn’t a total ban, but it might as well have been. “If you put a circle with a 7-km radius around each archeological site, you cover all of Sardinia,” says Emilio Ghiani, a power systems expert at the University of Cagliari. “In this way, it is impossible to find a place to install a new plant.”

The move was like giving the Italian government—and the EU’s clean energy targets—the middle finger. And it sent renewable-energy developers scrambling. One company building an agriphotovoltaic plant raced to bring construction to 30 percent completion, which the new law said was the threshold for being allowed to proceed. The company asked not to be named in this story to avoid trouble.

Furious, the government in Rome challenged the Sardinian regional law in Italy’s Constitutional Court, and in January this year it prevailed. In its decision, the court rejected the law, saying that renewable-energy projects should be evaluated case by case.

Project development quickly resumed. So did the backlash. A headline in L’Unione Sarda declared: “Enough With Top-Down Decisions Without Consulting Communities.”

Sardinia’s Renewable Energy Conflict

Where the island goes from here is unclear. There’s a willingness among a portion of the population to move forward with an energy transition. For example, some of Sardinia’s largest cheese makers are powering their operations with renewable energy and installing systems to utilize waste heat for efficiency. But for the most part, the public isn’t budging in its resistance. Researchers are trying to dispel inaccurate information, but regional newspapers seem bent on perpetuating fear.

Plus, there are technical issues to work out before a full-scale energy transition can be made. Sardinia’s transmission system was built around the centralized generation of two coal plants; it wasn’t made for the distributed generation of wind and solar plants. Renewables require a more dynamic grid, more energy storage, and a wider range of power sources to compensate for their intermittency. Engineers are working on it, but they’ve got a ways to go.

The new Tyrrhenian Link undersea power cable will help with that. By connecting Sardinia, Sicily, and the mainland, the cable creates more flexibility in the system. When wind or solar generation slows in Sardinia, for example, electricity from the mainland can fill in the gap, and vice versa. “It will increase the reliability of the system, and after it’s installed, it will be possible to switch off the old generation plants that use coal,” says Ghiani. In January, Terna finished laying the western section of the cable between Sardinia and Sicily, and in April it completed the eastern section between Sicily and Campania on the mainland. Doing so set a world record for power cable depth, at 2,150 meters below sea level, according to Terna.

Italy originally ordered Sardinia’s two coal plants to shut down by 2025 but later extended the deadline to 2038.

The link is one of the most innovative high-voltage direct current (HVDC) projects in Europe. It can move up to a gigawatt of power and reverse that power flow nearly instantaneously. By using voltage source converter (VSC) technology, it can also help prevent power-flow problems by regulating frequency and smoothing out oscillations in the grid in real time. And it has black-start capability: In the event of a shutdown, it can help restore the grid without relying on an external electric network. These features are particularly helpful for an isolated network like Sardinia’s.

Italy has created new incentives and regulations to build a market for grid-scale energy storage. Having plenty of storage is a key to scaling up renewables because it provides backup power when the wind isn’t blowing or the sun isn’t shining. To this end, Italy created MACSE, an auction that gives storage developers revenue certainty. Its name translates to mechanism for the procurement of electricity storage capacity. The first auction round, in September, successfully awarded 10 GWh.

Energy experts in Sardinia are also working with policymakers to change the rules around grid-connection requests. But these kinds of nerdy details don’t grace most household conversations.

Industrial Sites Host Energy Storage

Something more accessible that the public can get behind is building renewables on Sardinia’s abandoned industrial sites. “To be honest, not everything is so beautiful here. We have a lot of industrial areas where you can place PV panels. We have a lot of rooftops,” electrical engineer Pilo says. “We have unused coal mines.” I visit one such project that’s proceeding with local support—or at least without much opposition. It’s a coal mine near Gonnesa that shut down in 2018 and is now being turned into a data center and a pumped-hydro energy storage system.

The plan is to move water through the mine’s vertical geometry via an enclosed membrane—like a soft pipe—and use the flow to turn a turbine that generates electricity. The water then gets pumped back to the surface and stored in pear-shaped vessels above ground. The scheme will help power the data center, which will be built both above and below ground, including in the mine’s largest chambers nearly 500 meters below the Earth’s surface.

Energy Vault will remove old mining equipment from the Carbosulcis coal mine near Gonnesa to make way for an underground data center [above]. It will be powered by a pumped-hydro energy storage system that flows through the mine’s vertical geometry and stores water in above-ground tanks [top].Luigi Avantaggiato

Energy storage developer Energy Vault is building it, and despite being based in Lugano, Switzerland—that is, not Sardinia—the company seems to have avoided protest. It helps that the mine is owned by Carbosulcis, a Sardinian regional-government-owned company, which is calling the shots on the project.

Plus, doing nothing with the mine costs money. The mine closed eight years ago because it wasn’t profitable, but Carbosulcis must continue maintaining it because of its high methane emissions, which require monitoring and ventilation to prevent explosions and leaks. Carbosulcis managers figured that if they’re going to continue putting money and personnel into the mine, they might as well do something useful with it, Luca Manzella, vice president for Europe, Middle East, and Africa at Energy Vault, says as he and I tour the mine.

An innovative project in Sardinia’s interior—Energy Dome’s grid-scale carbon dioxide battery—seems to be avoiding protest as well. Built in a gated industrial complex near Ottana, this energy-storage facility looks like a giant bubble—the kind that fits over a stadium or tennis complex. It’s filled with carbon dioxide that is compressed to store 200 MWh of electricity for the grid. Although the bubble is visible from several of the surrounding hillside villages, and although the developer is headquartered on the mainland, there’s little sign of public pushback.

Energy Dome began operating its 20-megawatt, long-duration energy-storage facility in July 2025 in Ottana, Sardinia. In partnership with Google, the company this year aims to build replicas of the system on multiple continents.Luigi Avantaggiato

Another path forward is through “energy communities.” In this grassroots approach, consumers work together to build their own solar plant or other power generation. Dozens of these communities are already active on the island, according to the Sardinian Electricity Association, a group that provides guidance to consumers.

But by far the greatest need is for energy developers and authorities to understand the people and the history of the land on which they want to build. “When Europe or the national government make a law, they have to also consider the background of Sardinian people and why they are so afraid,” says Simone Micheletti, CEO at Futura Group, a renewable-energy developer based in Serramanna, Sardinia. “You cannot apply the same law to Sweden and Sicily. Sometimes you need to understand [the situation] locally,” he says.

Decision makers everywhere would be wise to listen. Otherwise, they may suffer the same fate as their counterparts in Sardinia: despised by locals, delayed by politics, and surprised at how badly it all went.

Special thanks to Luigi Avantaggiato for interpreting and additional reporting.

This story was updated on 13 May, 2026 to correct the percentage of electricity that Sardinia exports.

This article appears in the June 2026 print issue as “Sardinia’s Energy Future Hinges on Its Past.”

Laboratory or in-field measurements are often considered the gold standard for certain aspects of power system design; however, measurement approaches always have limitations. Simulation can help overcome some of these limitations, including speeding up the design process, reducing design costs, and assessing situations that are often not feasible to measure directly. In this presentation, we will discuss two examples from the power system industry.

The first case we will discuss involves corona performance testing of high-voltage transmission line hardware. Corona-free insulator hardware performance is critical for operation of transmission lines, particularly at 500 kV, 765 kV, or higher voltages. Laboratory mockups are commonly used to prove corona performance, but physical space constraints usually restrict testing to a partial single-phase setup. This requires establishing equivalence between the laboratory setup and real-world three-phase conditions. In practice, this can be difficult to do, but modern simulation capabilities can help. The second case involves submarine HVDC cables, which are commonly used for offshore wind interconnects. HVDC cables are often considered to be environmentally inert from an external electric field perspective (i.e., electric fields are contained in the cable, and the cable’s static magnetic fields induce no voltages externally). However, simulation demonstrates that ocean currents moving through the static magnetic field satisfy the relative motion requirement of Faraday’s law. Thus, externally induced electric fields can exist around the cable and are within a range detectable by various aquatic species.

Key Takeaway:

• Learn how to use modern simulation to translate single-phase laboratory corona mockups into accurate three-phase real-world performance for 500 kV and 765 kV systems.
• Explore the physics behind how ocean currents interacting with HVDC submarine cables create induced electric fields—a phenomenon often overlooked but detectable by aquatic species.
• Gain actionable insights into how to leverage simulation to reduce design costs and bypass the physical space constraints that often stall traditional testing.
• See a practical application of electromagnetic theory as we demonstrate how relative motion in static magnetic fields necessitates simulation where direct measurement is unfeasible.