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The challenges of long-duration energy storage have inspired some creative solutions.
Imagine a battery. Maybe you envision popping one into a fading flashlight or a dead remote controller. Perhaps you consider the little icon on the top of your phone or laptop screen, precariously dipping into the red while you search for a charger. Or you might picture the powerful battery pack inside your electric vehicle, helping to make gas stations obsolete.
These minor to major electrochemical marvels are fine, but the opportunity space for energy storage is so, so much larger — and weirder. Water moving between two reservoirs is a classic un-classic battery, but compressed air stored in a cavern, raising and lowering heavy blocks, even freezing water or heating up rocks can also all be batteries. And these methods of energy storage have the potential to be enormously helpful where standard lithium-ion batteries fall short — namely for long-duration energy storage and large-scale heating and cooling applications.
Lithium-ion batteries still dominate the market, Kevin Shang, a senior research analyst at energy consultancy Wood Mackenzie, told me. But “over the next 10 years, we do see more and more long-duration energy storage coming into play.” Typical lithium-ion batteries can provide only about four hours of continual power, occasionally reaching up to eight — though that’s an economic constraint rather than a technical one. Generally speaking, it’s too pricey for lithium-ion to meet longer-duration needs in today’s market. So as states and countries get real about their clean energy targets and install more wind and solar generation, they need some way to ensure their grids’ reliability when the weather’s not cooperating or demand is peaking.
“There’s a need for something that can substitute for natural gas,” Logan Goldie-Scot, director of market research at the sustainable infrastructure investment firm Generate Capital told me. Almost no one believes lithium-ion batteries will be a viable alternative. “And so then it is an open question of whether that role will be filled by long-duration energy storage, by green hydrogen, or by clean firm power” like nuclear or geothermal, he said.
There are some novel battery chemistries and configurations out there, from Form Energy’s iron-air batteries to flow batteries that store their electrolytes in separate tanks to zinc-based batteries. But there are also numerous more creative, non-chemical, not-what-you-might-consider-a-battery batteries vying for a role in the long-duration storage market.
Founded back in 2010, Toronto-based Hydrostor has been pursuing “advanced compressed air energy storage” for a while now. Essentially, the system uses off-peak, surplus, or renewable grid energy to compress air and pump it into a water-filled cavern, displacing that water to the surface. Then when energy is needed, it releases the water back into the cavern, pushing the air upward to mix with stored heat, which turns a turbine and produces electricity.
“Everybody has talked about long-duration storage for probably the past five years or so. The markets have not been there to pay for it at all. And that’s starting to change,” Jon Norman, Hydrostor’s president, told me.
Part of Hydrostor’s pitch is that its tech is a “proven pathway,” as it involves simply integrating and repurposing preexisting systems and technologies to produce energy. It’s also cheaper than lithium-ion storage, with no performance degradation over a project’s lifetime. Major investors are buying it — the company raised $250 million from Goldman Sachs in 2022, to be paid out in tranches tied to project milestones. At the time, it was one of the largest investments ever made in long-duration energy storage.
The company has operated a small 1.75 megawatt facility in Canada since 2019, but now with Goldman’s help it’s scaling significantly, developing a 500 megawatt grid-scale project in California in partnership with a community choice aggregator, as well as a 200 megawatt microgrid project in a remote town in New South Wales, Australia.
“Our bread and butter application is serving the needs of grids and utilities that are managing capacity and keeping the lights on all the time,” Norman told me. The company’s projects under development are designed to deliver eight hours of energy. “That’s what the market’s calling for right now,” Norman said, though theoretically Hydrostor could handle multi-day storage.
Standard lithium-ion batteries have shown that they can be economical in the eight-hour range too, though. Back in 2020, a coalition of community choice aggregators in California requested bids for long-duration storage projects with at least eight hours of capacity. While Hydrostor and numerous other startups threw their hats in the ring, the coalition ultimately selected a standard lithium-ion battery project for development.
While this could be viewed as a hit to more nascent technologies, Hydrostor said the process ultimately led to the company’s 25-year, 200 megawatt offtake contract with Central Coast Community Energy, which will purchase power from the company’s 500 megawatt project in California’s Central Valley, set to come online in 2030. But that long lead time could be one of the main reasons why Hydrostor didn’t win the coalition’s bid in the first place.
“When you consider the very pertinent needs for energy storage systems today in California and yesterday, a technology that is not due to come online for another six years – I don’t think you’re even yet at the cost comparison conversation,” Goldie-Scot told me, in reference to Hydrostor’s timeline. “It’s just, how soon can some of these companies deliver a project?” Generate recently acquired esVolta, a prominent developer of lithium-ion battery storage projects.
But ultimately, Norman says he doesn’t really view Hydrostor as in competition with lithium-ion. “We would even add [traditional] batteries to our system if we wanted to provide really fast response times,” he told me. He says the use cases are just different, and that he has faith that compressed air storage will eventually prove to be the superior option for grid-scale, long-duration applications.
Another company taking inspiration from pumped storage hydropower is Energy Vault. Founded in 2017, the Swiss company is pursuing a “gravity-based” system that can store up to 24 hours of energy. While the design of its system has shifted over the years, the basic concept has remained the same: Using excess grid energy to lift heavy blocks (initially via cranes, now via specialized elevators), and then lowering those blocks to spin a turbine when there’s energy demand.
The company raised $110 million from Softbank Vision Fund in 2019, but failed to find an immediate market for its tech. “When we founded the company, we started thinking long-duration was going to be required much more quickly, and hence the focus on gravity,” Rob Piconi, Energy Vault’s CEO, told me.
But instead of waiting around for the long-duration market to boom, the company went public via SPAC in early 2022 and reinvented itself. Now it makes much of its revenue selling the sort of traditional lithium-ion energy storage systems that it once sought to replace, and has made moves into the green hydrogen space, too.
“The near term difficulty for many of these long-duration storage companies is that we’re still relatively early on in the scaling of lithium-ion,” Goldie-Scot, told me, noting that prices for Chinese-made batteries have plunged in the past year. Generate usually only invests in tech that’s well-proven and ready to scale up. So while lithium-ion alternatives will look more and more attractive as the world moves toward full decarbonization, in the interim, “there’s a gap between that longer term need and where the market is today.”
Piconi agrees. “If you look at storage deployments 95% to 98% of them are all this shorter duration type of storage right now, because that’s where the market is,” he said, though he added that he’s seeing demand pick up, especially in places like California that are investing heavily in storage.
All that’s to say the company hasn’t given up on its foundational concept — its first commercial-scale gravity energy storage system was recently connected to the grid in China, and the company has broken ground on a second facility in the country as well. These facilities provide four hours of energy storage duration, which lithium-ion batteries can also easily achieve — but the selling point, Piconi says, is that unlike lithium-ion, gravity storage systems don’t catch fire, rely on critical minerals, or degrade over time. And once the market demands it, Energy Vault can provide power for much longer.
Still, the upfront costs of Energy Vault’s system can be daunting for risk-averse utilities. So in an effort to lower prices, the company recently unveiled a series of new gravity storage prototypes that leverage either existing slopes or multi-purpose skyscrapers. They were designed in partnership with the architecture and engineering firm Skidmore, Owings & Merrill, the company behind the world’s tallest building.
The market may not have been ready five years ago, Piconi told me. But “in 12 to 24 months, we’re going to start to see gravity pop up,” he projected.
But wait, there’s more. Perhaps one of the best use cases for lithium-ion alternatives is in onsite, direct heating and cooling applications. That’s what the Israeli company Nostromo Energy is focused on, aiming to provide cleaner, cheaper air conditioning for large buildings like offices, school campuses, hotels, and data centers.
The company uses off-peak or surplus renewable energy to freeze water, storing it for later use in modular cells. Then, as temperatures rise and air conditioning turns on, that frozen water will cool down the building without the need for energy-intensive chillers, which commercial buildings normally rely upon. The system can be configured to discharge energy for two-and-a-half all the way up to 10 hours.
“Because air conditioning is roughly half of the electricity consumption of a building, we can provide that half from stored energy. And that’s overall a huge relief on the grid,” Nostromo’s CEO Yoram Ashery told me.
While a lot of (my) attention has been focused on how thermal batteries can help decarbonize heat-intensive industrial processes, and much has been written about the benefits of electric heat pumps over gas-powered heating, cooling is sometimes overlooked. That’s at least partially because air conditioning is already electrified.
But as more of our vehicles, appliances, and systems go electric, strain on the grid is poised to increase, especially during times of peak energy demand in the late afternoon and evening as people return home from the office before the sun goes down. Nostromo’s system can help shift that load by charging either midday (when solar is abundant) or at night (when wind is peaking), and discharging as demand for AC ramps throughout the afternoon.
Goldie-Scot said thermal storage technologies like this “offer something that some of the other technologies that are purely power-focused cannot. But they are still competing against relatively cheap natural gas.”
The upfront cost of the system, $2 to $3 million, is also nothing to sneeze at. But Ashery says it will fully pay for itself after just five years, as building owners stand to see significant savings on their electricity bills by shifting their demand to off-peak hours.
While one could theoretically power a building’s AC system using large lithium-ion-batteries, “it’s a problem to put big lithium batteries inside buildings,” Ashery told me. That’s due to the fire risk, which could impact insurance premiums for businesses, as well as space issues — these batteries would need to be container-sized to run an HVAC system. “That’s why only 1% of energy storage currently goes into commercial/industrial buildings,” Ashery wrote in a follow up email.
Shang told me that he sees so-called “behind the meter” applications like this as promising early markets for long-duration storage tech, especially given that utilities are “pretty cautious to adopt these technologies on a large scale.” But ultimately, he believes that policy is what’s really going to jumpstart this market.
“For long-duration storage, it may look years ahead, but actually the future is now,” he said. Because some of these new systems take longer to design and build, Shang told me, “you have to invest now. For the policies, you have to be ready now to support the development of these [long-duration energy storage] technologies.”
The Biden administration is certainly trying. All energy storage tech — thermal, compressed air, gravity, and lithium-ion — stands to benefit from generous IRA tax credits, which will cover 30% of a project’s cost, assuming it meets certain labor standards. Additional savings can accrue if a project meets domestic content requirements or is sited in a qualifying “energy community,” such as a low-income area that derives significant revenue from fossil fuel production.
The Department of Energy’s ultimate goal is to reduce the cost of grid-scale long-duration energy storage by 90% this decade (with “long” defined as 10-plus hours). And last year, the DOE announced $325 million in funding for 15 long-duration demonstration projects.
So while the market might not be quite ripe yet for funky, alternative approaches to long-duration storage, support like this is going to be necessary to ensure that these technologies are proven, cost-effective and available as the grid decarbonizes and the need crystallizes.
“There is not currently a system-wide way of valuing long-duration energy storage while competing against gas, but there are customers and utilities that have shown a willingness, especially with federal and state support, to invest in these technologies,” Goldie-Scot said. “That I think is giving us the first real inkling of the role that the long-duration can play in this market.”
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What if, instead of maintaining old pipelines, gas utilities paid for homes to electrify?
California just hit a critical climate milestone: On September 1, Pacific Gas and Electric, the biggest utility in the state, raised natural gas rates by close to $6 due to shrinking gas demand.
I didn’t say it was a milestone worth celebrating. But experts have long warned that gas rates would go up as customers started to use less of the fossil fuel. PG&E is now forecasting enough of a drop in demand, whether because homeowners are making efficiency improvements or switching to electric appliances, that it needs to charge everyone a bit more to keep up with the cost of maintaining its pipelines.
Shortly after the rate increase went into effect, however, Governor Gavin Newsom signed a bill aimed at addressing this exact problem. The new law gives PG&E and other utilities permission to use money they would have spent to replace aging, leaky pipelines to pay for the electrification of the homes served by those pipes — as long as electrifying the homes is cheaper. Instead of investing millions of ratepayer dollars into the gas system, utilities can start to decommission parts of it, shrinking gas use and fixed costs in tandem.
PG&E actually already has the freedom to do this, and has even completed a fair number of projects. But the utility has had limited success, mainly because of an anti-discrimination law that gives building owners the right to stick with natural gas. It only takes one gas stalwart to thwart a whole neighborhood’s prospects for free electric appliances, since in order to keep delivering gas to that one household, the utility has to invest in the entire section of pipeline serving the area. A 2023 report showed that while PG&E had completed more than 100 projects, it hadn’t been able to convince clusters of customers larger than five at a time to convert.
The new law doesn’t fundamentally change the anti-discrimination rule, known as a utility’s “duty to serve,” but it does relieve PG&E and others of this duty if at least two-thirds of the homeowners served by a given section of pipeline consent to getting off gas. For now, the legislation limits utilities to executing 30 such projects. But for those 30, as long as two-thirds consent, the utility can now tell the holdouts that it is retiring the pipeline, and that they have no choice but to get on the electric bandwagon.
“If a supermajority wants it, it can move forward,” Matt Vespa, a senior attorney from Earthjustice who worked on the legislation, told me. “Which I think is probably a good place to start from. You want to have a place where there’s significant buy-in.”
This strategy, sometimes called “zonal decarbonization” or “targeted electrification,” is one that many climate groups are advocating for as a way to achieve an orderly and equitable transition off of natural gas. The approach most states have taken so far — providing subsidies that gently prod consumers into going electric — results in a random pattern of adoption that can benefit some homeowners while harming others. It also does nothing to deter gas utilities from investing hundreds of millions of dollars in maintaining, replacing, or building new pipelines each year — investments that are set up to be recouped from ratepayers over the course of decades.
California isn’t the first place in the world to experiment with targeted electrification. The Swiss city of Zurich began systematically shutting down sections of its gas system in 2021, giving affected users about a decade of warning and offering partial compensation for the cost of new equipment. In Massachusetts, the utility Eversource is piloting a unique neighborhood-scale electrification project. The company hooked up 32 residential buildings and a few commercial businesses in the city of Framingham to a new underground network of pipes that carry water rather than natural gas, which in turn connect to geothermal heat pumps that use the water to heat or cool the air inside. There are more than a dozen such “thermal energy network” pilot projects in various stages in Massachusetts, New York, Colorado, Washington, Vermont, Maryland, and Minnesota.
But the new California program is unique in its scale and approach. For one thing, it applies to all gas utilities in the state. Beginning next summer, they will each need to submit maps to the utility commission that identify potential pipeline replacement projects; then, in 2026, regulators will use those maps to designate priority areas, giving precedence to low-income communities and households that lack heating or cooling. By July of that year, the commission must establish the rules of the pilot program, including a methodology for utilities to determine when electrification is more cost-effective than pipeline replacement, and rules for how utilities can pay for the projects and recover costs.
PG&E supported the bill and worked closely with its authors on the language. The utility declined an interview, but emailed me a statement saying the legislation “enables cost-effective, targeted electrification projects which will help avoid more expensive gas pipeline replacements, reducing gas system operating costs, and support the state’s and PG&E’s decarbonization goals.”
Utilities will still be spending ratepayer money on the electrification projects, but far less than they would have spent on pipeline infrastructure. For the remaining gas customers, it’s still possible rates will go up, though by less than they would have otherwise. Mike Henchen, a principal in the carbon-free buildings program at RMI, told me these pilot projects alone are not going to pull so many customers away from the gas system that it will put upward pressure on rates. The law caps the program at no more than 1% of a utility’s customers.
Vespa, the Earthjustice attorney, told me he originally worked on a more ambitious version of the bill that would have required utilities to avoid any new investments in the gas system when electrification was a cheaper alternative. But it was pared back and made voluntary in order to get it through the legislature. “The hope is that we'll get projects off the ground, we’ll get proof-of-concept,” he said. “I think there was a need to demonstrate some successful stories and then hopefully expand from there.”
While these pilots make sense, economically, for a dual gas and electric company like PG&E, one big question is whether the state’s gas-only utilities like Southern California Gas will take the initiative. (SoCalGas did not respond to my inquiry prior to publication, but the company did support the legislation.)
Looking ahead, even if lawmakers do expand the program to authorize every cost-effective project, this model can’t transition the entire state away from gas. These projects are more likely to pencil out in places with lower housing density, where a given section of pipeline is serving only a handful of homes. A fact sheet about the bill published by its lead sponsor, state senator David Min, says that “zero emissions alternatives” to pipeline replacement are only technically feasible and cost effective for about 5% of PG&E’s territory. “Gas customers won't be able to pay for the decommissioning of the whole gas system, or even 50% of it,” said Henchen.
In the meantime, however, there’s lots of low-hanging fruit to pluck. Targeted electrification of just 3% to 4% of gas customers across the state could reduce gas utility spending by $15 billion to $26 billion through 2045, according to an analysis by Energy and Environmental Economics.
“It’s a modest step,” said Vespa of the new law. “But I do think it’s meaningful to start moving forward and developing the frameworks for this.”
Revoy is already hitching its power packs to semis in one of America’s busiest shipping corridors.
Battery swaps used to be the future. To solve the unsolvable problem of long recharging times for electric vehicles, some innovators at the dawn of this EV age imagined roadside stops where drivers would trade their depleted battery for a fully charged one in a matter of minutes, then be on their merry way.
That vision didn’t work out for passenger EVs — the industry chose DC fast charging instead. If the startup Revoy has its way, however, this kind of idea might be exactly the thing that helps the trucking industry surmount its huge hurdles to using electric power.
Revoy’s creation is, essentially, a bonus battery pack on wheels that turns an ordinary semi into an EV for as long as the battery lasts. The rolling module carries a 525 kilowatt-hour lithium iron phosphate battery pack attaches to the back of the truck; then, the trailer full of cargo attaches to the module. The pack offers a typical truck 250 miles of electric driving. Founder Ian Rust told me that’s just enough energy to reach the next Revoy station, where the trucker could swap their depleted module for a fresh one. And if the battery hits zero charge, that's no problem because the truck reverts to its diesel engine. It’s a little like a plug-in hybrid vehicle, if the PHEV towed its battery pack like an Airstream and could drop it off at will.
“If you run out of battery with us, there's basically no range anxiety,” Rust said. “And we do it intentionally on our routes, run it down to as close to zero as possible before we hit the next Revoy swapping station. That way you can get the maximum value of the battery without having to worry about range.”
To start, a trucker in a normal, everyday semi pulls up to a Revoy station and drops their trailer. A worker attaches a fully charged Revoy unit to the truck and trailer—all in five minutes or less, Revoy promises. Once in place, the unit interfaces seamlessly with the truck’s drivetrain and controls.
“It basically takes over as the cruise control on the vehicle,” he said. “So the driver gets it up to speed, takes their foot off the gas, and then we actually become the primary powertrain on the vehicle. You really only have to burn diesel for the little bit that is getting onto the highway and then getting off the highway, and you get really extreme MPGs with that.”
The Revoy model is going through its real-world paces as we speak. Rust’s startup has partnered with Ryder trucking, whose drivers are powering their semis with Revoy EVs at battery-swap stops along a stretch of Interstate 30 in Texas and Arkansas, a major highway for auto parts and other supplies coming from Mexico. Rust hopes the next Revoy corridor will go into Washington State, where the ample hydropower could help supply clean energy to all those swappable batteries. Happily, he said, Revoy can expand piecemeal like this because its approach negates the chicken-and-egg problem of needing a whole nation of EV chargers to make the vehicles themselves viable. Once a truck leaves a Revoy corridor, it’s just a diesel-powered truck again.
Early data from the Ryder pilot shows that the EV unit slashed how much diesel fuel a truck needs to make it down the designated corridor. “This is a way we can reduce a path to reduce the emissions of our fleet without having to buy anything — and without having to have to worry about how much utilization we're going to have to get,” Mike Plasencia, group director of New Product Strategy at Ryder, told me.
Trucking represents one of the biggest opportunities for cutting the carbon emissions of the transportation sector. It’s also one of the most challenging. Heatmap has covered the problem of oversized SUV and pickup truck EVs, which need larger, more expensive batteries to propel them. The trucking problem is that issue on steroids: A semi can tow up to 80,000 pounds down an American highway.
There are companies building true EV semi trucks despite this tall order — Tesla’s has been road-testing one while hauling Pepsi around, and trucking mainstays like Peterbilt are trying their hand as well. Although the EV model that works for everyday cars — a built-in battery that requires recharging after a couple hundred miles — can work for short-haul trucks that move freight around a city, it is a difficult fit for long-haul trucking where a driver must cover vast distances on a strict timetable. That’s exactly where Revoy is trying to break in.
"We are really focused on long haul,” he told me. “The reason for that is, it's the bigger market. One of the big misconceptions in trucking is that it's dominated by short haul. It's very much the opposite. And it's the bigger emission source, it's the bigger fuel user."
Rust has a background in robotics and devised the Revoy system as a potential solution to both the high cost of EV semis and to the huge chunks of time lost to fueling during long-distance driving. Another part of the pitch is that the Revoy unit is more than a battery. By employing the regenerative braking common in EVs, the Revoy provides a redundancy beyond air brakes for slowing a big semi—that way, if the air brakes fail, a trucker has a better option than the runaway truck lane. The setup also provides power and active steering to the Revoy’s axle, which Rust told me makes the big rig easier to maneuver.
Plasencia agrees. “The feedback from the drivers has been positive,” he said. “You get feedback messages like, it felt like I was driving a car, or like I wasn't carrying anything.”
As it tries to expand to more trucking corridors across the nation, Revoy may face an uphill battle in trying to sell truckers and trucking companies on an entirely new way to think about electrifying their fleets. But Rust has one ace up his sleeve: With Revoy, they get to keep their trucks — no need to buy new ones.
On the DOE’s transmission projects, Cybertruck recalls, and Antarctic greening
Current conditions: Hurricane Kirk, now a Category 4 storm, could bring life-threatening surf and rip currents to the East Coast this weekend • The New Zealand city of Dunedin is flooded after its rainiest day in more than 100 years • Parts of the U.S. may be able to see the Northern Lights this weekend after the sun released its biggest solar flare since 2017.
The Energy Department yesterday announced $1.5 billion in investments toward four grid transmission projects. The selected projects will “enable nearly 1,000 miles of new transmission development and 7,100 MW of new capacity throughout Louisiana, Maine, Mississippi, New Mexico, Oklahoma, and Texas, while creating nearly 9,000 good-paying jobs,” the DOE said in a statement. One of the projects, called Southern Spirit, will involve installing a 320-mile high-voltage direct current line across Texas, Louisiana, and Mississippi that connects Texas’ ERCOT grid to the larger U.S. grid for the first time. This “will enhance reliability and prevent outages during extreme weather events,” the DOE said. “This is a REALLY. BIG. DEAL,” wrote Michelle Lewis at Electrek.
The DOE also released a study examining grid demands through 2050 and concluded that the U.S. will need to double or even triple transmission capacity by 2050 compared to 2020 to meet growing electricity demand.
Duke Energy, one of the country’s largest utilities, appears to be walking back its commitment to ditch coal by 2035. In a new plan released yesterday, Duke said it would not shut down the second-largest coal-fired power plant in the U.S., Gibson Station in Indiana, in 2035 as previously planned, but would instead run it through 2038. The company plans to retrofit the plant to run on natural gas as well as coal, with similar natural-gas conversions planned for other coal plants. The company also slashed projects for expanding renewables. According toBloomberg, a Duke spokeswoman cited increasing power demand for the changes. Electricity demand has seen a recent surge in part due to a boom in data centers. Ben Inskeep, program director at the Citizens Action Coalition of Indiana, a consumer and environmental advocacy group, noted that Duke’s modeling has Indiana customers paying 4% more each year through 2030 “as Duke continues to cling to its coal plants and wastes hundreds of millions on gasifying coal.”
The Edison Electric Institute issued its latest electric vehicle forecast, anticipating EV trends through 2035. Some key projections from the trade group’s report:
Tesla issued another recall for the Cybertruck yesterday, the fifth recall for the electric pickup since its launch at the end of last year. The new recall has to do with the rearview camera, which apparently is too slow to display an image to the driver when shifting into reverse. It applies to about 27,000 trucks (which is pretty much all of them), but an over-the-air software update to fix the problem has already been released. There were no reports of injuries or accidents from the defect.
A new study published in Nature found that vegetation is expanding across Antarctica’s northernmost region, known as the Antarctic Peninsula. As the planet warms, plants like mosses and lichen are growing on rocks where snow and ice used to be, resulting in “greening.” Examining satellite data, the researchers from the universities of Exeter and Hertfordshire, and the British Antarctic Survey, were shocked to discover that the peninsula has seen a tenfold increase in vegetation cover since 1986. And the rate of greening has accelerated by over 30% since 2016. This greening is “creating an area suitable for more advanced plant life or invasive species to get a foothold,” co-author Olly Bartlett, a University of Hertfordshire researcher, told Inside Climate News. “These rates of change we’re seeing made us think that perhaps we’ve captured the start of a more dramatic transformation.”
Moss on Ardley Island in the Antarctic. Dan Charman/Nature
Japan has a vast underground concrete tunnel system that was built to take on overflow from excess rain water and prevent Tokyo from flooding. It’s 50 meters underground, and nearly 4 miles long.
Carl Court/Getty Images