Eronen’s first instinct: a massive water tank linked to solar thermal panels that could store heat, to be used in a district energy system. “Would that be economically and technically viable?” they wondered. The answer, as it turned out, was no. What they needed, instead, was a medium in which to store the high level of heat – as much as 650°C – generated by the electrical current flowing out of photovoltaic panels. That substance would have to be inert, non-combustible, not prone to melting or boiling, and cheap.

The answer, Eronen says, was essentially hiding in plain view: sand. It is abundant, as he says, “everywhere.”

That light bulb moment provided the spark for what would become Polar Night Energy, now a 25-person firm that develops sand batteries to serve industries and communities with renewable energy and district heating systems. Polar has developed two commercial sand batteries in Finland, and the company is developing a third near the village of Vääksy, as well as its first international project in Latvia. Eronen, who is the CEO, says Polar also plans to expand into northern European markets like Germany and Switzerland.

Soaring growth for storage

This particular innovation is the latest chapter in the evolution of the renewable-energy storage sector, which has become an indispensable element of the energy transition, particularly now that solar PV has become the least expensive form of electricity generation. Many utilities are deploying large-scale lithium battery installations as they incorporate more renewable sources, but other forms of storage – from traditional pumped hydro to more emergent technologies such as flywheels and aluminum batteries – are part of the mix.

According to a 2024 International Energy Agency report on the role of batteries in the energy transition process, “strong growth occurred [in 2023] for utility-scale battery projects, behind-the-meter batteries, mini-grids and solar home systems for electricity access, adding a total of 42 GW of battery storage capacity globally.” The IEA estimated that global energy storage capacity will have to increase by 1,500 gigawatts by 2030 to facilitate the amount of growth in new solar PV and wind required to achieve the Paris Agreement target of net-zero emissions by 2050.

With rapid projected increases in both electricity consumption and utility-scale solar farms, the role of large-scale storage will only grow in importance, Eronen says. “It means that we have to have very good batteries to take this excess energy at times when we have too much, and then obviously deliver it when we have too little.”

Sand stands out

If you want to understand Eronen and Ylönen’s insights about the role of sand, think about the experience of walking on a beach on a very hot day: the surface of the sand can be uncomfortably warm, but if you dig your feet in only a few centimetres, the temperature drops – evidence, Eronen says, of sand’s capacity to both absorb heat energy and provide natural insulation that prevents that energy from dissipating.

After graduating, the two inventors set up a small-scale sand battery in the backyard of Eronen’s grandparents’ cottage. The proof of concept worked and Polar Night was formed. They built their first pilot plant in Tampere, Finland, and then went on to deliver the world’s first commercial sand battery for the renewable energy supplier Vatajankoski, followed by the first industrial‑scale installation for Loviisan Lämpö, which provides district heating in Pornainen. Last year, they launched a €4.2-million pilot plant in the city of Valkeakoski, about 150 kilometres north of Helsinki, in partnership with Valkeakosken Energia, a district energy firm, to test a new version of the sand battery.

Polar describes its sand battery as both a power-to-heat (P2H) and a power-to-heat-to-power (P2H2P) technology: the former is what they’ve deployed so far, and the latter is still in pilot phase. For P2H, excess renewable electricity passes through a series of resistors, which throttle the current and become extremely hot. The hot air flows into the cylindrical sand battery. That thermal energy, in turn, can be drawn out as needed through a network of pipes and used for industrial process or district heating. Though still under development and not yet rolled out, Polar Night’s P2H2P technology uses the super-heated air to power a boiler that produces steam to generate electricity.

“We have patented a heat-transfer system that is taking the heat into the sand and away from it when we want to use it,” Eronen says. “We have lots of steel pipes going through the sand. The air and the sand don’t mix, ever.” He adds that large-scale cylinders – imagine something the size of an industrial oil storage tank – are the optimal shape for Polar’s technology and application (i.e., district heating), and the amount of storage they can provide increases in direct proportion to their size.

RELATED STORIES

Is the International Energy Agency bending to Big Oil?

With investment flowing, fusion energy’s long shot has become a gold rush

Trump’s war on wind is pushing investment north to Canada

The company’s technology, and its expansion strategy, received its first big boost a few years ago when a segment on the BBC’s website attracted half a billion views. Eronen says that as they’ve moved to commercial-scale projects, the company has begun bidding for contracts offered in “grid-balancing markets,” typically by transmission operators who need to add storage capacity as more renewable sources come on line.

The major advantage over other technologies is that Polar’s sand batteries can retain heat for up to 100 hours, whereas most other systems, like utility-grade lithium, provide only a few hours of storage between charges. The upshot: “They can charge with the lowest prices possible on the spot market,” Eronen says, “and also be very flexible when they offer that capacity to the grid-balancing markets.”

Perhaps the most appealing aspect of Polar’s invention has to do with its own environmental footprint. Unlike large-scale lithium batteries, for instance, Polar’s product consists of nothing more than sand, steel pipes and a steel silo. As Eronen says, “The life-cycle assessment will say that the emissions from sand batteries are one of the lowest, or even the lowest, of all battery technologies.”

A low-emission storage medium for the renewable-energy revolution seems like the right pairing to deliver the missing link in the energy transition.

Correction: The order of events in Polar Night’s company history was corrected from an earlier version. 

John Lorinc is a journalist and author specializing in urban issues, business and culture.

The post Finland’s giant sand batteries are starting to roll out across Europe appeared first on Corporate Knights.

Lauren Phillips’s balcony just became a power plant. A very small, carbon-free one.

A few weeks ago, the attorney set up what may be the first plug-and-play solar panel in the Bronx. The 220-watt installation, which is secured to the balcony railing with zip ties, has been a boon for the renter and mother of two. “I have an enormous childcare bill every month. My electricity bills never go anything but up,” Phillips says. ​“Everywhere you turn, things are only getting more expensive.”

Plug-in solar non-profit Bright Saver, which provided the roughly US$400 panel to Phillips at no cost, estimates that it will produce about 15% to 20% of the electricity her family uses and save her about $100 per year. Every time Phillips gazes at the device, she says, she’s amazed that ​“this is just a thing that I plugged in, and I’m generating my own power.”

Phillips is one of the few intrepid Americans installing DIY solar without the permission of their utilities, taking advantage of a regulatory grey area. Only deep-red Utah has a law, passed in March 2025, that explicitly allows residents to plug in these devices. A few thousand households there have installed systems so far, Bright Saver says.

But other states, including New York, could soon follow Utah’s lead and unleash much broader adoption of solar panels that plug into a standard 120-volt wall outlet. As of Wednesday, Democratic and Republican lawmakers in 27 states and Washington, D.C., had announced their own legislation to make these systems permissible, according to Bright Saver.

The post A giant wave of balcony solar could be coming to the United States appeared first on Corporate Knights.

Toby Heaps: Some people think the Inflation Reduction Act was a spectacular success. There are other views as well. What’s your take? Did the policy work?

Jigar Shah: I’m sure everybody is right. I think that we all have to be honest about the fact that the United States had chosen to allow its manufacturing sector to dwindle in a very big and material way, right from 30% of gross domestic product down to about 10% of GDP. I don’t think that what we were doing under the Inflation Reduction Act was going to be solely responsible for changing that trajectory.

I have a lot of friends who are doing very large, audacious things in the cleantech space, and every single one of them, without exception, when they hit a certain milestone, decided to build their manufacturing facility or their first-of-a-kind plant in Asia. A few of them decided to go to Europe or to India or to South America. In general, not a single one of them thought Tennessee or Georgia or Texas was the right place to scale up their plant.

That all changed over the last four years. We got every one of them to consider the United States, and I’d say close to 70% of them ended up choosing the United States after evaluating all of the situations. So from that perspective, we have made a material difference.

TH: That’s encouraging. In Canada, the current government led by Prime Minister Mark Carney has introduced a pack of investment incentives that, through the capital expensing of 100% and tax rebates, amount to about 50 cents on the dollar. So if you invest in most clean-economy investments, you’ll get back half that money in the same year. Do you think that is going to be enough for Canada to become a magnet?

JS: I would suggest that this is not really about numbers. I think that ultimately this is about the animal spirits of the cleantech sector. So the question is, are CEOs looking to Canada to build a facility? And I think right now, the answer is no.

And I don’t think Canada’s ever reached out to them and asked them to come to Canada. And the thing that bothers me the most – not just about Canada, but the U.K. or EU, Australia – is that they believe that the policies themselves are enough to attract companies. And I’m like, no, you need to make some phone calls. You need to reach out proactively to the top 400 companies and say, “Have you looked at Canada? Can I keep you on the phone for 45 minutes and explain it to you? Can I introduce you to a front-door person that will guide you through the entire Canadian process and introduce you to all of the three-letter acronyms and help you find the right programs?”

I’m focused on people who have raised at least $200 million of corporate capital. We’re not talking about the long tail of companies that have raised a seed round. We’re talking about people who’ve been able to get all their milestones reached, and now they’re at a very clear inflection point where they need public policy to be able to get to the next level.

TH: A lot of coverage in Corporate Knights magazine has focused on how the private sector and private capital can turbocharge this energy revolution. Do you think it’s capitalist Kool-Aid, this idea that the private sector is going to make up the bulk of the capital that gets deployed? Or do we really need the public sector to pony up, like they are now for the military spending?

JS: It’s an ongoing argument. I don’t know that I am smart enough to know what the conclusion is, but if you look at the solar, battery storage, critical minerals, EV sector in China, I would say that at least 70% of all the capital that China has put into that sector has been completely and utterly wasted right now. You may say, well, look at what they got for it: they have all this commanding market share and all this other stuff, right? But they haven’t ever raised their prices to the point where the profits of the winners are paying off the losses of the losers. China has no home runs. The question is, do you want to copy that exactly in the United States or Canada? My sense is no. So what do you want to do that’s different?

What we did in the United States was we said we’re going to be private-sector-led, government-enabled. We said the private sector has to vote with the $200 million worth of cash that they’ve given these companies, and then we’re going to match them with public-sector dollars that they need to get to the next stage, to really be able to get their costs down. And that worked really well. I would say the losses out of the U.S. system from the Inflation Reduction Act have been remarkably low. Let’s say we awarded 100 projects. Maybe 40 of them have failed, but of those 40, we’ve released almost no money because they had to meet certain milestones to get the money.

TH: You’re someone who doesn’t just focus on what’s already here but imagines what could be possible. Let’s say we’re sitting in our rocking chairs in 2050. What’s the prize? What could things look like?

JS: Well, I think we already see it. The beauty of our space is that every single thing worth talking about takes 50 years. We started seeing cellphones in the 1970s, but the technology didn’t really become powerful until the iPhone came out in 2007. Solar panels are the same.

When you look at where we are today, we’re in a place where there was disruption in Pakistan, in Nepal, in Ethiopia, and instead of choosing to move to diesel fuel, the entire country chose to move to solar and battery storage. So now, 20% of the entire grid in Pakistan has been transformed in three years into solar power.

You see the same potential in Canada or in the United States. Balcony solar means that you buy the solar panel from Home Depot, you unbox it, and you just stick it on your balcony, and then you plug it into the outside wall socket. And it’s super cost-effective, even in places that don’t get as much sun.

Now the question becomes what else is going to be cool? It is very obvious that everyone is moving to electric vehicles. Whether it’s 10% a year, or 25% or 50% a year, they’re all moving to electric vehicles. If you have 40 gigawatts of batteries, which is what we have already in the United States, and then you end up with 400 gigawatts of batteries [with the addition of EVs], which we will have here in the next few years – that backs up the entire U.S. grid during the spring and the fall. What do you need to unlock that? Vehicle-to-grid technologies. Why do people want to install those technologies? Because 15% of U.S. households already have backup gas or diesel generators, so they’ve already voted with their pocketbooks to pay for that.

Now if you have a car, and that car is a 125-kilowatt-hour battery, you can back up your whole house with that car. And once it’s backed up that way, well, now the utility can send it a signal saying, “We’re going to pay you 30 cents a kilowatt-hour, because otherwise we’ll have rolling blackouts because the natural gas plant that we were counting on failed, and so we’d like to pay you to basically save the grid.”

We’re in this situation where that technology works today, and when we’re in our rocking chairs in 2050, everyone will have them. They will be ubiquitous. And our children will say, “Well, duh, like, obviously.”

TH: When I talk to older utility guys, they kind of roll their eyes at the vehicle-to-grid idea and say, “Okay, well, tell me where that’s actually happening.”

JS: It’s happening at complete scale in the United Kingdom. It’s at a point where Octopus Energy is giving people free power on a regular basis to charge their electric vehicles. Because there’s a lot of excess wind and solar during certain times of the day. Remember, 90% of everything we need to do with the grid with electric vehicles can be done with managed charging, what they call V1G. Then there’s another 8% of what can be done with vehicle-to-home, where you never export back into the grid, you just take the home off-grid. So we could get 98% of the value without updating any of our standards that are in place now.

The 2026 Global 100 list puts speed in the spotlight

TH: Do you think geopolitically, has China sort of got themselves in a dominant spot that’s going to be pretty significant for this next century?

JS: China has clearly overplayed their hand. I think they don’t know it yet, but they have. Xi Jinping has been in power too long. And now he’s pissed off everybody. He’s pissed off India, Turkey, Malaysia, Vietnam – anyone who manufactures stuff, he’s pissed off all of them. So now the question becomes how long can they continue to lose money?

Remember, we have many more iterations of technology that you and I know about. Like, solar panels are not done, right? We got perovskites and other things that are coming in. Electric vehicles are not done. We have technologies in the queue that’ll double the energy density of lithium-ion batteries. We have no reason to share any of that technology with China now.

So when we decide not to share that technology with them and instead share it with India or Mexico or other places, we’ll see where it goes. Yes, it’s going to take us a solid 10-year effort to actually diversify the supply chain, which is exactly how long it took after the Arab oil embargo for us to diversify the supply chains for oil. We know how to do it. It’s a playbook. We’re executing on it now, and I think in 10 years’ time, we’re going to be quite a bit more diverse.

Toby Heaps is co-founder and publisher of Corporate Knights.

The post How to scale up the green economy appeared first on Corporate Knights.

The plant is designed to use Alberta natural gas to produce hydrogen, a clean-burning fuel that is used in refining and could replace oil and gas in a range of applications, including transportation and electricity. Air Products says the plant will capture some 95% of the carbon dioxide it emits and sequester the greenhouse gases in saline aquifer formations deep underground. In short, it was touted as a model for carbon capture and storage (CCS) technology that proponents say can dramatically reduce carbon emissions in the oil and gas sector, as well as in the cement, chemicals and steel industries.

Now, CCS proponents are about to face their biggest test, as Ottawa and Alberta put their weight behind a multibillion-dollar project in the oil sands. 

Fading promise

In 2022, both governments were on board for Air Products’ Edmonton blue hydrogen plants. “We need to be bold and seize the moment, and that’s exactly why we’re investing in Air Products,” François-Philippe Champagne, then the industry minister, said in a 2022 news release. 

The federal government pitched in $300 million from its strategic innovation fund, alongside Alberta’s $161-million contribution to what was pegged to be a $1.6-billion project. The plant was slated to create 2,500 construction jobs, along with 230 “highly skilled jobs.” Above all, the initiative was billed as “another major step forward on the path to net zero,” the federal government said. 

Fast forward three years, and the sheen has faded, amid delays and cost overruns that have doubled the price tag, to US$3.3 billion.

In an investor call last summer, the company labelled the Edmonton operation an “underperforming asset” not expected to be profitable. The plant was originally due to open last summer; projections now put the ribbon-cutting into late 2027, perhaps 2028. Air Products had pinned its hopes on supplying a growing hydrogen market, which so far has failed to materialize. 

Keeping the faith

Despite that setback, CCS technology still plays an important role in Canada’s net-zero ambitions and is a key plank in the government’s climate competitiveness strategy unveiled in the November budget. Prime Minister Mark Carney and Energy Minister Tim Hodgson are counting on CCS to deliver emission reductions even as they support expansion on oil and gas infrastructure that will increase exports and production. 

On November 27, the prime minister announced an agreement in principle with Alberta Premier Danielle Smith, in which Ottawa will support a bitumen pipeline to the West Coast, in exchange for provincial agreement on a higher carbon price and industry investment in CCS.

Carney has focused on CCS as a key to reducing emissions in the oil and gas sector. The Pathways project will be “the largest carbon capture utilization and storage project in the world,” he said in a speech to the Calgary Chamber of Commerce. “It will make Alberta oil amongst the lowest carbon intensity in the world, and it has the potential to create an entirely new industry in Canada.”

At the same time, proponents are touting CCS as a key means of cutting emissions in industrial sectors like cement and steel.

Despite the ongoing enthusiasm in Ottawa, the Air Products failure serves as a warning to the Liberal government and other would-be investors. Scaling up CCS will require huge subsidies. Just how much investment risk corporations will take on it remains up in the air. And in Canada, the tension between climate policy and a powerful petroleum sector is on full display, adding another layer of uncertainty.

Environmental groups argue that CCS is being used as a panacea to justify continued production and use of oil and gas, which will make it harder and more costly to deal with climate change in the coming decades. The majority of emissions from a barrel of oil, after all, come from its combustion in cars, planes, ships and other end uses.

“The narrative around so-called decarbonizing oil is nothing but a myth to justify expansion of oil production,” says Aly Hyder Ali, oil and gas manager at the Canadian advocacy group Environmental Defence. 

An expensive proposition

Canada is not alone in pursuing CCS. It remains an important component in decarbonization strategies produced by groups like the International Energy Agency and the United Nations’ Intergovernmental Panel on Climate Change. To date, there are 77 commercial projects in operation globally capturing up to 64 million tonnes of carbon dioxide per year, with 47 more under construction. However, few of those target oil production facilities like Canada’s oil sands. Norway’s Sleipner project, for example, is the world’s first commercial CCS facility and is located in an offshore natural gas field.

Norway-based consulting firm DNV Group anticipates the world will spend some US$80 billion on CCS projects between now and 2030. Much of that investment will be focused on natural gas processing and cement and steel producers, DNV said in a report released last summer.

But there remain huge hurdles to investment. In addition to prohibitive capital costs, CCS drives up operating costs at existing plants and can be energy intensive.

In search of profitability

Canada’s cement industry has focused on CCS as part of its plan to be net-zero by 2050. To date, however, no company has made an investment in a CCS facility. “The only way to make this work is if there is a path to profitability,” says Sarah Petrevan, vice president for industrial decarbonization at the Cement Association of Canada. “And there is no path to profitability.” 

To help make CCS financially viable, Carney’s first budget seeks to increase the industrial carbon tax and make it apply to a greater percentage of a company’s emissions. The levy applies to a portion of emissions from the country’s largest polluters. It now costs $95 per tonne of carbon dioxide and is due to rise. 

A more costly carbon tax is intended to incentivize businesses to invest in multibillion-dollar emission-reduction projects, like CCS. Ottawa is also providing companies with a type of insurance, known as contracts for differences, which compensates investors if carbon prices fall below project costs.

Six places to store a trillion tonnes of carbon

The oil industry is selling carbon capture as a way to boost production

Mark Carney trades climate allies for controversial oil-patch solutions

The industrial carbon price “plays a big role in determining the economic viability of various low-carbon projects,” Dale Beugin, research director for the Canadian Climate Institute, wrote in an explainer. “But the risk of future governments moving away from that carbon pricing pathway dilutes the policy certainty – and the incentive to invest in clean growth projects.” 

However, the levy won’t work to drive investment unless it has greater stringency and applies to a greater percentage of a plant’s emissions, Beugin argues.

The Alberta showdown

After the budget’s release, Petrevan welcomed the government’s climate-competitiveness pledges. She hedged, however, on whether the budget measures would provide a “path to profitability” for CCS projects. “Stability and predictability of the industrial carbon price are important contributors to building a positive business case for investment.” 

However, the federal government will have to find “alignment” with the provinces, Petrevan says. (Ottawa sets benchmarks for the industrial levy, but most provinces administer their own systems.) Alberta – home to the vast oil-sands sector – froze the price at $95 earlier this year. More recently, it proposed to allow a broader range of investments to count toward a company’s compliance requirements and allowed smaller firms to opt out completely.

The changes would reduce demand for the credits that companies receive when they succeed in reducing emissions. Cheaper credits would result in lower return on investment, and therefore less spending on emission-reduction technology.

The federal–Alberta memorandum signed in November commits the two sides to working together to “design and commit to globally competitive long-term carbon effective prices.” Alberta agreed to unfreeze the price to rise to $130 over the next three years.

The carbon price still won’t be enough to drive investment in CCS, says Chris Bataille, a Vancouver-based fellow with Columbia University’s Center on Global Energy Policy. With the enforcement mechanism related to pipeline progress, “it has to become basically a regulatory outcome,” he says. “That doesn’t mean post-combustion CCS will work or that the feds will enforce the deal. But Alberta gets to push forward its pipeline.”

Oil-sands companies working together under an umbrella organization dubbed the Pathways Alliance have released their own plan for emission reductions that relies on heavily subsidized CCS and a strong carbon credit market. 

The federal–provincial memorandum endorses the industry plan, and Ottawa and Alberta pledge to work with the oil companies in advancing the plan, with construction starting by 2027.

Corporate investment in CCS is contingent on the approval, commencement and continued construction of the pipeline, while ongoing progress with the pipeline will be contingent on the Pathways plan moving ahead. The federal government also agreed to drop its proposed cap on emissions from the oil and gas sector.

Bataille argues that Ottawa needs the threat of a cap as a stick. “Without the emissions cap as leverage – get these [emissions] cuts done or we will do this – I don’t see it happening,” he says. 

A subsidized market

It’s clear that without government intervention, carbon capture will not take root. The Pathways Alliance has laid out a $16.5-billion CCS plan that would require significant tax breaks. Even with those subsidies, it’s questionable how many carbon-capture projects would be built given the long-term financial risks and technological issues.

A key problem is that government policy is by its nature uncertain, especially given that Carney presides over a minority government that has a precarious hold on power. Any promise by Ottawa to set a floor under the cost of emitting and guarantee profitability for CCS could be quickly undone by a new federal government that would share Alberta’s opposition to aggressive climate action. Conservative Leader Pierre Poilievre – who came within 25 seats of winning the March election – has shown little enthusiasm for climate policy and promised to unshackle the oil and gas industry. 

In the United States, President Donald Trump has scuttled virtually all the climate measures adopted under Joe Biden.

Given those risks, corporate CEOs will be reluctant to invest in CCS projects that are bolted onto existing production facilities and generate no revenue except through regulatory means, Bataille says. The promise of a pipeline may, however, be the carrot that drives action.

Momentum continues 

Carbon capture itself isn’t novel, but its application for large-scale underground storage remains unproven over the long term. 

The fossil fuel industry already captures carbon dioxide for natural gas processing plants and injects the gas into old wells to enhance oil production. The Pathways plan would largely sequester carbon in saline aquifers rather than sell it. Worldwide, there is much less space underground for injected carbon than previously thought: less than a fifth of what the Intergovernmental Panel on Climate Change has estimated, according to a recent study by researchers at Imperial College London.

Carbon capture also isn’t widely applicable. In upstream oil-sands production, a large percentage of emissions result from burning natural gas in boilers to produce steam needed to extract bitumen, and from burning diesel in large trucks and other machinery. CCS would not currently be viable for either of those sources.

Sean McCoy, a professor at the Schulich School of Engineering at the University of Calgary, estimates that roughly 60% of carbon emissions in the oil-sands sector “might be capturable” with CCS. Despite the challenges, CCS continues to find support from government, even as the list of cancelled projects grows longer. Just last year, Edmonton-based Capital Power pulled the plug on a proposed $2.4-billion CCS project at its Genesee gas-fired generating station. “Through our development of the project, we have confirmed that CCS is a technically viable technology,” the company said in its statement. “However, at this time, the project is not economically feasible.”

The reality gap

Among the projects that have materialized, there is also a gap between carbon-capture promise and reality. A recent report from the Institute for Energy Economics and Financial Analysis (IEEFA) noted that claims of capture rates of 90% or more are misleading. Typically, the promise of higher capture rates applies only to concentrated streams of emissions at the specific types of plants.

In the oil and gas industry, CCS is used for natural gas processing plants that purify the fuel by removing contaminants like water, carbon dioxide, hydrogen sulphides and solids. And it includes facilities that produce hydrogen from gas for use in oil-sands upgraders and refineries.

Even at natural gas processing and hydrogen plants, carbon-capture rates rarely exceed 70% of emissions, the IEEFA report said.

Some projects, including at Air Products in Edmonton, are employing a new technology to produce hydrogen: autothermal reforming, which replaces steam methane reforming. Autothermal reforming is both more energy efficient and more capital intensive than the steam methane process. It also creates a more concentrated emission stream. 

CCS is best suited for applications that have high carbon dioxide concentrations in their flue gas and have high and stable flow emissions. In other words, facilities that burn hot and steady. 

Even in the bullish forecast by Norway’s DNV Group, CCS would capture only 6% of global emissions in 2050, a level that falls well short of what the consultancy says is needed to achieve any net-zero outcome.

“Recent turmoil, and budgetary pressure in the global economy pose risks to CCS deployment, potentially shifting priorities and removing the necessary finance,” the DNV authors wrote.

While some CCS will be viable, overly optimistic reliance on CCS is a trap if it is used to support delays in other emission-reduction strategies. The more we delay the transition away from fossil fuels, the more we will have to rely on hugely expensive carbon-capture strategies.

Shawn McCarthy is an Ottawa-based writer and senior counsel with Sussex Strategy Group.

The post Canada’s risky gamble on carbon capture and storage appeared first on Corporate Knights.

Fires have traditionally burned an average of 2.5 million hectares of land in Canada yearly. But the 2023 fires were unusually large and widespread: by mid-July, 29 megafires, each exceeding 100,000 hectares, left a trail of destruction across the country. Canada released 647 megatons of carbon that year, generating approximately 31% of the global emissions from wildfires.

This year, wildfires swept across northern Manitoba and Saskatchewan. Smoke permeated the atmosphere in central Canada, the Great Lakes region and the northeastern United States, compromising air quality and reducing visibility in major cities.

Looking not too far into the future, the amount of forest burned by wildfire is projected to double as a result of a changing climate.

“A warming planet is contributing to longer fire seasons,” says Mike Flannigan, professor of wildland fire at Thompson Rivers University. “Alberta’s fire season used to start in April. Now we’re seeing fires in March and February. The warmer the planet gets, the more lightning we expect. And the atmosphere gets more efficient at sucking moisture out of vegetation, the fuel for fire. The drier that fuel on the forest floor is, the higher the intensity of the fire, which is difficult to impossible to extinguish.”

Given the new reality, the burning question is how can Canada be better equipped to battle blazes that have increased in intensity and size, especially in the boreal forests? 

Fight smarter with precision tech

Earlier this year, the federal government announced a new wildfire-fighting initiative called WildFireSat, which will be the first government-owned satellite mission specifically designed to monitor all active wildland fires across Canada on a daily basis.

Spending money on more resources to extinguish larger fires is a waste. You want to get the fire at the start. That’s where the investment needs to be.

 – Mike Flannigan, wildland fire expert, Thompson Rivers University

Set to launch in 2029, seven microsatellites will feed the tracking information back to fire-management authorities. The data is intended to help those on the front lines identify high-risk wildfires and deploy resources and crews more strategically.

In recent years, start-ups have been testing a variety of tools to aid in battling forest fires. One company, Pano, makes AI-enabled cameras to spot wildfires; another called Rain has been piloting autonomous helicopters to douse them. Others have developed satellites and drones to monitor forests and weather.

Flannigan explains: “Say we’ve got 100 new fires. Which ones do we fight? What if we’ve only got enough resources to fight 20? Which are the important ones to fight, and which are the ones we can deal with later or just let Mother Nature run her course? Using machine learning helps make an informed decision when faced with that kind of situation.”

In a related effort, researchers at the University of British Columbia’s Okanagan campus and B.C. Wildfire Service, the province’s wildfire-suppression service, have formed a partnership to develop a provincial wildfire camera network. Using 5G technology, the cameras detect smoke from wildfires and share real-time data to support evacuation planning, resource deployment and wildfire behaviour predictions.

The Washington Post reports that, since 2023, more than 100 new wildfire-related technologies have launched in the United States and around the world. Many employ artificial intelligence in wildfire detection, such as FireSat, an initiative undertaken by the non-profit Earth Fire Alliance, with funding from Google and the Moore Foundation. Drawing on “high-res multispectral satellite imagery,” FireSat is designed to feed updates in 20-minute intervals to first responders, citing the location of active fires. The data will be accessible through phones, tablets and laptops. A prototype was deployed in March this year.

For now, though, firefighters mainly rely on people to alert them of a wildland blaze. To facilitate reporting, some provinces have created apps specifically to call in a fire. B.C. Wildfire Service’s mobile app features a “Report a Fire” function that automatically generates the coordinates of a fire’s location and sends them directly to the closest fire-management agency.

The high cost of forest fires

Economic losses due to forest fires are significant and likely to rise if current fire trends continue. Assistance funds now average about $340 million per year; in 2016/2017 and again in 2020/2021, the Disaster Financial Assistance Arrangements program paid $1.7 billion in assistance. (According to a government media release, WildFireSat is expected to save the Canadian economy between $1 billion and $5 billion over its first five years of operations.)

The 2016 wildfire in Fort McMurray, Alberta, is considered the costliest natural disaster in Canadian history at an estimated $9 billion in direct and indirect physical, financial, health and environmental impacts.

Equally alarming are the health impacts of smoke inhalation. Research suggests that as many as 1.5 million people die globally every year as a result of wildland fire smoke. Even short-term exposure is detrimental as it can lead to bronchitis, worsen asthma and create other health problems, as reported by the U.S. Environmental Protection Agency.

And there is the environmental cost, which itself contributes to worsening the main cause behind bigger, more frequent wildfires: a warming planet. Boreal forests have historically helped to slow climate change by storing carbon as trees grow rather than adding carbon dioxide to the atmosphere. Forests absorb approximately a quarter of global carbon emissions.

With forest fires burning more than twice as much tree cover as they did 20 years ago, this vital carbon sink is shrinking.

The window of opportunity

Canada has been warming at about twice the global rate. Average temperatures in 2023 between May and October were 2.2°C above the norm over the previous 30 years and were largely responsible for the unusual weather patterns that fuelled the fires. Which is all to say that wildfire season will continue to last longer and burn more fiercely than before.

Flannigan believes fire-management plans should prioritize quick and early containment of wildfires to realize the highest return on investment. “Every fire starts small, whether it’s a campfire or lightning strike. That’s our window of opportunity,” he says. “Spending money on more resources to extinguish larger fires is a waste. You want to get the fire at the start. That’s where the investment needs to be.”

Read more of our wildfire coverage

Canadian groups call for dramatic increase to wildfire defence funding

Massive wildfires are forcing governments worldwide to budget more for disaster

Canada is under attack by wildfires. It’s time to respond like it’s national defence.

Emerging research reveals stark health threats from wildfire smoke

Flannigan also highlights the importance of establishing a centralized agency solely dedicated to addressing natural disasters. “[Canada needs] an agency like the U.S. Federal Emergency Management Agency to deal at the national scale with floods, earthquakes, hurricanes and fire,” he says, noting that each province and territory devises its own fire-management plan and may not be in a position to share resources when a neighbouring region requires extra support.

Most Canadians agree that such an agency should be created. Recent polling conducted by Abacus Data shows there is overwhelming support for a national forest-firefighting unit. As Flannigan succinctly observes, “We live in a flammable environment.”

Victoria Foote is a writer and editor who specializes in clean energy and climate.

The post The fight against wildfires is getting increasingly high-tech appeared first on Corporate Knights.

This story was originally published by Canary Media. It has been edited to conform with Corporate Knights style.

XGS Energy, an advanced-geothermal start-up, says it has completed crucial testing that proves its novel technology can operate reliably at commercial scale – without losing a drop of water in the process.

The post Closed-loop geothermal is getting a big boost in New Mexico appeared first on Corporate Knights.

Canada Nickel Company expects to reach a final investment decision early in 2026 on a sprawling, low-emissions nickel mine and refinery near Timmins, Ontario, subject to permit approval and some government financial support.

The nickel is found in ultramafic rock, which can absorb carbon dioxide through a chemical process that stores it in carbonate form. The Canada Nickel refinery would create a concentrated stream of the carbon dioxide that would be more efficiently captured by the rocks. It can also use biochar – a by-product of forestry material – to replace coke or coal and reduce emissions in the processing.

The post Canada could soon add a major link in the domestic EV supply chain appeared first on Corporate Knights.

This story was originally published by Canary Media. It has been edited to conform with Corporate Knights style.

Commonwealth Fusion Systems just raised $863 million in additional funding as the company works to achieve the decades-old dream of commercializing nuclear fusion.

The post Investment in fusion energy is spiking appeared first on Corporate Knights.

A quaint northerly outpost of Napa Valley wine country, Calistoga has struggled to keep the lights on when wildfires strike the region. Now it’s got a brand-new microgrid to run the whole town for days on end without any onsite fossil fuels, just batteries and liquid hydrogen.

After disastrous conflagrations in 2017 and 2018, utility Pacific Gas & Electric began preemptively shutting off power lines to avoid sparking fires amid dangerously dry, windy conditions. “We were the first community in all of PG&E’s network that was getting our power shut off to protect us,” says Calistoga City Council member Lisa Gift. ​“By 2019 we were one of the first communities to have a microgrid in all of PG&E’s network, and that was being powered by diesel generators.”

PG&E arranged a bank of truck-based diesel generators to sit in the town during fire season. When the utility cut grid power, the generators kicked on, belching smoke in a particularly beloved pocket of the 5,000-person community. “We’re a small town, so they would come up and they’d be polluting the environment, taking up our dog park – loud, gross, noisy,” Gift recalls.

Now the diesel generators are gone and the park has been turned back over to Calistoga’s canine companions.

Community microgrids are the future of the energy system.

– Craig Lewis, executive director, Clean Coalition

On a slim parcel of city land next door, publicly traded energy-storage company Energy Vault installed lithium-ion batteries and a 234-foot, reinforced-steel tank for liquid hydrogen (designed to withstand a roaring fire, should it ever come to that) that runs a bank of hydrogen fuel cells.

Altogether, this compound should be able to meet Calistoga’s electricity needs without any power from the broader grid. It’s contracted to produce up to 8.5 megawatts for 48 hours, whenever PG&E shuts off grid power because of fire concerns. Refilling the hydrogen tank could let it run for several days more.

Showcasing a speculative technology

“Even though we’re taking elements – fuel cells, batteries, liquid hydrogen storage and distribution – that have been used before in commercial settings, they’re coming together for the first time as resiliency,” says Craig Horne, Energy Vault’s senior vice president for advanced energy solutions, in an interview before the project’s unveiling in early August.

Fans of hydrogen hail it as a solution to just about any entrenched decarbonization challenge, from heavy transport to steelmaking to on-demand power. But how hydrogen is produced makes a huge difference in its climate impact; seemingly clean sources can actually rack up major carbon emissions for negligible benefit.

For now, the clean hydrogen economy remains largely speculative, with hardly any truly clean hydrogen being produced or any real projects using it. Many planned clean hydrogen projects have vanished without a trace, following a short-lived boom fuelled by Biden-era support.

In Calistoga, Energy Vault has tapped hydrogen to deal with a very specific set of constraints – delivering energy without local emissions, over multiple days, in a tight footprint – but the cleanliness of that hydrogen is a more complicated issue than public descriptions of the microgrid suggest.

A high-stakes energy solution

The key players all have a lot riding on the project.

Energy Vault, which previously raised several hundred million dollars in a singular bid to store energy with multi-storey robotic cranes that stack blocks, wants to build a new long-duration storage business around this hydrogen microgrid showcase.

Plug Power, the financially challenged hydrogen company, points to Calistoga as its largest deployment of hydrogen fuel cells: a beefy eight megawatts, after 28 years of hard work.

And PG&E has orders from regulators to add more clean energy microgrids in communities where it regularly cuts off power. Calistoga was its first delivery on that directive, after a few years of soliciting proposals and a couple more years of permitting and construction. “Community microgrids are the future of the energy system,” says Craig Lewis, who advocates for such projects as executive director of the Clean Coalition non-profit. The Calistoga microgrid is ​“a commercial-scale experiment, and I’m grateful for it.”

The results of that experiment will take time to analyze. It could unleash a new, replicable model for premium-priced community-level backup power. Or the quirkiness of the design and the murkiness of hydrogen’s supply chain and emissions could make it a quixotic outlier of questionable climate value.

Power that’s cleaner and more compact

The Calistoga microgrid poses an answer to the question of how to provide a few days of backup power to a small town in a small space, without worrying too much about cost. The limitations drove the design, which turned out quite unlike anything built thus far. Energy Vault had to figure out how to pack 293 megawatt-hours of storage into just two-thirds of an acre. The lot used to hold debris from city works, like old bits of sidewalk and pipes, Horne says.

Lithium-ion batteries have proven themselves capable of storing power, be it as a Powerwall in someone’s garage or as a large-scale grid storage facility. But to store nearly 300 megawatt-hours, grid battery enclosures need more acreage than was available to lease from the city. Even if enough batteries could fit, the auxiliary power consumption for keeping them safely cooled would pose a challenge for a project that’s supposed to mostly sit around waiting for an emergency event.

Hydrogen gas can be liquefied by cooling it to ultra-low temperatures, which unlocks greater energy density. When converted back to gas and run through fuel cells, it produces a stream of electricity and no byproduct besides water vapour. That core technology powers hydrogen vehicles, though their cost and inconvenience make for a widely derided car-ownership experience.

At Calistoga, the hydrogen flows directly to six Plug Power GenSure 1540 fuel cells, boxy containers with cooling units stacked on top, making them about two storeys tall.

The engineers added a small lithium-ion battery (7.7 MW/11.6 MWh) to perform ​“black start,” the complicated and crucial task of rebooting an electrical system after a complete blackout, Horne notes. The battery also buffers the output of the system while the hydrogen gets up and running. Then the power flows to Calistoga’s grid, which, when PG&E shuts off the transmission lines, will be fully islanded from the surrounding network.

The hydrogen is stored onsite in an 80,000-gallon tank, manufactured in Minnesota by Chart Industries. The tank holds enough to power the fuel cells for about two days, but Energy Vault will try its best to keep the lights on beyond the contracted timeframe, Horne says. So the company made sure the tank can be refuelled while it’s in active use. “The task is to squeeze toothpaste into a toothpaste tube that was being squeezed,” Horne says. ​“That’s what we proved in our acceptance testing, running for multiple hours while the fuel cells were running and a tank trailer here in the driveway is pushing liquid hydrogen into the tank itself.”

How clean is ‘clean hydrogen’?

The microgrid’s promise as a clean energy breakthrough, of course, hinges on the supply of clean hydrogen, but supply chains are barely getting started. Almost all commercial hydrogen is currently made from methane gas, a fossil fuel, through a procedure called steam methane reforming that sends the carbon dioxide byproduct straight into the atmosphere.

For hydrogen to stake any claim as a climate solution, it needs to be made without massive carbon emissions. That usually involves an alternative production method called electrolysis, which separates hydrogen from water using electricity. But this method can produce even more emissions than the dirty methane version if the electrolyzers are drawing power from the grid rather than dedicated renewable sources like solar and wind.

Energy Vault describes the hydrogen it’s using in Calistoga as ​“clean,” which Horne clarified as meeting the federal standard of no more than four kilograms of carbon dioxide emitted per kilogram of hydrogen produced. But he declined to name the source. Notably, California has subsidized hydrogen fuelling stations for more than a decade but still hasn’t managed to develop a clean hydrogen supply in-state. So for Calistoga’s hydrogen to be clean, it must be coming from somewhere else.

We can do more and waste less, and so that’s how we can be more cost effective.

– Craig Horne, senior vice president for advanced energy solutions, Energy Vault

During a tour of the microgrid, Deepesh Goyal, vice president of stationary power at Plug Power, told Canary Media that Plug Power currently supplies hydrogen from its electrolyzer site in Georgia, which runs on grid power. More than half of Georgia’s electricity comes from fossil fuels, so that electrolysis incurs substantial power-plant emissions. Plug Power buys credits for clean energy supply to compensate for this, Goyal says.

To meet the highest federal standard for clean hydrogen, producers need to obtain clean power matched to their consumption on an hourly basis in the areas where they operate. Plug Power did not respond in time for publication to questions clarifying what type of credits it buys. But a spokesperson for Energy Vault told Canary Media that currently there aren’t any facilities that could supply Calistoga with liquid hydrogen from electrolysis powered by time-matched, dedicated clean electricity, and the earliest such facility is targeting completion in 2026.

Goyal also says some of Calistoga’s hydrogen comes from an unnamed partner in Las Vegas that uses renewable natural gas (RNG) as its feedstock. As it happens, legacy gas supplier Air Liquide opened a steam methane reformer in that area a few years ago to serve California’s demand. Air Liquide says it can substitute RNG for the usual methane, which would make the resulting hydrogen carbon-negative according to the convoluted calculations of California’s clean-fuels bureaucracy.

It’s still hydrogen made by splitting methane and releasing carbon dioxide, but it looks good on paper thanks to controversial rules that privilege certain politically connected providers of RNG.

A climate solution that’s less than ideal

If someone were to design a climate solution from a blank slate, they probably wouldn’t run electrolyzers on grid power in Georgia in order to load the super-cooled hydrogen onto diesel-powered tankers and haul it more than 4,500 kilometres to Northern California, where it will sit around almost every day awaiting a utility power outage. “We still have to truck in that hydrogen,” Gift says. ​“That’s not ideal, but we were trucking in the diesel, and we were trucking in the diesel sometimes three times a day and burning that diesel.”

One incontrovertible fact is that the microgrid doesn’t combust anything onsite, so the operations within the fenceline emit almost no carbon emissions and don’t affect air quality. But it will be hard to gauge the real climate impacts of such a project until a more verifiably clean and geographically localized hydrogen supply chain develops.

Several companies have said they will build truly green hydrogen production in the coming years. That task has grown only more difficult with the Trump administration’s efforts to thwart renewables development and vastly curtail clean hydrogen tax credits.

Confronting the outsized costs of liquid hydrogen backup

The other make-or-break variable for hydrogen-backed resilience is how much it costs. Liquid hydrogen is an expensive, specialty fuel produced by only a handful of suppliers in the United States, and clean liquid hydrogen is even rarer.

For this first project, Energy Vault didn’t need to worry about consumer price sensitivity. The city of Calistoga isn’t paying Energy Vault for backup power: PG&E is paying the company to provide this service, out of funds socialized across the utility customer base. In fact, Calistoga is making some money, since Energy Vault leased the land from the municipality for 10 years.

The project’s total price tag has not been made public. Regulators allocated up to US$46.3 million for PG&E to spend on the endeavour. Energy Vault closed $28 million in project financing this spring to support construction. The company also said on Thursday that it has raised $300 million to launch Asset Vault, a subsidiary that will build, own and operate storage projects, with Calistoga as one of two anchor properties.

Horne allows that the hydrogen microgrid costs more than diesel generators up front, but argues that it can be competitive in terms of operating costs, given all the hassles associated with diesel. “We can do more and waste less, and so that’s how we can be more cost effective,” he says.

The regulatory authorization paints a different picture. The California Public Utilities Commission explicitly allowed PG&E to spend more money than the diesel generators cost in order to test a new model for cleaner resilience. “This project was supported by a CPUC plan that said we could build a solution that costs no more than twice what it would cost to deploy diesel generation over 10 years,” says Jeremy Donnell, a senior manager for microgrid strategy and implementation at PG&E. ​“It’s a bit of an arbitrary marker, but that’s what was laid out, and this project did come in under that threshold.”

RELATED

As the cost of renewables plummets, other challenges emerge

Canada‘s largest battery storage farm just opened – and it’s Indigenous-led

Hydrogen won’t rescue pension funds from bad bets on gas

“But still, we have a ways to go to bring the cost down,” Donnell adds. ​“So hopefully, through implementation of this first project, Energy Vault learned a lot, the industry learned a lot on how to integrate these solutions in future projects.”

Energy Vault hopes to improve the project economics by upgrading the site to allow regular power exports to the grid.

Currently, the system is configured to push out power only when PG&E has scheduled a shutoff event; that means the microgrid sits idle almost every day of the year (and is unavailable for unforeseen outages, like if a tree falls on a key line). But with the right permissions and technical tweaks in place, Energy Vault expects to use the battery, and potentially even the hydrogen, to send power to California’s grid at particularly lucrative times.

“We can now have a viable second revenue stream outside of providing that resiliency service, without compromising our ability to provide the resiliency service,” Horne says. PG&E amended its contract this summer to clarify that Energy Vault is allowed to pursue this, provided it does not interrupt delivery of the required resilience services.

Going forward, Calistoga will serve as a showcase for Energy Vault’s new ​“H-Vault” product line, marketed as a high-tech option for long-duration clean energy needs. Hydrogen tanks will join gravity-based block stacking and conventional lithium-ion batteries as the company’s core offerings.

For the people of Calistoga, the project softens the upheavals of living through climate-change-induced extreme weather, without all the downsides of onsite fossil fuel combustion.

“Is it absolutely perfect? No,” Gift says. ​“But as a society, it is about making that next best right step. And for us in our community, this was that next best right step.”

For Energy Vault and the budding hydrogen industry, the next right step will be expanding hydrogen production that’s definitively low-emissions, and closing the 4,500-kilometre gap between supply and demand.

Julian Spector is a senior reporter at Canary Media. He reports on batteries, long-duration energy storage, low-carbon hydrogen and clean energy breakthroughs around the world.

Wendy Becktold contributed reporting from Calistoga.

The post A new California microgrid runs on hydrogen. But how clean is it? appeared first on Corporate Knights.

East of San Antonio in Bexar County, 500 electric vehicle batteries at the end of their automotive lives will soon be repurposed to provide energy storage for Texas’s electric grid, a California company, B2U Storage Solutions, announced on August 29.

The batteries, housed in 21 cabinets the size of shipping containers, create a second life for the technology made from critical minerals, including lithium, nickel and cobalt, for another eight years, says Freeman Hall, co-founder and CEO.

Once the site is built and in operation later this year, the batteries will charge when there is an excess of renewable-energy production on the grid and the cost of power is cheap. The Texas facility will have a total capacity of 24 megawatt hours.

B2U Storage Solutions, based in Los Angeles, plans to deploy three more grid-storage projects in Texas throughout the next year, totalling 100 megawatt hours across the state, the company says. Assuming the average household uses 30 kilowatt hours per day, it’s enough energy to power 3,330 homes for a day, Hall says.

The site near San Antonio will interconnect to the CPS Energy distribution system, one of the nation’s largest city-owned utility companies. “We’re really helping to pioneer and demonstrate to the automotive industry that repurposing makes a lot of sense for a pretty healthy number of batteries before they’re truly ready for end of life and recycling,” Hall says in an interview.

An epiphany in novel energy storage

Hall and chief operating officer Michael Stern began building industrial-scale solar projects almost 20 years ago in the California cities of Palmdale, El Centro and Mojave, installing some 100 megawatts, or enough electricity to power more than 15,000 homes. But soon, as more solar began connecting to the grid, their bids to utilities were undermined by a developing  “duck curve” – industry shorthand for when higher penetration of renewables on the grid depresses energy prices during sunlit hours followed by a cost spike in the evening as there’s a loss of sun.

“That’s what inspired us to realize that we needed to add storage to our projects,” Hall says. “Along the way, we had an epiphany.”

RELATED

How subsidized leasing can drive EV adoption

Who’s trying to kill the $17,000 electric car?

Lack of charging stations in high-rise buildings is cutting off access to EVs

In looking for battery storage options for their solar projects, the two developers realized that the first wave of commercial EV batteries were beginning to wrap up their roughly 10-year automotive life. Aware of research that these batteries’ state-of-health, measuring the difference between a new battery and a used one, circled up to 80%, Hall and Stern hypothesized that they could build technology to use the battery packs as they came from the vehicle, avoiding any repurposing costs.

So the two solar developers purchased 300 Nissan Leaf batteries. The carmaker had run into a powertrain warranty issue with the world’s first mass-market EV, as the range they promised in the lease with the customer fell short. To fix the warranty and guarantee, Nissan swapped out the battery packs and found themselves with thousands of batteries that were still useful, Hall says, just not for driving. The batteries still had thousands of cycles left in a less-demanding scenario, like stationary storage for renewable energy.

That’s when the solar developers initiated the EV-pack storage technology fundamental to B2U, which currently operates three facilities using retired batteries from electric vehicles like Teslas, the Honda Clarity and the Nissan Leaf in California.

B2U’s technology allows the company to buy the retired EV battery packs without having to modify them, creating large-scale storage projects for less than if they were installing new batteries.

A coming wave of available energy storage

The global electric car fleet reached almost 58 million by the end of 2024, or about 4%  of all cars on the road, according to an International Energy Agency 2025 EV report. It’s more than triple the amount of electric cars in 2021.

The batteries in electric vehicles are typically replaced once they reach around 70 to 80% of their capacity as their range begins to diminish. As more EV batteries retire throughout the coming decade, the second-life EV battery market is forecasted to grow into a US$4.2 billion industry by 2035, according to a December report by IDTechEx, a technology market research firm.

You haven’t heard about it much to date. But you will be hearing a lot more about it going forward.

 – Freeman Hall, co-founder and CEO, B2U Storage Solutions

As the burgeoning industry in the United States advances, second-life battery reuse will become less expensive to operate, the report says, as new technology develops and speeds up the process. For instance, quality assurance currently can take hours to complete, but the report suggests that soon technology will pare the process down to minutes. These cost savings will be especially important as loans and incentives from the Inflation Reduction Act that supported a growing domestic recycling industry expire.

The opportunities within Texas’s competitive, wholesale grid market are what led Hall and his company to consider operating outside of their California headquarters, Hall says.

As a storage power generator, B2U is able to sell power after cheaply charging it and provide ancillary services to the grid, or get paid by the grid operators to help curb frequency deviations and imbalances.

Batteries have made significant capacity contributions within Texas’s electric grid in recent years and have been credited with helping prevent summer blackouts by bolstering grid reliability. Nearly 4,000 of the 9,600 megawatts of capacity added to the grid since last summer came from energy storage, according to the Electric Reliability Council of Texas (ERCOT).

The latest interconnection report shows that more than 700 stand-alone battery-storage projects and more than 300 battery-plus-solar projects are in line to connect to ERCOT.

Last year, another California-based company, Element Energy, began storing electricity using 900 second-life EV batteries within ERCOT. The West Texas site totals 53 megawatt hours of storage capacity, making it one of the nation’s largest retired EV battery projects, according to Element.

Solving the technical challenges for second-life batteries

B2U manages more than 2,000 retired batteries through its system, which coordinates the performance of the batteries, cabinet and overall power plant. The data they collect in real time allows them to monitor the temperature of the battery packs and voltage levels. The firm has another 2,000 end-of-automative-life batteries at some stage of deployment, Hall says, that will soon be ready to plug into the grid.

Each time the firm receives a batch of EV batteries, B2U performs its own diagnostic tests, with some 5 or 6% rejected because of substandard health.

The testing, coupled with how they configure the batteries in their cabinets, allow the retired batteries to operate despite variance in their capacities. In laymen’s terms, if a weaker battery has charged up and reached its voltage limit, the way B2U links their battery packs ensures that the stronger batteries can keep charging until they’re full. “That’s kind of key to solving the problem of second-life batteries,” Hall says.

Repurposed EV batteries aren’t something you hear of much in ERCOT, or in other grids across the United States. As one of the early innovators, it’s taken B2U nearly five years to get the core technology ironed out, cost effective and ready to scale, Hall says. He says they got their timing just right. Since they started B2U in 2019, EV car sales in North America have nearly tripled. It means a steady flow of retirement-ready batteries available for their next career stabilizing the grid and staving off early recycling of critical minerals.

“You haven’t heard about it much to date,” Hall says of second-life EV battery use. “But you will be hearing a lot more about it going forward.”

Arcelia Martin is an award-winning journalist at Inside Climate News. She covers renewable energy in Texas from her base in Dallas.

The post Used EV batteries are poised to play a bigger role in grid-scale energy storage appeared first on Corporate Knights.