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Enegix Base One Green Hydrogen Plant will produce renewable hydrogen via electrolysis in Ceara, Brazil, leveraging 3.4 GW baseload renewables, offshore wind, and hydro to scale clean energy, storage, and export logistics.

Key Points

A $5.4bn Ceara, Brazil project to produce 600m kg of green hydrogen annually using 3.4 GW of baseload renewables.

✅ 3.4 GW baseload from hydro and offshore wind pipelines

✅ Targets 600m kg green hydrogen per year via electrolysis

✅ Focus on storage, transport, and export supply chains

In March, Enegix Energy announced some of the most ambitious hydrogen plans the world has ever seen. The company signed a memorandum of understanding (MOU) with the government of the Brazilian state of Ceará to build the world’s largest green hydrogen plant in the state on the country’s north-eastern coast, and the figures are staggering.

The Base One facility will produce more than 600 million kilograms of green hydrogen annually from 3.4GW of baseload renewable energy, and receive $5.4bn in investment to get the project off the ground and producing within four years.

Green hydrogen, hydrogen produced by electrolysis that is powered by renewables, has significant potential as a clean energy source. Already seeing increased usage in the transport sector, the power source boasts the energy efficiency and the environmental viability to be a cornerstone of the world’s energy mix.

Yet practical challenges have often derailed large-scale green hydrogen projects, from the inherent obstacle of requiring separate renewable power facilities to the logistical and technological challenges of storing and transporting hydrogen. Could vast investment, clever planning, and supportive governments and programs like the DOE’s hydrogen hubs initiative help Enegix to deliver on green hydrogen’s oft-touted potential?

Brazilian billions
The Base One project is exceptional not only for its huge scale, but the timing of its construction, with demand for hydrogen set to increase dramatically over the next few decades. Figures from Wood Mackenzie suggest that hydrogen could account for 1.4 billion tonnes of energy demand by 2050, one-tenth of the world’s supply, with green hydrogen set to be the majority of this figure.

Yet considering that, prior to the announcement of the Enegix project, global green hydrogen capacity was just 94MW, advances in offshore green hydrogen and the development of a project of this size and scope could scale up the role of green hydrogen by orders of magnitude.

“We really need to [advance clean energy] without any emissions on a completely clean, carbon neutral and net-zero framework, and so we needed access to a large amount of green energy projects,” explains Wesley Cooke, founder and CEO of Enegix, a goal aligned with analyses that zero-emissions electricity by 2035 is possible, discussing the motivation behind the vast project.

With these ambitious goals in mind, the company needed to find a region with a particular combination of political will and environmental traits to enable such a project to take off.

“When we looked at all of these key things: pipeline for renewables, access to water, cost of renewables, and appetite for renewables, Brazil really stood out to us,” Cooke continues. “The state of Ceará, that we’ve got an MOU with the government in at the moment, ticks all of these boxes.”

Ceará’s own clean energy plans align with Enegix’s, at least in terms of their ambition and desire for short-term development. Last October, the state announced that it plans to add 5GW of new offshore wind capacity in the next five years. With BI Energia alone providing $2.5bn in investment for its 1.2GW Camocim wind facility, there is significant financial muscle behind these lofty ambitions.

“One thing I should add is that Brazil is very blessed when it comes to baseload renewables,” says Cooke. “They have an incredibly high percentage of their country-wide energy that comes from renewable sources and a lot of this is in part due to the vast hydro schemes that they have for hydro dams. Not a lot of countries have that, and specifically when you’re trying to produce hydrogen, having access to vast amounts of renewables [is vital].”

Changing perceptions and tackling challenges
This combination of vast investment and integration with the existing renewable power infrastructure of Ceará could have cultural impacts too. The combination of state support for and private investment in clean energy offsets many of the narratives emerging from Brazil concerning its energy policies and environmental protections, even as debates over clean energy's trade-offs persist in Brazil and beyond, from the infamous Brumadinho disaster to widespread allegations of illegal deforestation and gold mining.

“I can’t speak for the whole of Brazil, but if we look at Ceará specifically, and even from what we’ve seen from a federal government standpoint, they have been talking about a hydrogen roadmap for Brazil for quite some time now,” says Cooke, highlighting the state’s long-standing support for green hydrogen. “I think we came in at the perfect time with a very solid plan for what we wanted to do, [and] we’ve had nothing but great cooperation, and even further than just cooperation, excitement around the MOU.”

This narrative shift could help overcome one of the key challenges facing many hydrogen projects, the idea that its practical difficulties render it fundamentally unsuitable for baseload power generation. By establishing a large-scale green hydrogen facility in a country that has recently struggled to present itself as one that is invested in renewables, the Base One facility could be the ultimate proof that such clean hydrogen projects are viable.

Nevertheless, practical challenges remain, as is the case with any energy project of this scale. Cooke mentions a number of solutions to two of the obstacles facing hydrogen production around the world: renewable energy storage and transportation of the material.

“We were looking at compressed hydrogen via specialised tankers [and] we were looking at liquefied hydrogen, [as] you have to get liquefied hydrogen very cool to around -253°, and you can use 30% to 40% of your total energy that you started with just to get it down to that temperature,” Cooke explains.

“The other aspect is that if you’re transporting this internationally, you really have to think about the supply chain. If you land in a country like Indonesia, that’s wonderful, but how do you get it from Indonesia to the customers that need it? What is the supply chain? What does that look like? Does it exist today?”

The future of green hydrogen
These practical challenges present something of a chicken and egg problem for the future of green hydrogen: considerable up-front investment is required for functions such as storage and transport, but the difficulties of these functions can scare off investors and make such investments uncommon.

Yet with the world’s environmental situation increasingly dire, more dramatic, and indeed risky, moves are needed to alter its energy mix, and Enegix is one company taking responsibility and accepting these risks.

“We need to have the renewables to match the dirty fuel types,” Cooke says. “This [investment] will really come from the decisions that are being made right now by large-scale companies, multi-billion-euro-per-year revenue companies, committing to building out large scale factories in Europe and Asia, to support PEM [hydrolysis].”

This idea of large-scale green hydrogen is also highly ambitious, considering the current state of the energy source. The International Renewable Energy Agency reports that around 95% of hydrogen comes from fossil fuels, so hydrogen has a long ways to go to clean up its own carbon footprint before going on to displace fossil fuel-driven industries.

Yet this displacement is exactly what Enegix is targeting. Cooke notes that the ultimate goal of Enegix is not simply to increase hydrogen production for use in a single industry, such as clean vehicles. Instead, the idea is to develop green hydrogen infrastructure to the point where it can replace coal and oil as a source of baseload power, leapfrogging other renewables to form the bedrock of the world’s future energy mix.

“The problem with [renewable] baseload is that they’re intermittent; the wind’s not always blowing and the sun’s not always shining and batteries are still very expensive, although that is changing. When you put those projects together and look at the levelised cost of energy, this creates a chasm, really, for baseload.

“And for us, this is really where we believe that hydrogen needs to be thought of in more detail and this is what we’re really evangelising about at the moment.”

A more hydrogen-reliant energy mix could also bring social benefits, with Cooke suggesting that the same traits that make hydrogen unwieldy in countries with established energy infrastructures could make hydrogen more practically viable in other parts of the world.

“When you look at emerging markets and developing markets at the moment, the power infrastructure in some cases can be quite messy,” Cooke says. “You’ve got the potential for either paying for the power or extending your transmission grid, but rarely being able to do both of those.

“I think being able to do that last mile piece, utilising liquid organic hydrogen carrier as an energy vector that’s very cost-effective, very scalable, non-toxic, and non-flammable; [you can] get that power where you need it.

“We believe hydrogen has the potential to be very cost-effective at scale, supporting a vision of cheap, abundant electricity over time, but also very modular and usable in many different use cases.”

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Germany renewable energy milestone 2019 saw wind, solar, hydropower, and biomass outproduce coal and nuclear, as low gas prices and high CO2 costs under the EU ETS reshaped the electricity mix, per Fraunhofer ISE.

Key Points

It marks H1 2019 when renewables supplied 47.3% of Germany's electricity, surpassing coal and nuclear.

✅ Driven by high CO2 prices and cheap natural gas

✅ Wind and solar output rose; coal generation declined sharply

✅ Flexible gas plants outcompeted inflexible coal units

In Lippendorf, Saxony, the energy supplier EnBW is temporarily taking part of a coal-fired power plant offline. Not because someone ordered it — it simply wasn't paying off. Gas prices are low, CO2 prices are high, and with many hours of sunshine and wind, renewable methods are producing a great deal of electricity as part of Germany's energy transition now reshaping operations. And in the first half of the year there was plenty of sun and wind.

The result was a six-month period in which renewable energy sources, a trend echoed by the EU wind and solar record across the bloc, produced more electricity than coal and nuclear power plants together. For the first time 47.3% of the electricity consumers used came from renewable sources, while 43.4% came from coal-fired and nuclear power plants.

In addition to solar and wind power, renewable sources also include hydropower and biomass. Gas supplied 9.3%, reflecting how renewables are crowding out gas across European power markets, while the remaining 0.4% came from other sources, such as oil, according to figures published by the Fraunhofer Institute for Solar Energy Systems in July.

Fabian Hein from the think tank Agora Energiewende stresses that the situation is only a snapshot in time, with grid expansion woes still shaping outcomes. For example, the first half of 2019 was particularly windy and wind power production rose by around 20% compared to the first half of 2018.

Electricity production from solar panels rose by 6%, natural gas by 10%, while the share of nuclear power in German electricity consumption has remained virtually unchanged despite a nuclear option debate in climate policy.

Coal, on the other hand, declined. Black coal energy production fell by 30% compared to the first half of 2018, lignite fell by 20%. Some coal-fired power plants were even taken off the grid, even as coal still provides about a third of Germany's electricity. It is difficult to say whether this was an effect of the current market situation or whether this is simply part of long-term planning, says Hein.

Activists storm German mine in anti-coal protest

It is clear, however, that an increased CO2 price has made the ongoing generation of electricity from coal more expensive. Gas-fired power plants also emit CO2, but less than coal-fired power plants. They are also more efficient and that's why gas-fired power plants are not so strongly affected by the CO2 price

The price is determined at a European level and covers power plants and energy intensive industries in Europe. Other areas, such as heating or transport are not covered by the CO2 price scheme. Since a reform of CO2 emissions trading in 2017, the price has risen sharply. Whereas in September 2016 it was just over €5 ($5.6), by the end of June 2019 it had climbed to over €26.

Ups and downs

Gas as a raw material is generally more expensive than coal. But coal-fired power plants are more expensive to build. This is why operators want to run them continuously. In times of high demand, and therefore high prices, gas-fired power plants are generally started up, as seen when European power demand hit records during recent heatwaves, since it is worth it at these times.

Gas-fired power plants can be flexibly ramped up and down. Coal-fired power plants take 11 hours or longer to get going. That's why they can't be switched on quickly for short periods when prices are high, like gas-fired power plants. In the first half of the year, however, coal-fired power plants were also ramped up and down more often because it was not always worthwhile to let the power plant run around the clock.

Because gas prices were particularly low in the first half of 2019, some gas-fired power plants were more profitable than coal-fired plants. On June 29, 2019, the gas price at the Dutch trading point TTF was around €10 per megawatt hour. A year earlier, it had been almost €20. This is partly due to the relatively mild winter, as there is still a lot of gas in reserve, confirmed a spokesman for the Federal Association of the Energy and Water Industries (BDEW). There are also several new export terminals for liquefied natural gas. Additionally, weaker growth and trade wars are slowing demand for gas. A lot of gas comes to Europe, where prices are still comparatively high, reported the Handelsblatt newspaper.

The increase in wind and solar power and the decline in nuclear power have also reduced CO2 emissions. In the first half of 2019, electricity generation emitted around 15% less CO2 than in the same period last year, reported BDEW. However, the association demands that the further expansion of renewable energies should not be hampered. The target of 65% renewable energy can only be achieved if the further expansion of renewable energy sources is accelerated.

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Electric mining equipment enables zero-emission, diesel-free operations at Goldcorp's Borden mine, using Sandvik battery-electric drills and LHD trucks to cut ventilation costs, noise, and maintenance while improving underground air quality.

Key Points

Battery-powered mining equipment replaces diesel, cutting emissions and ventilation costs in underground operations.

✅ Cuts diesel use, heat load, and noise in underground headings.

✅ Reduces ventilation infrastructure and operating expense.

✅ Improves air quality, worker health, and equipment uptime.

Mining operations get a lot of flack for creating environmental problems around the world. Yet they provide much of the basic material that keeps the global economy humming. Some mining companies are drilling down in their efforts to clean up their acts, exploring solutions such as recovering mine heat for power to reduce environmental impact.

As the world’s fourth-largest gold mining company Goldcorp has received its share of criticism about the impact it has on the environment.

In 2016, the Canadian company decided to do something about it. It partnered with mining-equipment company Sandvik and began to convert one of its mines into an all-electric operation, a process that is expected to take until 2021.

The efforts to build an all-electric mine began with the Sandvik DD422iE in Goldcorp’s Borden mine in Ontario, Canada.

Goldcorp's Borden mine in Borden, Ontario, CanadaGoldcorp's Borden mine in Borden, Ontario, Canada

The machine weighs 60,000 pounds and runs non-stop on a giant cord. It has a 75-kwh sodium nickel chloride battery to buffer power demands, a crucial consideration as power-hungry Bitcoin facilities can trigger curtailments during heat waves, and to move the drill from one part of the mine to another.

This electric rock-chewing machine removes the need for the immense ventilation systems needed to clean the emissions that diesel engines normally spew beneath the surface in a conventional mining operation, though the overall footprint depends on electricity sources, as regions with Clean B.C. power imports illustrate in practice.

These electric devices improve air quality, dramatically reduce noise pollution, and remove costly maintenance of internal combustion engines, Goldcorp says.

More importantly, when these electric boring machines are used across the board, it will eliminate the negative health effects those diesel drills have on miners.

“It would be a challenge to go back,” says big drill operator Adam Ladouceur.

Mining with electric equipment also removes second- or third-highest expenditure in mining, the diesel fuel used to power the drills, said Goldcorp spokesman Pierre Noel, even as industries pursue dedicated energy deals like Bitcoin mining in Medicine Hat to manage power costs. (The biggest expense is the cost of labor.)

Electric load, haul, dump machine at Goldcorp Borden mine in OntarioElectric load, haul, dump machine at Goldcorp Borden mine in Ontario

Aside from initial cost, the electric Borden mine will save approximately $7 million ($9 million Canadian) annually just on diesel, propane and electricity.

Along with various sizes of electric drills and excavating tools, Goldcorp has started using electric powered LHD (load, haul, dump) trucks to crush and remove the ore it extracts, and Sandvik is working to increase the charging speed for battery packs in the 40-ton electric trucks which transport the ore out of the mines, while utilities add capacity with new BC generating stations coming online.

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Just Transition for Coal and Nuclear Workers explains policy frameworks, compensation packages, retraining, and community support during decarbonization, plant closures, and energy shifts across Europe and the U.S., including Diablo Canyon and Uniper strategies.

Key Points

A policy approach to protect and retrain legacy power workers as coal and nuclear plants retire during decarbonization.

✅ Germany and Spain fund closures with compensation and retraining.

✅ U.S. lacks federal support; Diablo Canyon is a notable exception.

✅ Firms like Uniper convert coal sites to gas and clean energy roles.

The coronavirus pandemic has not changed the grim reality facing workers at coal and nuclear power plants in the U.S. and Europe. How those workers will fare in the years ahead will vary greatly based on where they live and the prevailing political winds.

In Europe, the retirement of aging plants is increasingly seen as a matter of national concern. Germany this year agreed to a €40 billion ($45 billion) compensation package for workers affected by the country's planned phaseout of coal generation by 2038, amid its broader exit from nuclear power as part of its energy transition. Last month the Spanish authorities agreed on a just transition plan affecting 2,300 workers across 12 thermal power plants that are due to close this year.

In contrast, there is no federal support plan for such workers in the U.S., said Tim Judson, executive director at the Maryland-based Nuclear Information and Resource Service, which lobbies for an end to nuclear and fossil-fuel power.

For all of President Donald Trump’s professed love of blue-collar workers in sectors such as coal, “where there are economic transitions going on, we’re terrible at supporting workers and communities,” Judson said of the U.S. Even at the state level, support for such workers is "almost nonexistent,” he said, “although there are a lot of efforts going on right now to start putting in place just transition programs, especially for the energy sector.”

One example that stands out in the U.S. is the support package secured for workers at utility PG&E's Diablo Canyon Power Plant, California's last operating nuclear power plant that is scheduled for permanent closure in 2025. “There was a settlement between the utility, environmental groups and labor unions to phase out that plant that included a very robust just transition package for the workers and the local community,” Judson said.

Are there enough clean energy jobs to replace those being lost?
Governments are more likely to step in with "just transition" plans where they have been responsible for plant closures in the first place. This is the case for California, Germany and Spain, all moving aggressively to decarbonize their energy sectors and pursue net-zero emissions policy goals.

Some companies are beginning to take a more proactive approach to helping their workers with the transition. German energy giant Uniper, for example, is working with authorities to save jobs by seeking to turn coal plants into lower-emissions gas-fired units.

Germany’s coal phaseout will force Uniper to shut down 1.5 gigawatts of hard-coal capacity by 2022, but the company has said it is looking at "forward-looking" options for its plants that "will be geared toward tomorrow's energy world and offer long-term employment prospects."

Christine Bossak, Uniper’s manager of external communications, told GTM this approach would be adopted in all the countries where Uniper operates coal plants.

Job losses are usually inevitable when a plant is closed, Bossak acknowledged. “But the extent of the reduction depends on the alternative possibilities that can be created at the site or other locations. We will take care of every single employee, should he or she be affected by a closure. We work with the works council and our local partners to find sustainable solutions.”

Diana Junquera Curiel, energy industry director for the global union federation IndustriALL, said such corporate commitments looked good on paper — but the level of practical support depends on the prevailing political sentiment in a country, as seen in Germany's nuclear debate over climate strategy.

Even in Spain, where the closure of coal plants was being discussed 15 years ago, a final agreement had to be rushed through at the last minute upon the arrival of a socialist government, Junquera Curiel said. An earlier right-wing administration had sat on the plan for eight years, she added.

The hope is that heel-dragging over just transition programs will diminish as the scale of legacy plant closures grows.

Nuclear industry facing a similar challenge as coal
One reason why government support is so important is there's no guarantee a burgeoning clean energy economy will be able to absorb all the workers losing legacy generation jobs. Although the construction of renewable energy projects requires large crews, it often takes no more than a handful of people to operate and maintain a wind or solar plant once it's up and running, Junquera Curiel observed.

Meanwhile, the job losses are unlikely to slow. In Europe, Austria and Sweden both closed their last coal-fired units recently, even as Europe loses nuclear capacity in key markets.

In the U.S., the Energy Information Administration's base-case prediction is that coal's share of power generation will fall from 24 percent in 2019 to 13 percent in 2050, while nuclear's will fall from 20 percent to 12 percent over that time horizon. The EIA has long underestimated the growth trajectory of renewables in the mix; only in 2020 did it concede that renewables will eventually overtake natural gas as the country's largest source of power.

The Institute for Energy Economics and Financial Analysis has predicted that even a coronavirus-inspired halt to renewables is unlikely to stop a calamitous drop in coal’s contribution to U.S. generation.

The nuclear sector faces a similar challenge as coal, albeit over a longer timeline. Last year saw the nuclear industry starting to lose capacity worldwide in what could be the beginning of a terminal decline, highlighted by Germany's shutdown of its last three reactors in 2023. Last week, the Indian Point Energy Center closed permanently after nearly half a century of cranking out power for New York City.*

“Amid ongoing debates over whether to keep struggling reactors online in certain markets, the industry position would be that governments should support continued operation of existing reactors and new build as part of an overall policy to transition to a sustainable clean energy system,” said Jonathan Cobb, senior communication manager at the World Nuclear Association.

If this doesn’t happen, plant workers will be hoping they can at least get a Diablo Canyon treatment. Based on the progress of just transition plans so far, that may depend on how they vote just as much as who they work for.

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Alberta Lithium Brine can power EV batteries via direct lithium extraction, leveraging oilfield infrastructure and critical minerals policy to build a low-carbon supply chain with clean energy, lower emissions, and domestic manufacturing advantages.

Key Points

Alberta lithium brine is subsurface saline water rich in lithium, extracted via DLE to supply EV batteries.

✅ Uses direct lithium extraction from oilfield brines

✅ Leverages Alberta infrastructure and skilled workforce

✅ Supports EV battery supply chain with lower emissions

After a most difficult several months, Canadians are cautiously emerging from their COVID-19 isolation and confronting a struggling economy.
There’s a growing consensus that we need to build back better from COVID-19, and to position for the U.S. auto sector’s pivot to electric vehicles as supply chains evolve. Instead of shoring up the old economy as we did following the 2008 financial crisis, we need to make strategic investments today that will prepare Canada for tomorrow’s economy.

Tomorrow’s energy system will look very different from today’s — and that tomorrow is coming quickly. The assets of today’s energy economy can help build and launch the new industries required for a low-carbon future. And few opportunities are more intriguing than the growing lithium market.

The world needs lithium – and Alberta has plenty

It’s estimated that three billion tonnes of metals will be required to generate clean energy by 2050. One of those key metals – lithium, a light, highly conductive metal – is critical to the construction of battery electric vehicles (BEV). As global automobile manufacturers design hundreds of new BEVs, demand for lithium is expected to triple in the next five years alone, a trend sharpened by pandemic-related supply risks for automakers.

Most lithium today originates from either hard rock or salt flats in Australia and South America. Alberta’s oil fields hold abundant deposits of lithium in subsurface brine, but so far it’s been overlooked as industrial waste. With new processing technologies and growing concerns about the security of global supplies, this is set to change. In January, Canada and the U.S. finalized a Joint Action Plan on Critical Minerals to ensure supply security for critical minerals such as lithium and to promote supply chains closer to home, aligning with U.S. efforts to secure EV metals among allies worldwide.

This presents a major opportunity for Canada and Alberta. Lithium brine will be produced much like the oil that came before it. This lithium originates from many of the same reservoirs responsible for driving both Alberta’s economy and the broader transportation fuel sector for decades. The province now has extensive geological data and abundant infrastructure, including roads, power lines, rail and well sites. Most importantly, Alberta has a highly trained workforce. With very little retooling, the province could deliver significant volumes of newly strategic lithium.

Specialized technologies known as direct lithium extraction, or DLE, are being developed to unlock lithium-brine resources like those in Canada. In Alberta, E3 Metals* has formed a development partnership with U.S. lithium heavyweight Livent Corporation to advance and pilot its DLE technology. Prairie Lithium and LiEP Energy formed a joint venture to pilot lithium extraction in Saskatchewan. And Vancouver’s Standard Lithium is already piloting its own DLE process in southern Arkansas, where the geology is very similar to Alberta and Saskatchewan.

Heavy on quality, light on emissions

All lithium produced today has a carbon footprint, most of which can be tied back to energy-intensive processing. The purity of lithium is essential to battery safety and performance, but this comes at a cost when lithium is mined with trucks and shovels and then refined in coal-heavy China.

As automakers look to source more sustainable raw materials, battery recycling will complement responsible extraction, and Alberta’s experience with green technologies such as renewable electricity and carbon capture and storage can make it one of the world’s largest suppliers of zero-carbon lithium.

Beyond raw materials

The rewards would be considerable. E3 Metals’ Alberta project alone could generate annual revenues of US$1.8 billion by 2030, based on projected production and price forecasts. This would create thousands of direct jobs, as initiatives like a lithium-battery workforce initiative expand training, and many more indirectly.

To truly grow this industry, however, Canada needs to move beyond its comfort zone. Rather than produce lithium as yet another raw-commodity export, Canadians should be manufacturing end products, such as batteries, for the electrified economy, with recent EV assembly deals underscoring Canada’s momentum. With nickel and cobalt refining, graphite resources and abundant petrochemical infrastructure already in place, Canada must aim for a larger piece of the supply chain.

By 2030, the global battery market is expected to be worth $116 billion annually. The timing is right to invest in a strategic commodity and grow our manufacturing sector. This is why the Alberta-based Energy Futures Lab has called lithium one of the ‘Five big ideas for Alberta’s economic recovery.’  The assets of today’s energy economy can be used to help build and launch new resource industries like lithium, required for the low-carbon energy system of the future.

Industry needs support

To do this, however, governments will have to step up the way they did a generation ago. In 1975, the Alberta government kick-started oil-sands development by funding the Alberta Oil Sands Technology and Research Authority. AOSTRA developed a technology called SAGD (steam-assisted gravity drainage) that now accounts for 80% of Alberta’s in situ oil-sands production.

Canada’s lithium industry needs similar support. Despite the compelling long-term economics of lithium, some industry investors need help to balance the risks of pioneering such a new industry in Canada. The U.S. government has recognized a similar need, with the Department of Energy’s recent US$30 million earmarked for innovation in critical minerals processing and the California Energy Commission’s recent grants of US$7.8 million for geothermal-related lithium extraction.

To accelerate lithium development in Canada, this kind of leadership is needed. Government-assisted financing could help early-stage lithium-extraction technologies kick-start a whole new industry.

Aspiring lithium producers are also looking for government’s help to repurpose inactive oil and gas wells. The federal government has earmarked $1 billion for cleaning up inactive Alberta oil wells. Allocating a small percentage of that total for repurposing wells could help transform environmental liabilities into valuable clean-energy assets.

The North American lithium-battery supply chain will soon be looking for local sources of supply, and there is room for Canada-U.S. collaboration as companies turn to electric cars, strengthening regional resilience.
 

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Electrically Smart Roads integrate solar road surfaces, inductive charging, IoT sensors, AI analytics, and V2X to power lighting, deicing, and monitoring, reducing grid dependence while enabling dynamic EV charging and real-time traffic management.

Key Points

Electrically smart roads generate power, sense conditions, and charge EVs using solar, IoT, AI, and dynamic infrastructure.

✅ Solar surfaces, verges, and gantries generate on-site electricity

✅ Inductive lanes enable dynamic EV charging at highway speeds

✅ Embedded IoT sensors and AI deliver real-time traffic insights

As more and more capabilities are added to roads instead of simply covering a country with extra roads, they are starting to make their own electricity, notably as solar road surface but then with added silent wind turbines, photovoltaic verges and barriers and more.

That toll gate, street light and traffic monitoring system all need electricity. Later, roads that deice and charge vehicles at speed will need huge amounts of electricity. For now, electricity for road systems is provided by very expensive infrastructure to the grid, and grid flexibility for EVs remains a concern, except for a few solar/ wind street lights in China and Korea for example. However, as more and more capabilities are added to roads instead of simply covering a country with extra roads, they are starting to make their own electricity, notably as solar road surface but then with added silent wind turbines, photovoltaic verges and barriers and more. There is also highly speculative work in the USA and UK on garnering power from road surface movement using piezoelectrics and electrodynamics and even its heat. 

#google#

China plans to create an intelligent transport system by 2030. The country hopes to build smart roads that will not only be able to charge electric cars as they drive but also monitor temperature, traffic flow and weight load using artificial intelligence. Indeed, like France, the Netherlands and the USA, where U.S. EV charging capacity is under scrutiny, it already has trials of extended lengths of solar road which cost no more than regular roads. In an alternative approach, vehicles go under tunnels of solar panels that also support lighting, light-emitting signage and monitoring equipment using the electricity made where it is needed. See the IDTechEx Research report, Electrically Smart Roads 2018-2028 for more.

Raghu Das, CEO of IDTechEx says, "The spiral vertical axis wind turbines VAWT in Asia rarely rotate because they are too low but much higher versions are planned on large UK roadside vehicle charging centres that should work well. H shaped VAWT is also gaining traction - much slower and quieter than the propeller shape which vibrates and keeps you awake at night in an urban area.

The price gap between the ubiquitous polycrystalline silicon solar cell and the much more efficient single crystal silicon is narrowing. That means that road furniture such as bus shelters and smart gantries will likely go for more solar rather than adding wind power in many cases, a shift mirrored by connected solar tech in homes, because wind power needs a lot of maintenance and its price is not dropping as rapidly."

The IDTechEx Research report, Off Grid Electric Vehicle Charging: Zero Emission 2018-2028 analyses that aspect, while vehicle-to-grid strategies may complement grid resources. The prototype of a smart road is already in place on an expressway outside of Jinan, providing better traffic updates as well as more accurate mapping. Verizon's IoT division has launched a project around intelligent asphalt, which it thinks has the potential to significantly reduce fossil fuel emissions and save time by reducing up to 44% of traffic backups. It has partnered with Sacramento, California, to test this theory.

"By embedding sensors into the pavement as well as installing cameras on traffic lights, we will be able to study and analyze the flow of traffic. Then, we will take all of that data and use it to optimize the timing of lights so that traffic flows easier and travel times are shorter," explains Sean Harrington, vice president of Verizon Smart Communities.

Colorado's Department of Transportation has recently announced its intention to be the first state to pilot smart roads by striking a five-year deal with a smart road company to test the technology. Like planned auto-deicing roads elsewhere, the aim of this project is, first and foremost, to save lives. The technology will detect when a car suddenly leaves a road and send emergency assistance to the area. The IDTechEx Research report Electrically Smart Roads 2018-2028 describes how others work on real time structural monitoring of roads and embedded interactive lighting and road surface signage.

"Smart pavement can make that determination and send that information directly into a vehicle," Peter Kozinski, director of CDOT's RoadX division, tells the Denver Post. "Data is the new asphalt of transportation."   Sensors, processors and other technology are embedded in the Colorado road to extend capability beyond accidents and reach into better road maintenance. Fast adoption relies on the ability to rapidly install sensor-laden pavement or lay concrete slabs. Attention therefore turns to fast adaptation of existing roads. Indeed, even for the heavy coil arrays used for dynamic vehicle charging, even as state power grids face new challenges, in Israel there are machines that can retrofit into the road surface at a remarkable two kilometres of cut and insert in a day.

"It's hard to imagine that these things are inexpensive, with all the electronics in them," Charles Schwartz, a professor of civil and environmental engineering at the University of Maryland, tells the Denver Post concerning the vehicle sensing project, "but CDOT is a fairly sophisticated agency, and this is an interesting pilot project. We can learn a lot, even if the test is only partially successful."

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