By Ian Munroe, Anna Berka and Christina E. Hoicka

The number of renewable energy projects that are fully or partly Indigenous-owned is growing quickly in Canada, and our new research suggests that their benefits reach far beyond reducing greenhouse gas emissions.

The number of such projects on traditional Indigenous territories and reserve lands jumped by more than 300 per cent between 2009 and 2020. Nearly one-fifth of the country’s electricity-generating infrastructure involved First Nations, Métis and Inuit partners or beneficiaries as of 2022.

Yet little is known about the impacts of these renewable-energy projects within the participating communities beyond the physical footprint of the construction.

We aimed to fill this information policy gap in response to a request from two organizations that work extensively with First Nations, the Clean Energy Association of British Columbia and the New Relationship Trust, which obtained funding from Natural Resources Canada to conduct research.

Together we conducted a study to paint a more complete picture of these broader impacts, interviewing knowledge-holders in 14 First Nations in British Columbia involved with 36 planned or operational Indigenous-led renewable energy projects.

We found that these projects employ “placed-based” approaches, often with a high degree of community engagement early on, and revenues often allocated to support their own culture, governance, ecology, support services and economy.

Transformational change

We found that when First Nations’ worldviews are centred and community control is enabled, broad social and cultural benefits result, providing greater self-determination.

As part of our research, we interviewed knowledge-holders from the West Moberly First Nations near Peace River, B.C. The nation has used wind-project revenues to support cultural camps and youth programs. As one knowledge-holder there told us:

“We are involved in it, and we are engaged in it. We are co-owners. And I know our Elders feel really good about hearing that. Knowing that we are not just sitting on the sidelines, while other people fill their pockets in our territory. And our community is doing that kind of stuff more and more. There is a connection there, right, because you are involved. More money is flowing to the community.”

In the Fraser Canyon region, the T’eqt’aqtn’mux (Kanaka Bar Indian Band), which has been affected by wildfires in recent years, has used proceeds from solar projects to reduce fire hazards and protect homes.

In the case of the Skidegate Band Council, we heard that revenues from a two-megawatt microgrid solar project would go toward funding Tll Yahda Energy, a partnership with the Old Massett Village Council to develop renewable energy projects in Haida Gwaii.

While these results demonstrate that a broad range of positive outcomes can flow from Indigenous-led renewable energy projects, the social and cultural impacts remain neglected in conventional energy practice.

An alternative to traditional energy planning

The Indigenous-led projects we heard about stand in contrast to typically used top-down decision-making, favoured by governments.

This approach is often characterized by public consultation that occurs after the decision of where to site the project has been made, often leading to local rejection of the project, and sometimes cancellation.

The bottom-up nature of the approaches we heard about hold important lessons that can enable widespread acceptance of energy transitions.

This is particularly relevant in B.C., where the provincial government is encouraging renewable energy projects to create economic opportunity and counter external economic shocks, including tariffs from the United States.

This policy push extends to the province’s more than 200 First Nations, with a 2025 procurement call that requires at least 25 per cent First Nations ownership of a project.

The B.C. government must also meet its obligations under the Declaration on the Rights of Indigenous Peoples Act (DRIPA), which aims to bring provincial legislation into agreement with the United Nations Declaration on the Rights of Indigenous Peoples.

The UN treaty requires that state parties enable self-determination and obtain free, prior and informed consent from Indigenous Peoples for projects that impact their lands or resources. Indigenous-led renewable electricity projects in B.C. could help meet requirements under DRIPA to provide pathways for First Nations to improve their economic and social conditions without discrimination.

The Indigenous-led approaches we studied provide a vehicle to support Indigenous communities and make progress toward the province’s decarbonization goals. They also hold valuable lessons for developing policy in other jurisdictions like Ontario, where the provincial government has pledged to boost support for the growing number of Indigenous energy projects.

The world is entering a new era in which energy independence will be more important. Our findings about Indigenous-led projects illustrate a radically different approach to growing the Canada’s renewables industry in a way that can provide energy and facilitate transformational social and cultural change.

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Contracted energy costs for wind and solar projects in Canada have fallen to half of what they were 10 years ago, new analysis shows.

“Now, they’re the lowest-cost form of new electricity generation,” write Pembina Institute electricity program manager David Pickup and senior analyst Will Noel, citing Ontario and Alberta grid operators and global analysts. The authors say the trend is expected to continue, with projections that wind and solar costs will fall another 25% to 50% over the next decade.

The cost decline comes at a good time, as demand for new electricity generation rises with the increasing adoption of electric vehicles, heat pumps, and other new technologies.

Plunging price trends make new wind and solar projects more affordable, and they can also be brought online faster than fossil fuel and nuclear power plants, Pickup and Noel add. “Getting more affordable electricity generation onto the grid— fast—underpins the competitiveness of the economy.”

Competitive procurement processes at the provincial level helped the wind and solar sectors expand by creating market certainty. The provinces that ran these procurements are now on track to bring online thousands of megawatts of renewable energy in the coming years. Quebec, for instance, has announced plans to develop 10,000 megawatts of wind and 3,000 megawatts of solar energy by 2035, and Manitoba is set to request proposals this March to procure 600 megawatts of wind. In Ontario, a technology-agnostic competitive bid process for up to 7,500 megawatts of new energy and capacity is under way, open to wind and solar developers, energy storage projects, and gas plants.

The Pembina analysts say provincial and territorial governments aiming to take advantage of low-cost electricity from wind and solar will need to plan their systems around a modernized grid.

“This means harnessing the latest technology—including interprovincial interties, demand-side measures, and long-duration energy

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By Benjamin Wehrmann

The North Sea’s neighbouring states have launched a joint initiative to massively scale up offshore wind power production and international grid connections. By turning Europe’s famously windy northern maritime zone into a renewable energy reservoir, the countries aim to lower industry costs and provide the region with a reliable clean electricity source to help Europe reduce its dependence on fossil fuel imports. At the third North Sea Summit held in the northern German city of Hamburg, government representatives of Germany, France, the UK, Luxembourg, Iceland, Norway, Belgium, Ireland, the Netherlands and Denmark, agreed to mobilise up to one trillion euros between 2031 and 2040.

German chancellor Friedrich Merz said all signatory states, which included EU members and non-EU states, shared the goal of achieving a secure and affordable energy supply. “For this, we need more cooperation,” Merz said, citing cross-border planning of offshore wind projects, hydrogen production, and grids as areas where this would be implemented. “I see great potential for better cost efficiency,” the chancellor said. He added that the protection against physical and cyberattacks on energy infrastructure in the region played an important role at the talks, which in addition to the EU Commission also featured representatives of the military alliance NATO. 

The plan aims to add 15 gigawatts (GW) of new capacity each year, reaching up to 300 GW in tens of thousands of installed turbines by 2050. Moreover, it provides for a fast increase of interconnectors that allow several countries to benefit from the electricity produced in the same wind farm and to develop the production of green hydrogen at sea.

“The world’s largest energy hub”

As of early 2026, a combined offshore wind capacity of 37 GW was installed across Europe. A recent analysis by the Boston Consulting Group found that North Sea countries would need to increase their expansion rate sevenfold in order to meet targets agreed at the 2023 summit, which aim for a capacity of 120 GW by 2030. Industry representatives have said that expansion has slowed in recent years due to rising investment costs and auction designs that create too much uncertainty for potential bidders.

“Our aim is to build the world’s largest energy hub,” said Germany’s energy minister Katherina Reiche. She said that Europe now can seize a major opportunity to attract capital, as investors are looking for stable conditions amid rising geopolitical uncertainties. “Every offshore wind project that connects Europe is making us more resilient,” Reiche said. She stressed that the multilateral agreement would provide Europe’s offshore wind industry with much-needed planning security to invest in production infrastructure, port capacity and specialised vessels.

The first North Sea Summit was held in 2022, in response to Russia’s invasion of Ukraine, as a forum for developing joint strategies to make their energy infrastructure more resilient. Four years later, threats to Europe’s security remain acute as the war on Ukraine continues. At the same time, recent statements about the possible seizure of Greenland, an autonomous territory belonging to the Kingdom of Denmark, severely undermined confidence across Europe in the US under president Donald Trump as an ally. European governments have responded by intensifying collaboration in strategic fields, including energy.

“Europe stands together in stormy weather,” said German minister Reiche, adding that “we have to prepare” for possible external shocks. The European Union’s energy commissioner, Dan Jørgensen, said that “homegrown clean energy” was the only way to become more independent and cut the hundreds of billions of euros that EU states spend on fossil fuel imports each year.

Renewable energy clearest path to energy security in Europe – governments

With a view to ongoing security challenges, Danish commissioner Jørgensen said that “the Greenland question is on everyone’s mind” at the summit. An analysis warning that Europe’s move away from Russian energy over the past years is accompanied by a fast-rising dependence on US supplies of LNG released in the week before the summit only underlined the need for action. However, Jørgensen stressed that neither Denmark nor the EU were against trading with the US. “We do need LNG from America as it is now,” Jørgensen said. However, “in the long-run we want to become free of gas.” After phasing-out Russian energy, Europe should avoid replacing one dependence with another, he added.

UK energy secretary Ed Miliband said it was “absolutely in our interest” to cooperate with other European states on offshore wind. Renewable power would offer the clearest path to energy security and help the UK and the rest of Europe to “get off the roller-coaster of fossil fuels,” the energy secretary added.

Cooperation to cut costs

Miliband pointed at the country’s latest round of offshore wind auctions, in which 8.4 GW of capacity was awarded, marking Europe’s most successful tender to date. The auction “sent a message across Europe that offshore wind is the backbone of the future energy system,” Miliband argued. The auction relied on Contracts for Difference (CfDs), which guarantee operators a minimum price for their output while capping revenues when market prices are high. Under the North Sea investment pact, CfDs will become the standard remuneration model for offshore wind auctions, a step that Germany’s offshore wind industry has long called for.

According to industry group Wind Europe, the joint approach agreed in the investment pact should lead to cost reductions of up to 30 percent and create more than 90,000 additional jobs. A separate analysis conducted by research institute Fraunhofer IWES found that connecting wind farms internationally could significantly reduce costs. Spreading turbines over larger areas would reduce wake effects and increase average turbine output, the researchers said.

“We need more cross-border cooperation and optimisation to improve cost efficiency,” said Kerstin Andreae, head of the German Federation of Energy and Water Industries (BDEW). Simply increasing capacity would no longer be sufficient, she said, arguing that new turbines must be planned in a way that optimises both costs and output. “A key lever for this is less dense construction and using suitable areas in other countries’ waters that pay towards Germany’s national expansion target.”

Spreading turbines more evenly across the North Sea would also help reduce environmental impacts of offshore wind energy production, said Sascha Müller-Kraenner, head of Environmental Action Germany (DUH). “We absolutely support the newly announced cross-border cooperation projects, as the German government’s ambitious expansion targets do not all fit into the exclusive economic zone alone,” Müller-Kraenner argued. However, all member states had to ensure that the industry’s expansion respects ecologic limits and coordinate planning to minimise adverse effects on ecosystems. 

Germany’s offshore wind industry worried about ongoing uncertainties 

The mood in Germany’s offshore wind industry and elsewhere in Europe has shifted markedly in recent years. While bidders in offshore auctions in 2023 were ready to pay billions of euros to implement new projects, a subsequent auction round in 2025 failed to attract a single bid. “The high bids that we saw in the past in a way concealed the true situation that the industry finds itself in,” Hans Sohn, head of communications at offshore wind industry association BWO, told Clean Energy Wire.

The meagre expansion of less than 1 GW annually since 2020 was caused by a spike in investment and capital costs, for which CfDs would provide a possible remedy. “And then there’s uncertainty about the availability of skilled workers, special construction vessels, storage and processing capacities at sea ports and so on,” Sohn added. Industry representatives therefore called to delay a planned auction in February until the end of the year to reform the auction design, but Germany’s government has signalled it intends to keep the schedule.

Another major uncertainty for the industry is the expected power price in the next two decades, Sohn added. “Demand and price depend on the pace and scope of electrification, meaning the roll-out of electric cars, heat pumps and so on – but it also depends on the level of industrial production we will have in Germany in the future.”

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Toronto-based energy storage developer Hydrostor has secured permission to build a 500-megawatt compressed-air energy storage system in the Mojave Desert and is now seeking customers to contract the project’s full capacity.

Final permitting approval from the California Energy Commission (CEC) positions its Willow Rock project to be “shovel-ready in 2026,” Hydrostor said in a mid-December release.

The grid-connected advanced compressed air energy storage (A-CAES) is designed to store and deliver enough electricity to power more than 400,000 average California homes for more than eight hours.

Willow Rock is also projected to deliver US$500 million in direct and indirect economic benefits regionally, “supporting thousands of jobs over the course of construction, with 700 workers onsite at peak construction,” Emily Smith, Hydrostor’s director of external affairs, told The Energy Mix. Once it goes into operation, the facility is expected to support 25 to 40 full-time jobs.

Unlike lithium-ion battery storage systems, Willow Rock will require neither critical minerals nor hazardous materials, Hydrostor says. The storage process begins at the point of its grid connection, where excess renewable energy, like that generated at mid-day by solar plants, spins compressors that produce heated compressed air.

The heat is captured and stored in tanks, while the cool compressed air is pushed 600 metres below ground into a water-filled cavern. As the air enters the cavern, the water is pushed up into a surface reservoir. The A-CAES system becomes a fully-charged battery when the cavern is full of air.

When power is needed, like during periods of peak power demand or when solar or wind production drops, the process reverses, using gravity to draw the stored water back down into the cavern, displacing the air and forcing it back up to the surface. The air is reheated using the heat stored in the tanks, then used to spin turbines to generate electricity.

Hydrostor has secured a retail supply agreement with the local water agency for a one-time water draw of 800 acre-feet, or around 987,000 cubic metres, Smith told The Mix. It’s a considerable volume of water—more than twice what’s used annually by a U.S. National Security Agency data centre in Utah, for example. But the draw will occur only once.

Willow Rock is in fact expected to be a net water producer, with the water generated as a byproduct of the compression process collected for reuse in the reservoir, Smith said.

The CEC approval comes almost three years after Hydrostor signed a 25-year contract with Monterey’s Central Coast Community Energy to reserve 200 megawatts of Willow Rock’s capacity for the non-profit utility.

With an additional 50 to 100 megawatts being negotiated, that “leaves 200 to 250 megawatts up for grabs,” reports Canary Media. The uncontracted capacity remains an obstacle to securing the US$1.5 billion in financing needed to begin construction, but Hydrostor has declared itself encouraged by the California Public Utilities Commission’s September recommendation that the state secure 10 gigawatts of long-duration storage by 2031.

“They’ve identified the need for very near-term procurement, so we’re looking forward to participating in that,” company president Jon Norman told Canary Media.

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By Daan Walter, Kingsmill Bond, and Sam Butler-Sloss

2025 was a year of new electric thinking. We saw many energy analysts and writers argue that there is more to the energy transition than just a shift from dirty to clean energy. It came in the form of McCormick and D’Amico’s The Electric Slide, to the IEA’s declaration of an Age of Electricity, to growing discussion of electro-industrialism, the rise of a New Joule Order, and the widespread use of the term electrostates, a term we introduced two years ago that gained broad uptake last year.

We laid out the facts in our September report, The Electrotech Revolution, which we also presented at DERVOS last fall. As we enter 2026, we compiled ten key insights from our work that we think are particularly important this year.

1. This is a technology revolution

The energy system is not just decarbonizing, it is entering a new technological age. A new generation of technologies is coming together: on the supply side technologies like solar and wind, demand technologies like EVs and heat pumps, and connection technologies like batteries, grids and software.

Each of these technologies is falling in price and rising exponentially in deployment. Individually, each is disruptive. But together, they form something more powerful. As supply finds demand and connections enable both, they reinforce each other on the way up. This is why we speak of not just a transition but a technology revolution.

This matters for 2026. Even as decarbonization slips down political agendas, the self-reinforcing nature of this technological transition does not stop. The revolution has its own momentum.

2. It brings energy abundance

Human history has seen only a handful of leaps in how much energy is at our disposal. Foragers relied on muscle and fire. Farmers unlocked the energy stored in crops and livestock, multiplying available energy by a hundred. Fossil fuels gave us another fifty-fold increase by tapping ancient sunlight buried underground.

Electrotech promises a similar leap. The sun delivers more energy to Earth every five days than all our fossil fuel reserves combined. As we move to tap into this solar resource, our energy system not only becomes more abundant, but also more immediate; moving from burning old sunshine to capturing it in real time. This is a shift from foraging fossil fuels to harvesting the sun.

As we are sure to see a year full of energy abundance debates in 2026, it is worth noting which path actually delivers on that promise.

3. It has been a long time coming

The rise of electrotech is not a recent trend. It has been coming for over a century. Electrification began in the 1880s, when electric lights and motors started replacing flame and steam. From there, electricity demand grew at 5-7% annually after 1900, as lights, industrial machinery, and household appliances spread across the developed world.

The mid-20th century brought televisions, refrigerators, and washing machines into homes. Then came the information age—semiconductors powering mainframes, then personal computers, then smartphones. The clean lab manufacturing techniques developed for chips eventually made mass production of solar panels and battery cells possible.

Now a century of evolution is turning the 2020s into a decade of revolution. This trend has been running longer than any administration or political setback. It comes with a century of momentum.

4. It inherits the momentum of the IT revolution

In many ways, electrotech is a child of the IT revolution. The precision processes that mass-produce chips and smartphones now build battery cells and solar panels. The same factories, often with the same workers trained by firms like Apple, now power electrotech’s rise. As McCormick and D’Amico argue in The Electric Slide, the tech stack underpinning electrotech is essentially the same as for digital technology. There is more in common between a laptop and a solar panel than between a solar panel and a gas power plant.

This explains why electrotech scales so fast: it inherits decades of manufacturing know-how and cost curves from IT.

It also reveals a strategic paradox visible in 2026. IT hardware and electrotech are the same industrial family. They share supply chains, manufacturing capabilities, network effects, and require the same abundant electricity. Building one without the other is incoherent. The current Trump administration push for AI datacenters and manufacturing automation while throttling EVs and solar exemplifies this disconnect. So does the EU’s embrace of electrotech even as it inhibits the AI rollout with complex regulation. Today’s new information technologies and electro technologies feed off each other. Those that starve one will weaken both.

5. The ceiling of the possible is far above our heads

We are nowhere close to the technical limits of electrotech. We already know how to run grids with 70-80% renewables at costs comparable to fossil fuels. We can electrify around three-quarters of final energy demand with technologies that exist today or are nearly commercial. Renewables and electrification could more than triple from current levels before reaching what we know is achievable.

And the ceiling keeps rising. As frontrunner regions push grids toward 90% renewables and innovators bring electrotech into aviation, shipping, and heavy industry, the technical frontier expands. By the time most catch up to today’s ceiling, the pioneers will have raised it once more.

In 2026, expect more narratives about slowing deployment in leading markets. But most of the world is still catching up. This catch-up dynamic alone sustains momentum for years to come.

6. The physics of change

Fossil systems are inherently wasteful, losing about two-thirds of their primary energy to heat and friction. Electrotech is built on efficient electricity: EV drivetrains convert around 80-90% of input into motion, while heat pumps deliver three to five times more heat than the electricity they consume. Wind and solar avoid thermal losses altogether. Physics itself tilts the system toward electrons.

This efficiency advantage extends to materials. Electrotech uses eternal sunshine and wind rather than one-time use fossil fuels; therefore it needs roughly 50 times fewer raw materials than fossil equivalents. This gap widens as innovation continues to improve efficiency and reduce material requirements. We should expect 2026 to be another year of such innovations and commercializations—sodium batteries being one example to watch this year.

7. The economics of change

Electrotech and fossil fuels follow opposite economic trajectories. As demand for electrotech rises, new, more efficient factories lower production costs through learning and economies of scale. Solar, wind, and batteries sit on learning curves with costs falling about 20% per doubling. Solar module costs have dropped 99% since 1980, wind by 80%, batteries by 99%.

Fossil fuels work differently. As demand rises, new, more expensive fields must be developed, driving prices up. After decades of these opposing trajectories, we have recently hit cost parity for key electrotech—solar, battery storage, and EVs. Today that means solar-plus-storage in India at $40/MWh and Chinese EVs below $10,000.

This matters acutely for 2026. Affordability is the dominant concern across politics and policy. Five years ago, affordability pressures would have pointed toward fossils. Today, they point toward electrotech. The crossover has happened. The cheaper path is now the electric path.

8. The geopolitics of change

Three-quarters of the world relies on fossil fuel imports. Get cut off, and your economy grinds to a halt. Countries have fought wars over energy access and structured foreign policy around securing supply.

Those risks are rising. Trade tensions are escalating. Geopolitical fractures are deepening. In this environment, every country is looking for alternatives.

At some point, they will look up. The sun delivers energy everywhere. 92% of countries have the potential to generate at least ten times their own energy demand from domestic renewables. With electrotech, every country can become energy independent.

If 2026 is indeed going to be a year of rising geopolitical tensions as many expect, we should expect countries to accelerate electrotech deployment as a strategic priority. Those that sow electrotech will reap sovereignty.

9. Electrotech is a tool for rapid development

For decades, development meant following the fossil path. Rich countries burned coal and oil to industrialize, and emerging economies assumed they would need to do the same. Electrotech allows them to skip that step entirely.

The fastest change is now happening in emerging markets. ASEAN leapfrogged the US in electrification in 2023. Solar deployment has surged across Asia, Latin America, and Africa. In many countries, solar has gone from the smallest to the largest source of new capacity in less than a decade.

The pattern makes sense. Some 80% of the world’s population lives in the sunbelt, where solar resources are abundant and cheap. For countries building energy systems from scratch or expanding rapidly, solar plus storage offers a faster, cheaper path than fossil infrastructure. Development no longer requires a fossil-first pathway. Electrotech is becoming the foundation for growth.

We should expect more emerging market leapfrogs in 2026 as well as a pullback from fossil fuels. As solar and storage costs continue to fall, emerging economies will increasingly look to exit expensive LNG contracts in favor of domestic renewables.

10. Electrification is the geopolitical differentiator today

The world is rapidly building new electricity supply. Solar and wind capacity is being deployed at record pace. But supply alone does not determine competitive advantage. Today, the differentiator is electrification; putting that new supply to work by electrifying transport, heating, and industry.

China has grasped this. It is scaling both supply and demand simultaneously: solar farms and EVs, wind turbines and industrial electrification. This approach, which we call the electrostate model, uses domestic markets to drive down electrotech costs and improve quality, then capture export markets with superior products.

The West is deploying substantial new supply. But electrification of demand has lagged. Solar and wind without EVs, heat pumps, and industrial electrification is an incomplete strategy. As we move through 2026, the question is whether Western economies will match China’s integrated approach, or continue building only half the system.

Entering the second half of the decisive decade

For the first time, humanity can harness the power of the sun directly, at scale, and in real time. After a century of evolution, electrotech is breaking through in a decade of revolution.

The 2020s are this decisive decade. This is the decade when manufacturing reaches global scale, when uptake s-curves enter their steep ascent, and when costs cross over from more expensive to cheaper than incumbents. We have just passed cost parity for solar, batteries, and EVs. From here, the economic logic only strengthens—as do the physics and geopolitics drivers of change.

Countries and companies that recognize this shift will shape the next era of global competition. Those who resist will find themselves left behind. The revolution has its own momentum. 2026 is another year deeper into it.

For more, watch the conversation from DERVOS on Energy Dominance and the Electrostate featuring Daan Walter.

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By Alessio Scanziani, Energy Security Analyst
Shobhan Dhir, Critical Minerals Analyst
Mari Nishiumi, Consultant
Kentaro Miwa, Consultant
Tae-Yoon Kim, Head of Critical Minerals Division

Share of top refining country for energy-related strategic minerals, 2024

Stepping up global action on critical minerals security has never been more urgent. A clear priority is to develop diversified sources of supply for key critical minerals. However, inevitably, it takes time to develop new projects in both mining and refining. Strategic stockpiling of critical minerals can serve as an important protective measure to safeguard countries from supply shocks and disruptions while they develop new, diversified sources of supply. Strategic stockpiles provide a way for countries to strengthen economic and national security, while also helping to deter future export controls and limiting their impact.

Strategic stocks are an insurance policy against short-term disruptions

Strategic stocks – held specifically for emergency purposes with the involvement of the government – have demonstrated effectiveness across various sectors. A notable example is the oil market, where stockpiles have played an important role in mitigating severe economic impacts for decades. After the oil shock of 1973, IEA member governments established a mechanism to build up and pool emergency oil stocks to protect them from being held to ransom via oil supplies in the future. Since then, the IEA has coordinated five collective responses to major oil supply disruptions, helping to limit the economic impacts of shocks caused by natural disasters or geopolitical strife, most recently in 2022 following Russia’s invasion of Ukraine.

Critical mineral markets operate in a very different context from oil markets. The diversity of critical minerals, each with distinct market contexts, means that stockpiling is not a catch-all solution and its suitability can vary by mineral. It is also not a substitute for efforts to develop diversified supply sources that deliver fundamental security benefits. However, stockpiles can still play an important role in providing emergency supply and protecting industries and jobs. Strategic mineral stockpiles also bring several additional benefits. Even when they are not used, they send a signal to markets that sudden supply shocks or export restrictions need not immediately cripple the system. Some IEA Member countries such as Japan, Korea, and the United States hold strategic stockpiles of critical minerals that have protected industries from supply disruptions.

The build-up of critical minerals stockpiles and the need for stock rotation can also support diversification efforts by sourcing materials from projects outside the dominant suppliers, while also enhancing market transparency by providing governments with insights into pricing.

Strategic stockpiles should primarily serve to ensure business continuity and provide a buffer during supply disruptions, rather than to manage price volatility or influence market dynamics. Clear and transparent principles for stockpile releases, focused on addressing acute and short-term supply interruptions, can help prevent market distortion and maintain healthy investment signals that drive market development.

Designing effective stockpiling systems involves addressing a range of strategic questions including material form, governance model, costs, and financing

Amid mounting risks to mineral supply chains, many countries are showing growing interest in establishing stockpiling systems for critical minerals. In doing so, they need to address a range of strategic questions, including the choice of materials to stockpile, governance models, associated costs and financing mechanisms. Critical minerals vary widely in their physical forms, end-use sectors, market sizes, levels of pricing transparency, warehousing needs, and supply chain complexity. Each material therefore needs to be analysed individually, with stockpiling governance models tailored to its specific characteristics.

As part of the Critical Minerals Security Programme, the IEA has examined these issues in detail and developed a comprehensive database and model covering over 30 forms of strategic minerals that are used in the energy sector and have critical applications in AI, advanced technology, aerospace, and defence. This work involved developing an assessment framework to evaluate the supply and strategic risks for each material across multiple dimensions, exploring potential governance models, understanding warehousing requirements posed by the diverse forms that minerals take along their value chains, building cost models to estimate the expenses associated with stockpiling and examining possible financing mechanisms.

The IEA Critical Minerals Stockpiling Assessment Framework evaluates risks and warehousing needs

To determine which materials should be prioritised for stockpiling, the IEA Critical Minerals Stockpiling Assessment Framework was developed to analyse risks and challenges for each material across multiple dimensions: supply risk, the availability of alternative supply routes, strategic importance and the feasibility of stockpiling.

Criteria for determining materials for stockpiling under the IEA Critical Minerals Stockpiling Assessment Framework

When evaluating supply risks, the level of supply concentration in both mining and refining is a key factor, as relying on few dominant suppliers means that any disruption can immediately flip markets into shortfall. For gallium, graphite, manganese and rare earths, the top refiner, China, accounts for over 90% of global supply. High price volatility further complicates the development of new supply: for example, lithium, vanadium, rare earths and cobalt have exhibited much higher volatility than oil and gas. Many high-risk minerals are already affected by some form of export restrictions, such as rare earths, gallium, and tungsten, straining their supply chain. These restrictions highlight the supply risks but also indicate the procurement challenges of building strategic stocks for these materials.

The availability of alternative supply routes is another important consideration. For some materials, there are limited options for substitute materials, such as chromium for stainless steel, titanium for alloys requiring a high strength-to-weight ratio, and germanium for high-performance fibre optics, heightening the risks from supply disruptions. Additionally, many materials are produced as co- or by-products alongside other minerals, making their supply less responsive to demand or price signals. For example, gallium is mainly recovered as a by-product of zinc and aluminium production, tellurium from copper and lead, and germanium from zinc and coal.

The strategic importance of each material depends on the sectors in which it is used. When materials have applications in strategic sectors such as semiconductors or defence, their security of supply becomes a crucial factor for economic and national security. While strategic importance can be assessed at the global level, each country should also consider domestic vulnerabilities and dependencies to assess potential impacts on its overall security and resilience.

The feasibility of stockpiling varies by material as each mineral takes different forms along its supply chain. The form most suitable for stockpiling is generally the imported form – most exposed to disruption risks – that can be directly used domestically in case of a disruption, without the need for further processing abroad. A broad assessment of the properties of strategic materials that are imported by IEA Member countries highlights a number of warehousing challenges for certain critical minerals such as hygroscopicity (sensitivity to humidity), reactivity, hazardousness and fragility. For example, lithium hydroxide is highly sensitive to humidity and degrades quickly in air, reducing its shelf life to around six months, while lithium carbonate can be stored for much longer. Gallium has a melting point of around 30°C. These warehousing challenges can be overcome, for example through controlling temperature and humidity of warehouses, using advanced packaging to minimise contact with air and moisture, and rotating stocks of materials with short shelf life. However, these additional requirements increase the cost and complexity of stockpiling.

Assessment of stockpiling warehousing requirements for selected strategic minerals

Stockpiling governance models balance roles between government and industry

There is a spectrum of stockpiling governance models, with suitability varying by country and material. Governance models can be grouped into two broad categories based on where the minerals are physically stored: ‘government-held’ or ‘industry-held’, each with two main options. For government-held (centralised) stockpiling models, the government owns and manages the stockpile, either directly or through a public agency acting on its behalf. Industry-held (decentralised) models require companies to store strategic stocks in addition to their existing commercial inventories. For industry-held stockpiles, stocks may be industry-owned, where the government sets a mandate for a volume to be reserved for emergency use, or government-owned, where industry manages the stocks which are owned and purchased by the government. Companies that participate in these models may receive public support. Governments could also consider leveraging the expertise and assets of commodity traders to manage stockpiles more efficiently.

Most existing strategic critical mineral stockpiling systems are government-held and managed through public agencies. Japan’s mineral stockpiles are managed by its public agency; Japan Organization for Metals and Energy Security (JOGMEC), Korea’s stockpiles are handled through the Korea Mine Rehabilitation and Mineral Resources Corporation (KOMIR) and the Public Procurement Service (PPS), and the United States’ National Defence Stockpile is managed by the Defence Logistics Agency (DLA). China also has major stockpiles of critical minerals, but unlike the others, utilises a combination of governance models with material stored and managed by both government and industry.

Operating costs underpin total stockpiling costs, with financing, warehousing, and discounting as the largest components

The costs of stockpiling are comprised of two primary components: the material purchase cost and the operating cost. The material purchase cost is the significantly larger upfront expense; however, this is a capital cost that is converted into an asset (the stockpile), and the capital is recuperated when stocks are released or during stock rotation (when selling the stock back to the market before reaching the end of their shelf life). The net costs of stockpiling are therefore determined by the operating costs. Stockpiling costs are sometimes misconstrued with an overemphasis on the material purchase cost, whereas operating costs form the actual costs borne over time. The operating cost components include financing, warehousing, discount, logistics, material loss and administrative costs. Financing costs refer to the cost of using debt or equity to purchase the material, warehousing refers to the cost of storing the material, and discount costs reflect the loss in market value when selling the stockpiled material to the market after a period of storage.

Our analysis indicates that financing, warehousing, and discount account for the largest share of total stockpiling operating costs, but there are major differences in the share of each component by material. Financing costs are the largest cost component for high-value, lower volume materials such as gallium and germanium, while warehousing costs become more significant for larger volume, lower-value materials such as synthetic graphite and nickel sulphate. Stricter warehousing requirements can triple warehousing costs per tonne compared with standard metals; however, financing costs remain dominant for many materials, even those with the strictest storage requirements such as lithium hydroxide and rare earth permanent magnets. Materials with shorter shelf lives incur more significant discount costs under government-held models due to more frequent stock rotation. Industry-held governance models reduce these discounts as companies use the stocks directly rather than needing to sell them back to the market.

Stockpiling critical minerals entails relatively modest costs compared with the potential economic impacts of supply disruptions

Analysis of stockpiling costs at the aggregate IEA level indicates that the total net cost of stockpiling most critical minerals is relatively modest, particularly for many high-priority strategic materials such as gallium and germanium, which often involve low volumes. According to our analysis, for all IEA countries to stockpile six months of their exposed imports of gallium metal from the top supplier, the total operating costs of stockpiling would be around USD 800 000. By comparison, costs of stockpiling the same months of exposed imports of rare earth permanent magnets would be almost USD 90 million. For material used in much larger volumes such as lithium hydroxide, the costs only grow to just under USD 300 million.

Government-owned governance models have lower financing costs while industry-led models have lower discount costs and greater efficiencies

The appropriate stockpiling governance model varies considerably by material and depending on domestic context and supply chain structures. Government-owned operating models with access to lower interest rates are most cost efficient for high-value materials, such as gallium or germanium. Lower-volume materials with fewer specifications such as upstream concentrates or midstream rare earth oxides may be more suitable for centralised government-led models, if there are domestic facilities able to process them. However, materials with a wide variety of company-specific specifications, such as graphite anode material or rare earth permanent magnets, or with short shelf lives, such as lithium hydroxide, are often better suited to industry-held governance models, where companies can store the specific materials, they need and undergo stock rotation more efficiently. Government-owned, industry-held governance models combine some of the advantages of both models: reduced financing costs, greater logistical efficiencies and reduced discount costs.

Beyond material characteristics and cost considerations, stockpiling can also support the development of diversified projects. Government-led stockpiling operating models are better suited to procuring material from specific strategic projects, providing offtakes that enhance project viability. In industry-led models, it is harder to control where material is purchased from, but the government could still have a role in aggregating demand. Ultimately, the most suitable stockpiling governance model depends strongly on national circumstances. A hybrid solution using a mixture of governance models for different materials may be optimal for many countries.

There are multiple ways to finance strategic stockpiling, which depend on the governance model and domestic circumstances

In the case of direct management of government-held stocks, purchase and operational costs are typically financed directly from the general budget or through a special purpose fund. In case the government chooses to use a public agency to manage the stocks, it can provide loan guarantee for the initial stock purchase and cover the agency’s operational costs. In an industry-held model, most of the costs are borne by companies, but governments could contribute through several instruments, such as direct loans or loan guarantees, public subsidies, tax breaks or direct equity investments. In the government-owned, industry-held hybrid model, the government would typically cover purchasing and financing costs, while operating costs could be shared through an agreement between government and industry.

The IEA Critical Minerals Security Programme is a key platform for international cooperation on critical minerals stockpiling

The urgency of today’s challenges facing critical mineral supply chains calls for strong international collaboration to achieve greater economic and national security, and stockpiling is a key tool that countries are considering implementing or expanding. While the objective of stockpiles is to strengthen security of domestic supply, coordination with international partners can be beneficial to achieve greater security more efficiently and faster. Coordination on the timing for stockpile purchases and principles for releases could help ensure markets are not distorted. When procuring stocks, countries could also agree to support strategic projects that would increase global diversification or consider aggregating demand. When compatible with domestic policies, countries could also consider to co-locate stocks for greater efficiencies, especially for low-volume materials, or reserve production in countries with production infrastructure to be dedicated to emergency use. Close dialogue among partners also helps transferring knowledge on efficient stockpile management.

The IEA Critical Minerals Security Programme is a key international platform helping countries to explore strategic questions around developing domestic stockpiling systems and opportunities to strengthen international coordination. The Programme will continue to support IEA Members in their efforts on reviewing strategic stockpiling as a tool to enhance preparedness to supply shocks.

Seven recommendations for developing domestic strategic stockpiles of critical minerals

When developing or expanding domestic strategic stockpiles of critical minerals, governments should consider:

1. Assessing value chains to identify bottlenecks and determine the material portfolio, prioritising those materials with the highest supply risks for a specific country or region.
2. Stockpiling the form of the material imported to a country or region to enable rapid deployment during disruptions.
3. Preparing for potential future disruptions by considering materials exposed to major risks that are not yet subject to export restrictions.
4. Tailoring the stockpiling governance model to the materials of choice, for an overall stockpiling system that optimises cost and benefits.
5. Setting clear transparent principles for stockpile releases to respond to acute short-term supply disruptions, while maintaining robust investment signals for market development.
6. Closely involving industry across upstream and downstream sectors to design feasible and effective stockpiling systems and ensure their operational viability.
7. When compatible with domestic policies, leveraging international collaboration to optimise multiple domestic systems for greater efficiencies.

 

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By Normand Mousseau and Roberta Dagher

Record forest fires, under-utilized agricultural residues like straw and husks and struggling sawmills have left Canada with an abundance of undervalued biomass. If carefully and strategically managed, this resource could become a powerful ally in the fight against climate change.

Canada’s biomass sectors are facing significant uncertainty because of political and natural disruptions. The forestry sector was hit last year by new American tariffs announced by the Donald Trump administration on Canadian forest products, bringing the total duties imposed on Canadian lumber to 45 per cent.

The agricultural and agri-food sector is also particularly vulnerable, since it exports more than 70 per cent of its main crops.

In addition to facing these political uncertainties, biomass sectors are increasingly experiencing the effects of climate disasters. In 2025, fires had burned 8.3 million hectares of Canadian forests by Sept. 30, making it Canada’s second-worst wildfire season on record. With climate change, extreme weather events like wildfires and droughts are likely to become more frequent and intense.

Change is accelerating and risks are mounting. For industries and communities that rely on biomass, this is the moment to define a long-term role in the climate transition.

Biomass resources

Canada needs to move towards a carbon-neutral economy, and the biomass sectors have a key role to play in this transition.

The availability of diverse biomass resources in Canada’s forests and agricultural lands, combined with new technologies to convert them into bioproducts and bioenergy, makes biomass a potential solution for reducing carbon emissions in several sectors, including industry, construction and all modes of transport (road, marine, rail and air).

Biomass can be part of climate change mitigation strategies. Used properly, it can replace fossil fuels and products, and help store carbon in different ways: in sustainable materials made from wood or agricultural residues, in the form of biochar that traps carbon in the soil or through bioenergy with carbon capture and storage (BECCS), which prevents carbon released during energy production from entering the atmosphere.

Several recent projects have demonstrated that interest in biomass feedstocks is high in many industries. In 2025, Canada’s first industrial-scale biochar plant was inaugurated in Québec, while the Strathcona refinery in Alberta will become Canada’s largest facility for renewable diesel.

The potential role of biomass becomes clear in the pathways now being modelled to achieve Canada’s climate goals. These analyses show that if a significant portion of available biomass were used differently, it would be possible to sequester up to 94 million tonnes of CO₂ equivalent per year through BECCS and biochar.

These results underscore the need for Canada to carefully plan new project developments and judiciously allocate biomass between its traditional and emerging uses.

Best uses for biomass

As we explain in a recent study, several factors influence the potential of biomass to reduce emissions, including the type of ecosystem where it’s harvested, the efficiency of its conversion, the fuels used and the products it replaces in the sectors concerned.

In other words, the climate benefits of biomass are not automatic: they depend on the choices that are made at each stage of the value chain. For example, if the processing or transport of resources requires a lot of fossil energy, or if the final product displaces a low-emission alternative, the climate benefit may be marginal or even negative.

Using biomass effectively requires understanding what resources will be available under climate change and their true potential to cut emissions. That potential depends not only on technological efficiency, but also on the cultural, environmental and economic realities of communities.

Still no long-term vision

Decision-makers must avoid working in isolation and take into account the collateral effects of resource allocation. Practices in biomass sectors, whether in forestry or agriculture, evolve slowly. Forests, in particular, follow long growth and harvesting cycles, so the choices made today will influence emissions for decades to come.

Yet, despite the importance of its resources, Canada has no strategy or vision for the role biomass will play in the transition to carbon neutrality by 2050.

Canada has developed several bioeconomy frameworks, including the Renewed Forest Bioeconomy Framework (2022) and the Canadian Bioeconomy Strategy (2019). However, there is still no comprehensive strategy that defines the role biomass will play in achieving a carbon-neutral future, either in energy-related or non-energy-related sectors.

Read more: Océans : les poissons, un puits de carbone invisible menacé par la pêche et le changement climatique

Canada can draw inspiration from its own Canadian Hydrogen Strategy to develop a similar strategy for biomass, based on integrated modelling of its potential in different sectors of the Canadian economy. There is an urgent need to adopt a realistic approach based on analyses at multiple scales — from regional to national — rather than on isolated sectoral targets.

Many players in the sector are stressing the urgent need to adopt a clear national strategy for the bioeconomy in order to provide more predictability to biomass industries in Canada. In an article in Canadian Biomass Magazine, Jeff Passmore (founder and president of Scaling Up) says he’s been waiting for Canada to develop a concrete national strategy for the bioeconomy.

Another article in Bioenterprise in 2023 argued that “one of the key areas needed to build the future of biomass in Canada is a solid, long-term national bioeconomy strategy, supported by industry and governments.”

Finally, a call to action from Bioindustrial Innovation Canada recommends revising the national bioeconomy strategy by setting measurable targets for interdepartmental and intersectoral co-ordination, with a clear road map for collaboration between industry and the public sector.

Biomass cannot be managed blindly. Its impacts vary depending on the region and uses. For future projects to truly contribute to Canada’s climate goals, a coherent national vision is needed now.

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By David Pickup

It’s a happy coincidence of timing: we need a lot more electricity generation, and fast — and we’ve also experienced more than a decade of price reductions in renewable energy.

A look at projects built in Canada shows a clear trend: contracted energy costs from wind and solar have been cut in half over the last 10 years, the period of time during which most projects were built in Canada.

These wind and solar projects provide concrete, local examples of how costs are coming down as the technology improves and the market matures. Each point in the graph below reflects one or more real projects from signed deals. Altogether, the deals come from procurements in seven provinces across Canada.

The utilities that operate the electricity systems in most provinces held competitive procurement processes to secure contracts. This gave the market the certainty to grow and build projects that deliver low-cost energy. To top off all that good news, analysts expect that the cost of renewables will continue to drop further by between 25 to 50 per cent over the next decade.

In contrast, the cost of new nuclear projects, including refurbishments, has risen over the same period, so that the energy delivered by nuclear projects contracted over the last couple of years will likely be two to three times the cost of energy from renewables projects contracted in that year. We estimate the Pickering nuclear refurbishment will deliver power at $266 per megawatt-hour (MWh), and the Darlington small modular reactor project will be $152 per MWh; compare that to wind and solar procured in Saskatchewan and B.C. at $64-110 per MWh.

It’s worth noting, too, that the energy from renewables will come along sooner — in the next three to five years — rather than 10 years or more for nuclear projects. It’s important to move quickly as forecasts across the country show a rapid and substantial increased need for additional electricity. For example, Ontario expects electricity demand will grow by 75 per cent by 2050, while Alberta expects a 26 to 44  per cent increase between 2024 and 2043.

Why the timing of the renewable energy price drops matters

A decade ago, wind and solar electricity generation were more expensive than other types of generation. But since then, prices have dropped steadily. Now, they’re the lowest-cost form of new electricity generation, according to the grid operators in Alberta and Ontario, as well as global analysts.

The timing of this price drop could not have come at a better time. Electricity demand is surging to accommodate the electrification of vehicles, home heating and industrial processes, so provinces across Canada are making crucial decisions about how to add more electricity to their systems. Getting more affordable electricity generation onto the grid —  fast — underpins the competitiveness of the economy.

How electricity users benefit when renewable energy is added to the grid 

Even if solar panels or wind turbines are not on your shopping list, your budget can still benefit from a growing clean energy sector. That’s because when the most affordable forms of new electricity generation — namely solar, wind and battery storage — are added to the electrical grid in your province or territory, they help keep electricity prices low for everybody.

The biggest cost involved in the life of a wind or solar farm is the upfront capital cost to build the infrastructure. Once they’re built, they run on free fuel (wind and sunshine), unlike natural gas or nuclear plants.

There are effective ways of making sure this low-cost energy is still available when the sun sets and the wind isn’t blowing. Ontario figured this out when it contracted 1,885 megawatts of battery storage capacity in its first long-term procurement. Extra wind and solar power is stashed away during peak energy producing hours and is discharged to the grid when it’s most needed. The province is also harnessing energy savings by working with electricity consumers to reduce demand when necessary, and it’s building transmission lines to move energy from high production to high consumption areas.

The overall cost reductions of renewable energy over time and the continued low operating costs are the reasons why 93 per cent of new electricity infrastructure built in the United States last year was solar, wind and batteries. It’s also why renewable energy overtook coal as the largest source of electricity worldwide in 2025.

Where clean energy is being added to the Canadian grid now

Canadian provinces, having recognized the value of adding more renewables to their electricity mix, are scaling up calls for wind and solar project proposals in 2026. The fact that they’re using competitive auctions to secure the additional electricity means they’re getting the best value for their dollar. Here’s what we’ll be watching this year:

• Ontario: Over four years, the province is running a technology-agnostic competitive bid process for up to 7,500 megawatts (MW) of new energy and capacity. It’s open to wind and solar developers, as well as energy storage projects and natural gas plants. The first round of results are expected in April.
• Quebec: Hydro-Québec announced plans last year to develop 10,000 MW of wind and 3,000 MW of solar energy by 2035. The first call for tenders for 300 MW of solar energy is opening in April.
• B.C.: BC Hydro launched a bid process in 2025 to acquire up to 5,000 gigawatt hours per year of new clean or renewable energy projects. For comparison, this is roughly equivalent to either 1,600 MW of wind or 2,500 MW of solar. BC Hydro got 14 proposals totaling more than 9,100 gigawatt hours per year, nearly double the targeted amount, and final results are expected in the coming months.
• Manitoba: Manitoba Hydro is procuring 600 MW of wind power this year, with the official request for proposals coming out in March.
• The territories do not have centralized renewable energy requests for proposals. They’re typically smaller community-oriented projects, funding programs, and utility procurements rather than large multi-hundred-MW auctions. Our recent report, Restoring the Flow, explores the status of policies supporting Indigenous-led clean energy in remote communities.

However, a couple of provinces are choosing to go a different direction with new energy needs, and are missing out on the opportunities of low-cost renewable energy:

• Alberta: Until recently, Alberta led the country in renewable energy deployment. However, after a series of major policy changes, the market is stalling, as our report from last year highlights.
• Saskatchewan: The Government of Saskatchewan decided in the middle of last year to extend its coal fleet to power its grid until nuclear plants come online sometime later in the century. Although it is also procuring some renewable energy, we believe the decision to extend coal is going in the wrong direction.

The provincial and territorial governments with the foresight to take advantage of the low-cost electricity available from wind and solar can do so by planning their systems around a modernized grid. This means harnessing the latest technology — including interprovincial interties, demand-side measures and long-duration energy storage — to manage their energy in a way that delivers affordable and reliable electricity as demand grows.

2026 will be another exciting year for clean energy in Canada as federal, provincial and territorial governments adjust to the new reality of low-cost renewable energy and make crucial decisions about the future of our energy supply.

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By Jake Bittle

Since his presidency began last year, Donald Trump has embarked on an all-out campaign to destroy the nation’s nascent offshore wind industry. He has halted all wind lease sales in federal waters, issued stop-work orders for nearly-completed wind farms, and told oil industry executives that his “goal is to not let any windmills be built.” Last month, his Interior Department said it would terminate five major wind farms that are under construction in the north Atlantic Ocean, citing vague “national security” issues. These wind farms would together generate around 5.6 gigawatts of power, enough to supply around 4 million homes.

Trump’s actions have all but destroyed the U.S. offshore wind industry, which was already facing significant economic challenges during the Biden administration. While developers behind the terminated wind farms recently secured court orders allowing them to complete construction, other potential wind installations have been scrapped, and investors are retreating from offshore projects. Even as solar energy continued to grow at a rapid clip in 2025, wind saw virtually no growth in the United States.

That’s not just bad for the climate — it will also make it harder to keep the lights on in the U.S. northeast.  The nation’s densest region is counting on dozens of new wind farms to meet rising power demand; the stretch of coastal states from Maine to Virginia have collectively committed to buy more than 45 gigawatts of offshore wind power by 2040, almost ten times more than the five nearly-complete projects will provide. The region does not have many other good options for filling the gap. Without wind, residents of states like Massachusetts and New York will pay more money for dirtier fuel. The energy future of these states now hinges on whether they can tempt offshore wind developers back to a market that the federal government has just spent a year destroying.

“The market is at less than zero confidence right now,” said Kris Ohleth, director of the Special Initiative on Offshore Wind, an independent organization that supports the buildout of the industry.

The country’s first crop of major offshore wind farms has been a generation in the making. Developers have been trying to sink steel turbines onto the ocean floor since the turn of the century, but their projects collapsed amid high costs and community opposition. It wasn’t until the Obama administration that the federal government laid the groundwork for wind leases in federal waters near Long Island, conducting landmark studies that identified ocean zones where wind is strongest and environmental risks are lowest. That attracted major renewable energy developers like the Danish firm Ørsted and the Norwegian company Equinor, who leased territory in the north Atlantic and sketched out billion-dollar wind farms.

Even before Trump, these projects were on shaky financial ground. Ørsted and its peers signed power contracts with states including New York, New Jersey, and Massachusetts before the COVID-19 disruptions, but pandemic-driven shortages and the supply-chain chaos of Russia’s war on Ukraine drove up costs for construction materials like steel and copper. State governments also demanded developers put up more money for port improvements and onshore manufacturing jobs.

At the same time, developers encountered a wave of opposition from fishermen’s groups, conservative activists, and shoreline residents concerned about their ocean views. Prominent Republicans like U.S. Representative Jeff Van Drew of New Jersey championed these groups. The opposition filed several lawsuits that slowed down the permit process for a few major wind farms, with one suit even reaching the Supreme Court.

“These were new, first-of-a-kind-in-the-U.S. permits, and we were trying to improve the permitting process as we were going along,” said Elizabeth Klein, who led the Interior Department’s Bureau of Ocean Energy Management under former President Biden. (Klein said that by the end of Biden’s term the average environmental permit review took between two and three years, much longer than the more established procedure for offshore oil and gas.)

After the 2024 election, Trump’s sudden assault on the industry destroyed what little investor confidence was left. Even though several companies still hold leases that give them the right to build wind farms in federal waters, the industry has frozen in place. Other than the handful of major wind farms that are suing Trump for permission to finish construction, there are no large-scale projects in the pipeline. This freeze stands in stark contrast to the fate of solar energy, where installed capacity grew by 27 percent in 2025.

“In order for someone to get a commercial gleam in their eye, you need alignment with the federal government, the state government, and the market,” said an energy consultant who has advised offshore wind developers. “That’s gone, and it makes projects literally impossible. There’s no beating around it.” (The consultant requested anonymity in order to speak frankly given federal government backlash against the wind industry.)

Though the Biden administration focused primarily on the north Atlantic, it also auctioned federal wind leases in places like South Carolina, Louisiana, and Oregon. Klein believes that those states may now turn away from offshore wind given the market turmoil — and also because they have increasing access to alternatives like solar and cheap natural gas.

The Northeast does not have the same luxury. It is too dense and too cloudy to allow for large-scale solar farms, and other baseload power sources like nuclear will be hard to site, given population density and local opposition.

“There’s no other energy source coming to save them,” said Klein.

The situation is most acute in New England. In a report analyzing decarbonization scenarios, the energy nonprofit Clean Air Task Force found that offshore wind would have to make up almost half of all power generation by 2050 for the region to fully decarbonize. But it’s not just that these states need offshore wind to ditch fossil fuels. Experts also say that, with federal support, wind could be both the easiest-to-build and the most reliable power source for New England. That’s in part because communities across the region have mobilized against new gas pipelines and power plants. Furthermore, the region’s winter power needs will increase as more homes switch away from heating oil and begin to use electric heat pumps instead. Offshore wind turbines also fare much better in cold weather than power plants fuelled by natural gas and oil.

“For all the difficulties, building [wind] and interconnecting is easier than almost anything else you would do,” said John Carlson, the senior Northeast regional policy manager at Clean Air Task Force, which co-produced the report on New England’s decarbonization. “At the end of the day, this has to happen. There isn’t another option.”

The first prerequisite to a revival of the industry would be a cooperative federal government. Given how long it takes to build a wind farm, many experts believe that some form of permitting reform will be necessary to tempt investors back into the market. Clean energy lobbyists and oil industry groups alike have endorsed bills that would prevent presidents from pulling already-approved permits, but Congress has yet to pass one. The most recent negotiations collapsed after Trump’s attempt to terminate the five major wind farms. (Beyond the five nearly-complete wind farms, there are several more projects that have obtained most or all of their federal permits, and their developers may just try to wait out the administration.)

But there are other constraints, one of which is money. Industry insiders say global firms like Ørsted and Equinor have little desire to make further investments in the U.S. market, though they’re still holding on to their federal leases in windy sections of the ocean. There may be smaller developers who may want to take the leases off their hands. Before the current crop of massive European-built wind farms, smaller American developers tried to build minor farms along New England’s coast. These projects collapsed amid local opposition, but it’s possible that American energy developers may now want to get back into the fray. (Both Ørsted and Equinor declined to comment on their future investment plans.)

The problem is that these smaller companies will have a harder time borrowing the billions of dollars it takes to build big wind farms, and they may need to charge more money for the electricity they produce. Experts say that state governments in the region will likely need to grease the wheels for investment by putting up taxpayer money rather than asking developers to bear all the costs.

“The ability for the state to de-risk the investment environment is enormously valuable in terms of making Maine an attractive state,” said Jeremy Payne, a lobbyist for the government affairs firm Cornerstone and the former director of Maine’s renewable energy trade association. Payne said that the state could attract investment by training wind workers or coordinating with neighboring states on transmission corridors for wind power cables, taking some of the work off the developer’s hands.

Infrastructure is also a key constraint. The first wind projects required states to spend hundreds of millions of dollars on port upgrades and onshore construction. Massachusetts has spent well over $100 million to upgrade the old whaling port of New Bedford so it can serve as a staging area for massive wind turbine blades that can stretch the length of a football field. New York built a similar wind staging area along the harbor in Brooklyn.

But this infrastructure is still not sufficient to support wind development on the scale that the region needs. The New Bedford port is just a quarter of the size of an offshore wind terminal under construction at the port of Rotterdam in the Netherlands, and it may be too narrow to accommodate some large vessels. Massachusetts is planning to build a second facility in Salem — but Trump canceled a $34 million grant for that project, and its future is now uncertain.

The states along the eastern seaboard must invest now in order to make it easier for future projects to get off the ground. That includes upgrading transmission infrastructure, investing in workforce training, and expanding ports to accommodate larger turbines.

“We understand that whatever we’re doing now, we’re doing for 2029 or maybe 2030,” said Bruce Carlisle, the managing director of offshore wind for the Massachusetts Clean Energy Center, a quasi-state agency that supports the buildout of renewable energy. “We want to make sure we’re balancing state investment with realistic timelines.”

At the same time, Carlisle said states may not get all they originally wanted from wind projects. In the first go-round, states pushed developers to hire local workers for manufacturing and assembly, but Carlisle now says that the states may need to walk some of those requests back, because they will further raise costs for developers. Instead, states may need to let developers source labor and materials from Europe — which has built out far more offshore wind and therefore has a developed labor force and supply chains already — rather than demanding they build out a U.S. manufacturing base.

Given that President Trump has refused to issue new permits for offshore wind, it will likely be impossible for states like New Jersey and Massachusetts to achieve their current procurement targets on time. In the rest of the country, planned projects may never materialize. But offshore wind will still dominate the Northeast power grid in the long run, even if future projects are more expensive and require more state support. For all the blows the industry has taken, the region just doesn’t have good alternatives.

“I think it’s more a question of ‘when’ than ‘if,’” said Ohleth.

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By Gaye Taylor

Senior Chinese officials arrived in Davos, Switzerland this week speaking the language of multilateralism. They ended the week correcting the United States president after he dismissed wind power and doubled down on oil and gas.

During his keynote address at the World Economic Forum, Donald Trump ranted that China has no working domestic wind farms, or more specifically, that he hadn’t “been able to find any” beyond a handful that he claimed were marketing backdrops used to sell wind turbines to “stupid people.”

China was swift to bat away Trump’s disinformation, noting at a press briefing that it has been the global leader in installed wind capacity for 15 consecutive years, reports Reuters.

“China’s efforts to tackle climate change and promote the development and application of renewable energy in the world are obvious to all,” foreign ministry spokesperson Guo Jiakun said, adding that the country’s exports of technologies like solar and wind have helped other countries reduce their carbon emissions by over four billion tonnes.

“As a responsible developing country, China is willing to work with all parties to continue to promote the global green and low-carbon transformation,” Jiakun said.

Vice-Premier He Lifeng had spoken at some length on this theme during his own main stage address, some 24 hours before the American president arrived.

“China will work with all other parties to fully and effectively implement the United Nations Framework Convention on Climate Change and the Paris Agreement, uphold the multilateral process on climate change, and actively promote global green and low-carbon development,” he said, just a couple of weeks after Trump withdrew the U.S. from the UNFCCC and five dozen other international fora. Earlier in his address, the vice-premier had pledged that “we are committed to building bridges, not walls,” vowing to “work with all parties to foster closer partnerships for green development.”

For his part Trump “pronounced last rites on American leadership of the liberal democratic order” in his address, as the New York Times put it. He prompted multiple analysts to compare his speech to mob boss language, declaring that “Canada lives because of the United States,” and that “after the [Second World War], we gave Greenland back to Denmark. How stupid were we to do that?”

He derided the energy transition as “the green new scam,” belittling Europe for its continuing efforts to decarbonize.

“Natural gas production is at an all-time high by far and oil production is up by 730,000 barrels a day, and last week, we picked up 50 million barrels from Venezuela alone,” Trump said.

Trump followed a pronouncement about America’s global lead in artificial intelligence with the claim that all AI facilities built on U.S. soil will be powered by brand-new oil and gas plants. “They’re even going coal, in some cases.”

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