The report, Path of Most Resistance, argues the province’s proposed pathway to net-zero electricity emissions by 2050 depends largely on natural gas plants equipped with carbon capture and storage (CCS), hydrogen fuel and future nuclear technologies such as small modular reactors (SMRs).

Those technologies could eventually play a role in reducing emissions, the Calgary-based think tank says, but relying on them as the backbone of the power system represents a series of “risky bets.”

The analysis comes as Alberta negotiates with Ottawa over the future of electricity regulation under a Canada–Alberta memorandum of understanding signed last November.

Under the agreement, the federal government has indicated it could suspend its Clean Electricity Regulations in Alberta if the province can demonstrate that its own policies would achieve equivalent emissions reductions.

Pembina says that outcome should depend on whether Alberta presents a credible and detailed alternative plan.

Heavy reliance on uncertain technologies

The report argues Alberta’s current strategy places a large share of its emissions reductions on technologies that remain expensive, uncertain or years away from widespread deployment.

Carbon capture has been demonstrated at only a handful of power plants globally. Small modular reactors are still under development, with most projects not expected to come online until the 2030s or later.

Hydrogen, which Alberta officials have promoted as a potential fuel for power generation, also faces significant economic and technical hurdles, including high production costs and transportation challenges.

According to Pembina researchers, relying on these technologies to decarbonize Alberta’s grid could delay emissions reductions and increase costs if they fail to scale as expected.

Renewable growth slowed by policy changes

At the same time, the report says provincial policy decisions over the past two years have slowed the development of wind and solar power.

In 2023 the Alberta government imposed a seven-month moratorium on approvals for new renewable energy projects while regulators reviewed land-use rules and grid impacts. The government later introduced new regulations governing renewable development.

Since the moratorium began, nearly 11 gigawatts of wind, solar and energy storage projects have left the Alberta Electric System Operator’s development queue, according to Pembina analysis.

That amount of capacity exceeds Alberta’s average electricity demand.

The province had been a national leader in renewable energy development earlier in the decade, attracting the majority of new wind and solar investment in Canada.

But analysts say regulatory uncertainty and shifting market rules have made developers more cautious about building projects in Alberta.

Government emphasizes reliability

The Alberta government has defended its approach, arguing intermittent power sources such as wind and solar must be balanced with reliable generation to maintain grid stability and keep electricity affordable.

Provincial officials have pointed to natural gas, nuclear and emerging technologies as key components of a reliable, low-emissions electricity system.

However, the Pembina report suggests Alberta could reduce emissions more quickly and at lower risk by accelerating renewable deployment while expanding grid connections with neighbouring provinces.

Greater electricity trade with hydro-rich provinces such as British Columbia and Manitoba could help balance renewable generation by using hydroelectric reservoirs as a form of large-scale energy storage.

Industrial self-generation — including rooftop solar, geothermal and on-site wind generation — could also help reduce demand on the grid while cutting emissions from heavy industry.

Negotiations with Ottawa could shape future

The negotiations between Alberta and the federal government could determine how the province’s electricity sector evolves over the coming decades.

If Alberta can demonstrate a credible pathway to reduce emissions while maintaining reliability and affordability, Ottawa may allow the province to regulate its electricity sector independently through an equivalency agreement.

But if the province’s strategy relies too heavily on technologies that take decades to scale, Pembina warns Alberta could risk missing emissions targets while other jurisdictions move ahead with cleaner power systems.

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On February 9, 2026, Tokyo Electric Power Company Holdings (TEPCO) confirmed the restart of the 1,356-megawatt Unit 6 at Kashiwazaki-Kariwa in Niigata Prefecture, with full commercial operations expected by mid-March. The reactor — offline since the 2011 Fukushima Daiichi accident for safety enhancements and regulatory review — will be the first TEPCO unit to resume service in nearly 14 years and is projected to generate about 9.5 terawatt-hours (TWh) annually once fully ramped up.

Japan now has 15 operating nuclear reactors with a combined capacity of about 33 gigawatts (GW), out of an operable fleet of 32. In 2024, this fleet produced roughly 83 TWh — about 9 per cent of total electricity generation — as nuclear capacity gradually returned after extensive safety reviews and public debate over nuclear energy’s role.

Impact on fossil fuel use and LNG imports

Analysts and government estimates suggest the added nuclear output from Unit 6 could displace about 1.3 million tonnes of LNG — equivalent to roughly 62 billion cubic feet of natural gas imports annually — if generation from nuclear substitutes for gas-fired power. That displacement figure reflects Japan’s ongoing effort to reduce reliance on imported fossil fuels for electricity, a legacy effect of all reactors shutting down following the 2011 tsunami and nuclear accident.

Natural gas previously accounted for about 33 per cent of Japan’s electricity mix in 2024, with LNG imports serving as a critical feedstock for gas-fired plants. Japan remains the second-largest LNG importer globally after China, though annual LNG demand has declined in recent years as nuclear and renewables have grown. Japanese companies imported roughly 9 billion cubic feet per day (Bcf/d) of LNG in 2025, down from about 11 Bcf/d in 2018, according to market data. Australia, Malaysia, Russia and the United States have been among Japan’s top LNG suppliers, with Australian volumes rising in recent years while U.S. shipments declined.

The increase in nuclear output also fits within Japan’s long-term energy strategy, which aims to raise nuclear’s share of electricity generation to around 20 per cent by 2040. Meeting that goal would require up to 30 reactors in operation, meaning some of the 17 currently non-operating reactors would need to clear regulatory and local hurdles before restarting. Three units have initial Nuclear Regulation Authority approval and six more are under review.

Renewables and policy context

Alongside nuclear, Japan’s power mix has seen renewable generation grow steadily. Solar capacity, in particular, expanded rapidly in the past decade, and preliminary statistics indicate that renewables accounted for more than 26 per cent of electricity generation in 2024, with solar alone contributing more than 11 per cent and hydro nearly 8 per cent. Fossil fuels, including coal and natural gas, still made up the majority of generation but have trended downward from levels exceeding 70 per cent earlier in the decade.

Japan’s evolving energy policies — including its 6th Strategic Energy Plan and the broader Green Transformation (GX) agenda — reinforce these shifts. The plans aim to nearly double renewable generation’s share and boost nuclear’s role by 2030 while reducing fossil fuel dependence significantly. Officials see nuclear as an essential part of ensuring energy security and reducing electricity price volatility, particularly in a country that imports roughly 90 per cent of its energy needs.

Historical and public sentiment backdrop

Japan’s reliance on nuclear power draws directly from its pre-2011 energy configuration, when reactors provided around 30 per cent of electricity. Following the Fukushima disaster, all reactors were taken offline for safety upgrades under new regulatory standards, and public opinion tilted sharply away from nuclear generation. That shift significantly increased fossil fuel use and raised energy import costs.

Efforts to restart large reactors like Kashiwazaki-Kariwa have often been met with local debate and scrutiny over safety and disaster preparedness. Approval from regional authorities has been essential for restarts, reflecting lingering public sensitivity to nuclear risks. Still, government policy revisions now emphasize maximizing both renewable and nuclear “carbon-free” power sources, signalling a broader acceptance of nuclear as part of Japan’s decarbonization trajectory.

Market and geopolitical implications

Bloomberg and Reuters reporting over recent years has underscored that Japan’s nuclear comeback is closely tied to broader energy security concerns, including volatile LNG markets and price spikes following global supply disruptions. Analysts have noted that a robust nuclear fleet could insulate Japan from some of these risks, particularly as competition for LNG supplies intensifies in Asia.

NPR highlighted the challenge Japan faces balancing safety, public sentiment and decarbonization goals, noting that nuclear restarts require meticulous regulatory oversight and clear communication to gain social license.

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By Naveena Sadasivam

For more than a decade, the clean energy economy has been on a steep growth trajectory. Companies have poured billions of dollars into battery manufacturing, solar and wind generation, and electric vehicle plants in the U.S., as solar costs fell sharply and EV sales surged. That momentum is set to continue surging in much of the world — but in the United States, it’s starting to stall.

According to a new report from the clean energy think tank E2, new investment in clean energy projects last year was dwarfed by a cascade of cancellations for projects already in progress. For every dollar announced in new clean energy projects, companies canceled, closed, or downsized roughly three dollars’ worth. In total, at least roughly $35 billion in projects were abandoned last year, compared to just $3.4 billion in cancellations in 2023 and 2024 combined.

“That’s pretty jarring considering how much progress we made in previous years,” said Michael Timberlake, a director of research and publications at E2. “The rest of the world is generally doubling down or transitioning further, and the U.S. is now becoming increasingly combative and antagonistic towards clean energy industries.”

Timberlake said the Trump administration’s attacks on renewable energy are the main driver of the slowdown. Companies began pulling back their investments shortly after the November 2024 election, when a victorious Trump telegraphed that he would promote fossil fuels over solar, wind, and other clean energy technologies. For instance, TotalEnergies, the French oil-and-gas giant, paused development of two offshore wind projects in late November 2024, citing uncertainty after Trump’s election. The company has not restarted the projects since.

Trump followed through on those promises once in office: One of his first actions in office was to pause leasing and permitting for offshore wind. The freeze resulted in several wind developers indefinitely pausing or abandoning their projects while lawsuits trickled through the courts. (Federal judges have issued judgments in favour of the wind companies in recent months.) Trump’s administration also pulled billions of dollars in funding for a range of clean energy projects and cancelled or retooled Biden-era policies favourable to the industry, such as energy-efficiency measures, IRS tax guidance, and loans for a transmission line expected to carry solar and wind power.

Congress, at the behest of Trump, also passed the “One Big Beautiful Act” over the summer. In addition to sunsetting lucrative tax credits for renewable energy production, the law hammered the electric vehicle industry from multiple sides: It ended investment credits supporting the buildout of battery manufacturers, and simultaneously nixed the $7,500 tax credit available to American consumers who purchase EVs.

Timberlake cautioned against pinning clean energy’s disappointing year on any one policy. While the One Big Beautiful Act was the “biggest signifier” of the shift, “the overall policy and regulatory attack” is to blame for the glut of project cancellations, he said. “It’s not an environment that encourages more investment because no one knows what six months from now will look like.”

Electric vehicle and battery manufacturing have been hit the hardest over the past year. Each sector lost roughly $21 billion in investment over the past year, according to E2’s analysis, which includes some overlapping projects that serve both purposes. The industries also lost an estimated 48,000 potential jobs. These two industries likely lost the most investments because they had been growing the fastest in recent years, meaning they had more projects in the pipeline to cancel or downsize once President Trump was elected. The EV industry’s outlook, in particular, changed once Congress repealed consumer tax credits made available by former President Joe Biden. That, along with the general policy uncertainty, led to automakers revising their expectations for EV demand in the U.S. and reallocating their investments accordingly.

Some states were hit harder than others. In 2025 alone, Michigan lost 13 clean energy projects worth $8.1 billion — more than twice as many as any other state, due to its role as the capital of the U.S. auto industry. Illinois, Georgia, and New York also lost billions of dollars in investments.

Many automakers that scaled back electric vehicle plans last year redirected those investments rather than abandoning them outright. Ford, for example, had originally planned to build all-electric commercial vehicles at its $1.5 billion Ohio Assembly Plant in Avon Lake. But after revising its EV ambitions, the company pivoted the facility toward gas-powered and hybrid vans. Because Ford did not scrap the plant altogether, Timberlake said, facilities like Avon Lake could still be retrofitted for electric vehicle production if market conditions and policy outlooks improve.

“The silver lining view is they’re hopefully maintaining those facilities so that when there is certainty, those factories will still be available for making EVs down the road,” said Timberlake.

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By Gavin Pitchford

I was absolutely gobsmacked earlier this week by just how pervasive certain myths are, and realizing how much work we in the clean economy have to do before Canadians will believe we can make the transition.

And before a critical mass of Canadians see the clean economy as a real option that can displace the fossil fuel industry as an engine for prosperity, employment, improved health, a better environment, and also, a little climate action.

At the invitation of greenwashing expert Dr. Wren Montgomery (Clean50 2026), I took the clean economy show down Highway 401 to London, Ontario and Western University, my alma mater. I was addressing two fourth year Honours Business Administration (HBA) classes at Ivey, arguably Canada’s top business school.

Before I began my description of Canada’s clean economy, I asked both classes a lead-off question: What percentage does Canada’s oil and gas business contribute to our GDP?

Their answers blew me (and Wren) away.

The students came back with a wide range of responses. The closest, from just one of the ~20 students who answered, suggested 35%. Most of the others? Between 50 and 65%. One said 40% and a couple came in at 70%, with one outlier suggesting 90%.

It was literally breathtaking.

Murmurs of ‘Wow’

These are very sharp students. Some of them have already spent summers working for banks and consulting firms. And from all the attention we pay to the fossil fuel industry, the FUD (fear, uncertainty, and doubt) the industry spreads, and the amount politicians talk about it, students assumed its importance to Canada was literally 10 times bigger than it actually is.

Also of note, it’s only ~20% of Alberta’s GDP. Of course, if Premier Danielle Smith stopped making it impossible to roll out new wind and solar projects, that number would decrease quite rapidly.

My lecture then tabulated the clean economy numbers—clean/climate tech, renewable energy, green building, green fuels, biotech, venture investment, responsible investing, sustainability consulting. Counting only the numbers I could get with any accuracy, with lots of holes still to fill, the total for the clean economy was actually higher.

And so I was blessed to actually watch world views changing –and in real time!

We talked about where the fossil fuel industry is headed over the next 10 years (flat to down) vs. the clean economy (300% growth over next 10 years, if we keep pace with the rest of the world).

We talked about the incredible impact and massive risk of abandoned oil wells and the oil sands ($260 billion in estimated cleanup costs, with less than $2 billion held in reserve to do the job). How Big Oil offloads liabilities for cleanup by selling almost-depleted wells for pennies on the dollar to smaller companies that strip as much oil as possible—then abandon the business, the cleanup, and the liability, leaving taxpayers on the hook for yet one last VERY big subsidy.

To put this in perspective, the cleanup bill will get bigger, as 50% of existing wells are expected to become non-profitable/non-productive by 2030. And yet the cleanup tab is already half –HALF—of our federal budget for one year.

Solutions That Are Saleable World-Wide

They were dumbfounded all this information was not already well understood by Canadians. That no one had ever shared it with them. One perceptively compared the fossil industry’s misinformation to that previously spread by the tobacco industry.

And they wanted this information spread widely!

We had a couple of dissenting voices in the crowd. “I don’t want government support going to the oil companies—but I don’t want it going to clean tech, either,” said one. Several nods from the free market bros around the room.

So we talked about why clean tech companies should get government support and why oil companies should not: Because clean tech is in a start-up phase, because it’s where the jobs are and where many more will come from, and mostly because intellectual property is highly portable. Other countries want ours, and our best are being pursued with significant government support, matching and top-ups for building facilities, easier access to capital—the list goes on. It means tomorrow’s Canadian business leaders can be lured south to the United States, to Europe, and even to China. taking the jobs with them. And so Canada needs to keep pace with investment, or lose them.

Nods from the free market types. They got it now…

After a lot of further conversation, the students expressed genuine frustration that no one had ever shared these facts with them before, then asked what they could do.

And then they committed to calling their MPs. And I’m holding them to it!

If you want to add your comments, there’s a shorter version of this story posted on LinkedIn.

Gavin Pitchford is founder and executive director of the Canada’s Clean50 sustainability leadership award program and CEO of Delta Management. This post originally appeared in the weekly Clean50 newsletter, and has been edited to match Energy Mix style.

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The IEA’s annual Electricity 2026 report — released February 6 — finds that world electricity demand is set to grow by more than 3.5 per cent annually on average through the end of the decade, more than two-and-a-half times faster than overall energy demand. The report underscores that this surge is reshaping power systems around the world and accelerating what the agency calls the “Age of Electricity.”

IEA Director of Energy Markets and Security Keisuke Sadamori said the forecast reflects a fundamental transformation in how people and industries consume energy. “Meeting this demand will require annual investment in grids to rise by 50 per cent by 2030,” he said, adding that expanding system flexibility — including storage, demand-side management and market reforms — is equally critical.

Growth driven by electrification and digitalisation

The report identifies multiple drivers of rising electricity use. The global transition to electric vehicles, widespread adoption of heat pumps and air conditioning, and the burgeoning infrastructure for digital services and data processing all contribute to demand growth.

Independent analysis by Axios highlights how data centres — particularly those serving artificial intelligence and cloud computing — are emerging as some of the fastest-growing sources of U.S. power demand, with projections showing these facilities could account for roughly half of increased U.S. electricity consumption through 2030. This reflects a broader global trend in digital electricity demand.

Moreover, the expansion of electrification in emerging economies — especially China and India — is expected to account for the bulk of global demand growth over the next decade, reaffirming long-standing IEA forecasts that these regions will drive power sector expansion.

Renewables and supply mix evolution

The rapid increase in demand is being met largely by low-emissions sources and natural gas. The IEA report shows that renewables, bolstered by record solar and wind deployment, and nuclear power are together set to generate about half of global electricity by 2030. That would mark significant progress toward decarbonising power systems, even as natural gas output expands to meet demand and coal’s share declines.

Despite these gains, global electricity generation from fossil fuels is not disappearing in the near term, and utility planners are being challenged to integrate variable renewable output with reliable supply across regions. Bloomberg’s analysis of future grid capacity needs notes that integrating high levels of renewables without additional grid flexibility and storage creates technical and economic challenges that could slow emissions reductions.

Grid investment and flexibility imperative

A central theme of the IEA report is the imperative of modernising and expanding electricity grids. Existing infrastructure — much of which was built in the 20th century — was not designed for the scale and variability of today’s power systems. The agency warns that grids could become the “weak link” in clean energy transitions unless policymakers and investors act quickly.

Current grid investment levels lag behind the pace of renewable deployment, with thousands of gigawatts of wind, solar and battery projects stalled in connection queues worldwide. Without faster buildout of transmission and distribution lines, grid congestion and curtailment — where renewable output goes unused — could rise, reducing the economic and environmental benefits of clean power.

Beyond physical infrastructure, the IEA and analysts emphasise system flexibility measures such as energy storage, demand response, digitalisation and market reforms that can help balance variable supply and demand more efficiently. A recent World Economic Forum report highlights that enhancing grid flexibility could underpin resilience, reduce costs and unlock greater renewable integration by 2030.

Affordability and reliability challenges

Rising electricity demand also intersects with concerns about affordability and reliability. In parts of the United States, electricity prices have surged as ageing infrastructure and demand spikes from data centres strain existing grids, prompting political pushback and highlighting the social dimensions of power system evolution. Financial Times reporting notes that rising wholesale power costs are becoming a contentious issue in industrial and policymaker circles alike.

India, the U.S., and China are all projected to see notable increases in electricity demand through the decade, prompting varied responses from national policymakers on grid investment, electrification incentives and energy security measures.

As the world heads deeper into the Age of Electricity, experts and energy officials warn that investment in grids and flexibility is not optional — it is central to satisfying rising demand, reducing emissions and ensuring reliable power for economic and social needs through 2030 and beyond.

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By Mitchell Beer

An updated industrial carbon pricing system must deliver outcomes as well as optics, the Canadian Climate Institute (CCI) concludes this week, based on a review of 57 possible future scenarios for how Alberta’s emission pricing system can deliver on a target price of $130 per tonne of carbon dioxide emissions by 2030.

The $130 target under Alberta’s Technology Innovation and Emissions Reduction (TIER) regulation is built into last November’s controversial memorandum of understanding (MOU) between the Canadian and Alberta governments. But the climate institute warns there’s a difference between the advertised price per tonne in a carbon regulation and the effective marginal credit price (EMCP)—the real-world price a carbon polluter actually has to pay, and therefore the strength of the incentive they receive to reduce their emissions.

The institute released its analysis [pdf] this week as Environment and Climate Change Canada (ECCC) looks into whether the federal government’s current benchmarks for industrial carbon pricing “can distinguish systems that merely function from those that deliver outcomes of equivalent stringency,” the CCI paper states. Most of the 57 scenarios could meet the 2030 benchmark on paper, “yet fail[ed] to deliver stringency equivalent to $130-per-tonne EMCP.”

The analysis by CCI Chief Economist Dave Sawyer and Executive Vice President Dale Beugin found that:

• 84% of the scenarios met the federal government’s design criteria for a provincial pricing system;

• But of those apparently successful design options, 77%  failed to deliver the equivalent of a $130-per-tonne EMCP by 2030, meaning that only 11 of the original 57 succeeded.

A High-Stakes Review

The stakes for the ECCC review are high, the paper states, since this year’s decisions on system design and stringency will shape Canada’s industrial carbon pricing market into the 2030s.

The review is also taking place in a deeply politicized atmosphere, with Canada facing a serious sovereignty threat from south of the border and a separation referendum likely to take place in Alberta this year. “Against this backdrop, the federal government has launched a process to modernize large-emitter trading systems,” CCI writes. “The first track is regulatory and technical,” while “the second track is political and bilateral, centred on negotiations between Canada and Alberta.” The paper says the Canada-Alberta MOU sets the $130-per-tonne benchmark, but contains no plan or deadline to meet the stringency target.

The weaknesses in the current system have been accumulating for some time, the institute says. Existing large-emitter trading systems (LETS) “are opaque, rely on outdated design choices, and have been systematically weakened by provinces over time.” The federal government, meanwhile, has been inconsistent in its oversight and “reluctant to impose the backstop where provincial systems fall short, most notably as Saskatchewan zeroed out its industrial carbon price in 2025.”

But improving the system wouldn’t just make it easier to link provincial carbon trading systems and reduce disparities between polluters operating in different jurisdictions: “It would also help shield Canadian exports from rising border carbon tariffs, including the EU Carbon Border Adjustment Mechanism.”

Asked what it would take for the federal government to adopt a more consistent, evidence-based pricing strategy, Beugin replied that “grounding the benchmark in concrete, transparent metrics of stringency is the best way to shift the federal government’s approach to industrial carbon pricing. It’s currently too easy for provincial systems to comply with the federal benchmark without delivering robust carbon markets with strong incentives to invest in low-carbon projects.  That’s why we’ve proposed an approach that’s focused on market outcomes and ensuring a minimum effective carbon price in each system.”

In response to Trump’s annexation agenda and the separatist threat at home, the CCI’s plan would also “ensure provinces have plenty of flexibility in designing provincial carbon markets,” Beugin added in an email. “We’re suggesting that the federal benchmark makes provinces accountable for delivering an outcome (minimum effective carbon price) without being prescriptive as to how. Provinces can and should tailor their approach to their own context.”

An ‘Unresolved Tension’

However, in the consultation materials that ECCC released late last month, the climate institute said it detected an “unresolved tension” between the carbon pollution price signal the government wants to send and the tools it is proposing to assess polluters’ performance.

“By establishing minimum national stringency standards, the benchmark seeks to ensure that regulated facilities face comparable incentives to reduce emissions and invest in low-carbon technologies,” the CCI explains. But the gap is in the detailed factors ECCC is proposing to measure, including market balance, credit availability, and banking dynamics. “These considerations are necessary to ensure market operation and compliance feasibility,” the paper states, but they aren’t enough on their own to ensure that provincial pricing systems meet the federal target, and meet it on schedule.

“This distinction matters. The relevant question is not simply whether systems adopt the minimum national carbon price (MNCP) schedule, but whether the price signal delivered by the system achieves the intended outcome,” the CCI stresses. “Tests of net demand, market balance, and static banking metrics are useful for determining whether a market is operational. They are not sufficient for determining whether a system meets a given stringency requirement.”

The report identifies the size of the buffer—the extent to which a carbon pricing system adapts to keep the demand for carbon credits higher than the supply—as a key factor driving the stringency of the system. A 6% buffer, the level ECCC has proposed, is enough to keep a carbon market from failing. But carbon pricing systems only “begin to deliver stronger outcomes” with buffers of 10 to 305. They can only deliver reliable price signals, consistent with the federal targets, with buffers of more than 30%.

What Works, What Doesn’t

The CCI paper identifies tighter benchmarks over time as the single most important tool to create a scarcity of carbon credits and reduce emissions. By contrast, that stringency is severely diluted by direct investment credits that allow polluters to directly fund emission reduction projects instead and increase the number of carbon credits in the system while paying a lower carbon price.

“In the scenarios, introducing direct investment credits reduces costs by roughly two-thirds and cuts abatement by more than half,” the paper states. “The cost savings are therefore not a productivity improvement but rather a dilution of policy stringency.”

With a half-dozen policy options included in the analysis, the paper lays out a “clear hierarchy of levers,” Sawyer and Beugin write. “Benchmark tightening does the heavy lifting for equivalency attainment. Floor escalation and banking controls protect and stabilize the signal that benchmarks create. Credit and offset limits provide guardrails. Direct investment credits, by contrast, act as a dilution lever capable of neutralizing even aggressive benchmark tightening.”

The two authors recommend four steps to bolster the system:

• Strengthening the investment incentive for emission reductions—in an updated federal benchmark, and in the MOU—by basing it on what carbon polluters actually have to pay, rather than the average market price of the credits;

• Allowing Alberta and other provinces to find their own way to hit the $130 threshold “subject to a small set of non-negotiable conditions” to ensure their programs meet the test for stringency—including benchmarks that get progressively tighter, minimum and maximum prices that shift over time, and limits on compliance options that dilute the carbon price’s impact;

• Requiring data that is transparent and credible enough to verify compliance;

• Tracking performance over time.

“Taken together,” they write, “these recommendations support a benchmark framework that verifies equivalency based on outcomes rather than optics while maintaining flexibility in provincial system design and strengthening confidence that industrial carbon pricing delivers federal climate objectives.”

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By Tik Root

The logic behind electric vehicles benefiting public health has long been solid: More EVs means fewer internal combustion engines on the road, and a reduction in harmful tailpipe emissions. But now researchers have confirmed, to the greatest extent yet, that this is indeed what’s actually happening on the ground. What’s more, they found that even relatively small upticks in EV adoption can have a measurably positive impact on a community.

Whereas previous work has largely been based on modeling, a study published this month in the journal Lancet Planetary Health used satellites to measure actual emissions. The study, conducted between 2019 and 2023, focused on California, which has among the highest rates of EV use in the country, and nitrogen dioxide, one of the gases released during combustion, including when fossil fuels are burned. Exposure to the pollutant can contribute to heart and lung issues, or even premature death. Across nearly 1,700 ZIP codes, the analysis showed that, for every increase of 200 electric vehicles, nitrogen dioxide emissions decreased by 1.1 percent.

“A pretty small addition of cars at the ZIP code level led to a decline in air pollution,” said Sandrah Eckel, a public health professor at the University of Southern California’s Keck School of Medicine and lead author of the study. “It’s remarkable.”

The group had tried to establish this link using Environmental Protection Agency air monitors before, but because there are only about 100 of them in California, the results weren’t statistically significant. The data also were from 2013 through 2019, when there were fewer electric vehicles on the road. Although the satellite instrument they ultimately used only detected nitrogen dioxide, it did allow researchers to gather data for virtually the entire state, and this time the findings were clear.

“It’s making a real difference in our neighbourhoods,” said Eckel, who said a methodology like theirs could be used anywhere in the world. The advent of such powerful satellites allows scientists to look at other sources of emissions, such as factories or homes, too. “It’s a revolutionary approach.”

Mary Johnson, who researches environmental health at Harvard University’s T.H. Chan School of Public Health and was not involved in the study, said she’s not aware of a similar study of this size, or one that uses satellite data so extensively. “Their analysis seems sound,” she said, noting that the authors controlled for variables such as the COVID-19 pandemic and shifts toward working from home.

The results, Johnson added, “totally make sense” and align with other research in this area. When London implemented congestion pricing in 2003, for example, it reduced traffic and emissions and increased life expectancy. That is the direction this latest research could go too. “They didn’t take the next step and look at health data,” she said, “which I think would be interesting.”

Daniel Horton, who leads Northwestern University’s climate change research group, also sees value in this latest work. “The results help to confirm the sort of predictions that numerical air quality modellers have been making for the past decade,” he said, adding that it could also lay the foundation for similar research. “This proof of concept paper is a great start and augurs good things to come.”

Eckel hopes that, eventually, advances in satellite technology will allow for more widespread detection of other types of emissions too, such as fine particulate matter. That could even help account for some of the potential downsides of EVs, which are heavier and could therefore kick up more tire or brake dust than their gasoline counterparts. On the whole, though, she believes the picture overwhelmingly illustrates how driving an electric car is better not just for the planet but for people.

Research like this, she says, underscores the importance of continued EV adoption, the sales of which have slumped recently, and the need to do so equitably. Although lower-income neighbourhoods have historically borne the brunt of pollution from highways and traffic, they can’t always afford the relatively high cost of EVs. Eckel hopes that research like this can help guide policymakers.

“There are concerns that some of the communities that really stand to benefit the most from reductions in air pollution are also some of the communities that are really at risk of being left behind in the transition,” she said. Previous research has shown that EVs could alleviate harms such as asthma in children, and detailed data like this latest study can help highlight both where more work needs to be done and what’s working.

“It’s really exciting that we were able to show that there were these measurable improvements in the air that we’re all breathing,” she said. Another arguably hopeful finding was that the median increase in electric vehicle usage during the study was 272 per ZIP code.

That, Eckel says, means there is plenty of opportunity to make our air even cleaner.

Correction: This story originally misidentified the pollutant studied. It is nitrogen dioxide.

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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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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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