There is no denying that the rate of growth in EV sales in the US has slowed down. But an all-electric future in cars is still the general expectation among automakers. The feeling is that we’ll reach there, but it will be a bit slower than what the enthusiasm of two years ago suggested.

Most automakers that had revealed ambitious plans between 2020 and 2022 have scaled down their ambitions. Whether it’s automakers in the US or in Europe, all have modified their goals to 2030 and 2035.

Situation in the West

Recent actions and the general attitude of the current administration in the US about green technologies have dampened expectations of strong growth in the EV sector there. Many car makers are reviving gasoline models or delaying new EV models. But this is not the only challenge that exists in the US facing EVs.

People are definitely sticking to gasoline cars despite the growth in EV adoption in recent years. Cost and range anxiety are still major hurdles in the West.

Even before recent policy uncertainty, automakers were already seeing several persistent issues with widespread adoption of EVs. Most EVs being sold in the West are still more expensive than their gasoline counterparts, although that gap is falling. And even in the EU, which has a more supportive policy environment for EVs, the gap still exists, though it is narrower. Only in China have EVs become price-competitive with gasoline alternatives, largely due to the intense competition and falling battery costs in that market.

Range anxiety is still a big concern, especially in the US. Many car owners don’t have access to chargers on their home property and have to rely on public chargers. Lower per-capita public fast-charging access in the US will remain a hindrance to widespread adoption.

It is not surprising, therefore, that most EV owners are luxury car buyers who are buying EVs as a second car and who have private driveways and access to home charging for their EVs. Breaking into the general consumer market is still a challenge. But note that this is a very Western phenomenon. In China, EVs are already cheaper than gasoline counterparts, and government subsidies are helping increase their adoption faster than ever. And public access to fast charging is much higher there than in the West. So the major barriers that still persist in the West have already been broken down in China.

After a rough 2024 for EU automakers from experiencing sluggish car sales and the existential crisis of competition from Chinese automakers, the EU has eased some of the requirements on domestic manufacturers to meet climate goals, like relaxation of its CO2 emissions standard so that manufacturers can avoid fines and meet the longer-term climate goal more gradually, in order to give them a breather to better compete with rising competition in the auto sector from China, especially in the EV space. The policy environment in the EU is friendlier to EVs than in the US and that should push adoption further in the coming years.

Despite these challenges, though, the growth trajectory of EVs remains strong globally, mostly due to China, and is continuously eating into the share of the new car market.

And although EV sales growth in the US was slower in 2024 vs. 2023, it was not negative. More EVs were sold in the US in 2024 vs. 2023. And let’s not forget that over the previous five years, the growth, although starting from a low base, has been quite explosive.

Situation in China

The progress of EVs in China is clear when you see that around 1 in 10 cars sold in the US are electric, while in China it is around 5 or 6 for every 10 cars sold in 2024.

In China, the government is actively trying to promote the adoption of EVs and replacement of older gasoline vehicles. There is obviously an energy security imperative to it, as well as an opportunity to break into the global automotive market that has traditionally been the territory of Western firms. If China is on one end of the support spectrum, pushing the country to adopt EVs, the US is on the opposite end of this spectrum today, actively trying to choke demand appetite. Europe is somewhere in the middle with some supportive schemes still there while others have not been renewed, to give domestic automakers more time to adapt.

The cost of EVs is another factor that is helping China move to an all-EV market sooner than other countries. In China, a large majority of the new EV models sold are cheaper than their gasoline counterparts, even without incentives. In Europe, they sell at a 20% premium, while in the US, the premium is even larger. The falling cost of EVs, especially in China, is generally due to falling prices of critical minerals and intense domestic competition among its battery and car manufacturers. But those cheaper EVs selling in China are unlikely to be sold in the West, where both the US and EU are aggressively trying to protect their domestic manufacturers from Chinese competition. But it cannot be denied that Chinese manufacturers have gained an upper hand in both the technology and the manufacturing capabilities and are able to produce EVs that are better, at lower cost, and at much higher volumes than can be said of the manufacturers in the US or EU. They do have a leg up.

Another reason for faster adoption in China is the rate of deployment of public charging stations. This has made EVs accessible to a larger public that doesn’t have the convenience of home charging. In the US, access to home charging is more widespread, which has also resulted in slower public charging buildout. But lower per-capita charger access, especially fast-charging access, is a major factor behind range anxiety that still affects consumers.

Situation of the Jugglers

In the US, the over-ambition of automakers towards EVs over the past few years is becoming clearer. The new technology has not been easy to master and the billions spent on it have only amounted to losses. And despite EVs still being sold as a luxury offering by these companies, many are losing money on each EV they sell. Ford, for example, has not seen the excitement it had expected when it first launched the concept for the F-150 Lightning, in the sales. Ford’s EV division has been losing money.

Both Ford and GM had expected demand for EVs to skyrocket and had, as a result, made investment decisions to increase capacity for producing EVs and their components such as batteries. But both Ford and GM have either slowed work on those plants or canceled projects and have delayed the launch of EV products. Some, like GM, have started to embrace internal combustion engines more enthusiastically and see a full transition to EVs as a multi-decade gradual transition rather than a 2030 or 2035 event, a stark contrast in tone from just two years ago.

The losses and the changing market environment have meant that car companies have started to lift the pedal off the accelerator on their EV ambition. Consumer enthusiasm has changed quite starkly too. This can be seen by a sudden increase in enthusiasm for hybrid models over EVs. And this is something that is being observed not only in the US but in the EU too and also surprisingly in China, where EV growth is so strong. This is to a large extent because many consumers are still not satisfied with the charging capabilities of their EVs. And although they want to switch, there is still that persistent issue of range anxiety. Alongside traditional hybrids, there has been rising interest in Extended Range EVs that have an onboard gasoline engine whose sole purpose is charging the battery. These have started to become a popular option for those really concerned about range anxiety among those that really want to switch to an EV. Car companies have responded by delaying their pure EV offerings in favor of hybrid offerings, and many are considering bringing in bridge offerings like the Extended Range EV.

In the EU, the picture among the automakers is similar, although they have the added stress of competition from China—which is not the case in the US. Western manufacturers had built a competitive moat in the internal combustion engine vehicle. The complexity built into the design and production made it difficult for new companies to emerge quickly and outcompete incumbents either on quality or on cost. EVs are a technology disruption. For many traditional car makers, it is an existential challenge. Car companies that had built an expertise in building superior hardware—the Porsches and Lamborghinis and Ferraris of the world—are having a tough time adjusting to an all-electric future. What would separate a 500km range VW Beetle from a 500km range Porsche if speed, range, and drive are all similar? What else are they offering their customers? This is the most important question that the car industry is currently grappling with. EVs level the playing field by making the drive—the mechanical bits—of one vehicle mostly indistinguishable from the competitor’s. This is a nightmare scenario for companies that had built hardware niches and an opportunity for new players that see competition taking place in other avenues like cost, customer experience, and luxury features.

Part of the reason for automakers being hesitant in making a switch to EVs is because the policy environment today is starkly different than it was in 2022. Back then, buyers were being offered incentives for purchasing EVs and being penalized for purchasing internal combustion engine cars. And that meant that the higher profitable gasoline vehicles for automakers suddenly became less attractive offerings, and the choice among many companies was either to try to become the next Tesla on the one end or risk being left behind by the transition on the other end. Most were pushing to have as many EV offerings as they possibly could. Offering attractive EV concepts also meant shareholders were rewarding you amply by almost instantly boosting the stock price. The policy environment and consumer preferences led to this. There was a degree of irrational exuberance in all of this.

Today the direction of policy has gone the other way. Support for EVs by governments has fallen in both the US, since President Trump came into power, and at the national level in the EU, led by Germany. Automakers have reacted by offering more models that are hybrids or gasoline-powered. The hope is to bring back profitability. The trade war initiated by the US has also not been kind to automakers, and they are, broadly speaking, taking a step back from all the enthusiasm for EVs that was seen in 2022.

There has been a transition from an environment-focused narrative 3–4 years ago to what has been, in recent months, a complete reversal. There is now a sustained push to revive fossil fuel energy sources, especially in the US. Several forces have come together at the same time to bring this about, but I think there are three most visible ones that highlight the nature of the change and also perhaps bring a better understanding of why environmental focus was first embraced and why it has so quickly been abandoned.

Interest rates

Low interest rates seem as vanilla a factor as one can pick out from the assortment, and yet they’ve been, in many ways, a powerful driver. The world of finance works on profits and returns above any other incentive, even if sometimes the marketing of an investment may point toward altruism as the overriding factor.

In the rock-bottom interest rate environment from 2020–2022, and with an expectation of lower long-term rates, capital-intensive energy projects—renewables fall in this category—became attractive. The low interest rate also made funding these projects cheap and more attractive than lower capital intensity fossil fuel projects. There was another advantage of funding these projects—they helped investment firms market themselves as climate warriors who were leading the charge toward solving the climate change problem.

Marketing teams nicely wrapped up the action into something that investors could gobble up, that offered something other than just a potential for good return. Sustainability became a way to differentiate against other forms of investments.

But it was not expected at this time that inflation would emerge so quickly after the economic shock of 2020 and that the Fed would be set on a path of increasing interest rates. Higher rates emerging after 2022 deflated the interest in sustainability as capital-intensive projects became financially unattractive. A few other events also happened simultaneously that put fuel on the fire.

Ukraine

The war in Ukraine started in early 2022 and severely impacted gas supplies to the EU. This new environment meant that LNG projects would now not only benefit from their lower capital intensity vs. renewable projects in a rising interest rate environment, but would also benefit from better profitability because of higher natural gas prices.

Energy security now became a front-and-center concern. And the US had plenty of gas to offer, but not many ways to carry it across the ocean. Its LNG projects had seen severe restrictions from the Biden administration. Why curtail such a national treasure, the narrative went. It was also well understood that for critical minerals used in green technologies, the US was heavily dependent on China. And Russia’s actions had shown how energy security was so important for national security too. Thus, energy security, like in Europe, also gained prominence in the US.

But another force was also impacting the way we were thinking about energy.

Big Tech's changing priority

The growth in AI has now become the central priority for the big money investors who, in the past few years, had stated sustainable development as their central priority. And whether you call them FAANG, Big Tech, or Hyperscalers, they represent the biggest pot of money flowing in and out of the fast-growing sectors that have most interested investors in the past decade. And AI is now their central priority, overriding anything else.

The long-term survivability of their business is now tied to their superiority in AI. Losing this race—no matter how sustainably you do things—means losing investors. Shareholders might forgive you for missing sustainability targets, but they would walk away if you lose the AI race. Sticking to sustainability goals at the expense of AI capabilities would generally be regarded as a poor business strategy today. A CEO pursuing such a strategy would certainly be at a high risk of losing their job.

And AI superiority is not necessarily superiority of software. The race is now in hardware. Who has the most AI chips at their disposal? Who has the biggest data centers? Who has the most energy capacity available to them—with little concern for how clean that source is—to train their large language models and to answer the new energy-intensive search queries?

The need for firm power

Rising power needs due to growing capabilities and use of AI have also highlighted the need for firm power—uninterrupted power. AI data centers prefer energy sources that can deliver power on demand so that the data centers themselves don’t have to slow down when the sun stops shining or the wind stops blowing.

Today, grid stability is a front-and-center concern. There is a lot more awareness that intermittent sources like wind and solar are not a good fit for the needs of AI, which depends more on dispatchable power. There is also a growing awareness that as the intermittent sources become a larger share in the energy mix, it would make the grid more unstable if there is not a counterbalancing source that is large and flexible enough to offset their intermittent nature.

Therefore, it is not surprising that nuclear has seen a revival over the past 3 years, especially among the AI leaders who see it as the ideal off-grid option that wouldn’t require either a connection to the grid or a pipeline—both of which have shown several barriers to growing quickly enough. However, nuclear is also seen as only a long-term alternative and not a short-term solution since most next-generation projects have yet to build even a first-of-a-kind unit. But given nuclear is only a long-term solution, and given the priority for achieving AI superiority among companies and countries, favor for building more firm power sources that use fossil fuels has grown strongly, and their carbon intensity is no longer seen as a barrier. This has so far been for natural gas only; however, in some circles, there are growing calls for reviving coal as an energy source too.

Efficiency is not the first priority here

Big Tech companies are already reporting that their carbon emissions have increased by around 30 to 50% in the past 5 years, blaming this on the growth in data center energy consumption. AI queries are 10 times more energy-intensive than Google search queries. And although it may be tempting to think that AI searches have the ability to hit the bullseye in giving us the information we want on the first try, while we might spend significantly more time and energy, e.g., 10 to 20 Google search queries, to eke out that same information from the web, which is a reasonable claim to make, we should not forget that AI tools like ChatGPT have opened up unthinkable new avenues—like image generation or video generation—and created new use cases that were not even available to us before. This makes it a powerful new energy consumer. And given the priority today is acquiring power in an environment where the grid is becoming increasingly strained and a bottleneck to growth, and that acquiring firm power—especially from sustainable sources—to run AI data centers is becoming more and more difficult, it is not surprising that where the overarching aim is to achieve superiority in AI capabilities, it would most likely only happen by standing on the heap of ashes of a sustainable future.

That is not to say that there is no way to be found to make these systems more efficient in their energy use and function in a way that is more grid-friendly and more complementary to a renewable-heavy grid. For example, the heat management—which is a very energy-intensive part of data center operation—can be done more efficiently by placing data centers in cooler climates. Another way would be to use thermal storage techniques—like chilled water tanks or ice storage—which could allow energy used for cooling to align with renewable power generation, thus helping data centers to rely less on fossil fuel-derived firm power and therefore more on intermittent and environmentally friendly sources.

But there needs to be an incentive for companies to pursue these alternatives and make AI systems more efficient. Shedding the burden that Big Tech had once decided to bear and switching to fossil fuels is a simple solution to their problem. Political opinion today is clearly standing in their favor. Energy companies are planning new natural gas power plants at the fastest pace in years, driven by this new thirst for power, and are also cementing a new reality—that fossil fuels are going to stay around for longer than we had previously thought. Most investments being made in these plants come with an expectation that the plants will continue to produce power for at least a few decades. And there is such a rush for the gas turbines powering data centers that manufacturing backlog today is up to 5 years. This was seen as a dying sector just a few years ago.

And given the grid has become such a bottleneck to their growth, and given that it will always be a lot more difficult to expand the grid than to build a data center that needs its power, we will see a lot more cases where data centers either build their own power generators—whether it’s nuclear SMRs or natural gas turbine-based generators—or co-locate where the electricity generation plant is, or where the energy extraction is occurring. And that could mean that states that are producing the most natural gas could be very attractive destinations for data center companies that don’t want to deal with grid connection. Several states are clearly excited about this.

Implications longer term

If the use of natural gas continues to grow over the coming years—remember that new projects will stay operational for a few decades—and if the voice for climate change and sustainability also doesn’t vanish but, and this is reasonable to assume, only subsides temporarily before coming back stronger later in the decade, then we will see a growing acceptance of carbon capture projects to realign the reality to the commitments from countries and companies for reaching net zero around 2050.

Despite new priorities emerging today, the climate is still changing, global warming is still happening. At some point, a majority in society will come to a realization that action—urgent action—is required, if not for themselves and their world, then for the world that their kids and grandkids will inhabit. And given the way a new vigor is pushing the development of fossil fuels today, it would be very reasonable to think that a bright and profitable future will soon emerge for carbon capture projects to try and undo the damage. And these projects, while having faced intense criticism in the past, will then become a necessity. And even the past critics of such projects will be calling for more of them.

Is nuclear energy making any real progress? Or is the hype cycle fizzling?

Towards the end of 2023 and into 2024, enthusiasm for nuclear energy was growing stronger by the week, it seemed, and the uranium spot price touched $100 per pound. The reason was a realization that electricity demand in the US would grow rapidly over the coming years after being stagnant for decades, that there was a need for firm power to counter the growing share of intermittent resources on the grid, and there was also political acceptance for nuclear from most corners of the political spectrum to an extent not seen in recent history. AI bosses were singing its praises and putting actual money into making deals. AI’s future was pushing nuclear’s future too. The spot price has since then come back down into the 60s and 70s, although it is still higher than pre-2023 levels. What happened? Is enthusiasm for nuclear fizzling away after the first excitement, or is there actual progress being made? Undersupply is a concern. However, the uranium spot price is also a proxy for market enthusiasm for nuclear.

Although you cannot feel the same enthusiasm as you could back then, there is real progress being made. But there has also been a realization that nuclear will play a part, but it will be slow to scale, and perhaps it’s not the technology immediately available to aid the expansion of AI. By the 2030s, when nuclear might become available at larger scale and become a more scalable product, AI would have transformed our lives quite substantially.

Policy-side progress

World Bank

The World Bank recently decided to lift its ban on providing funding for nuclear energy projects. It would, in collaboration with the IAEA, fund projects that help extend the life of existing reactors and support grid infrastructure, as well as support the development and deployment of SMRs.

The World Bank’s changing view and policy stance is due to the changing views of many of its member countries that for many years had been staunchly anti-nuclear. For example, Germany’s new government recently decided not to stand in the way of nuclear energy development in the EU. It has indicated it would have no objections to France’s efforts to ensure that nuclear power is treated on par with renewables as a low-carbon energy source in EU policy. Other EU members are also slowly changing their tone on nuclear, like Denmark, which had a ban on nuclear power in the country for 40 years. Nordic countries Sweden and Finland are already supporters. Advances in nuclear power, especially SMRs that would incorporate advanced safety features and be easier to manufacture, have been a driving force behind the changing views in many nations that had previously been opposed to nuclear. A rapidly growing electricity demand and the issues that have emerged from over-reliance on a renewable-only grid have also contributed to the changing view. In the EU, the question of energy security is also front and center in the minds of many policymakers since the Russian invasion of Ukraine and the tumultuous natural gas supply situation several countries in the EU have found themselves in.

US decisions

If there is growing enthusiasm in the EU, that is still somewhat outshined by the enthusiasm in the US. President Trump recently signed four executive orders in order to push the industry and the regulators to increase the speed of decision-making and make it easier for the construction of new nuclear power plants. There is genuine support across the board for making it easier for the industry to construct new plants and to attract new investments. The current administration sees nuclear energy capacity growing from 100 GW to 400 GW over the next 25 years. To that end, there will be much faster approval for new reactors. AI data centers will be treated as critical defense facilities and therefore find it easier to be powered by advanced reactors. Dependence on foreign sources for nuclear fuel is also to be reduced, and there will be more support for mining, enrichment, conversion, and even recycling and reprocessing of nuclear fuel (including HALEU) in the US. Apart from the domestic effort, there is going to be more support offered to export nuclear energy technology to friendly nations.

In just two years, the policy environment and public acceptance for nuclear energy has starkly changed. The current environment feels so different from the pre-2020 era. And real policy changes mean that things are moving along. And the reversal from 10 years ago is unprecedented. The only concern is whether such actions—taken by presidential executive order—would mean lasting change. And it feels like it will be lasting, given there is positive support for nuclear from even those who had been the most anti-nuclear in the past. Public acceptance is another thing. And here also there is a stark difference from 10 years ago. This suggests that even though executive orders give a whiff of the temporary, these actions are more or less going to be of the permanent sort.

Private sector progress?

Westinghouse is praising its ability to develop large reactors like the one it did at Vogtle and is hoping to develop the 10 reactors that the government is aiming to start construction on before 2030. SMR developers also feel that they can fully compete with any large reactor builder by siting multiple units on the same site. For example, 12 of NuScale’s 77 MW reactors or 4 of Holtec’s 230 MW reactors can equal one 1 GW large reactor. The benefit of SMRs over large reactors is that more of the construction can take place in factories vs. on-site. And it would be more modular, requiring more quantities of smaller parts, which plays into cost reduction achieved from scaling the production. And this is obviously not lost on many investors.

SMR developers have raised over a billion dollars in funding recently. And these are not unsophisticated small investors but investors like Citadel that would not have invested unless they saw a real possibility of generating above-average returns on their investments. Hyperscalers like Amazon and Google have made real deals with these SMR developers, a few of which are working on really quite futuristic designs that we have never seen in the nuclear fission business outside laboratories—and perhaps that too only before the 1970s.

Recently, even the old reactors have received new lifelines. Last year, it was Microsoft’s 20-year deal to reopen the Three Mile Island nuclear plant. Last month, the news was centered on Meta’s 20-year deal for Clinton Nuclear Power Plant in Illinois, allowing the plant operator to boost output by building another reactor.

And this activity from both private and public sectors points to real action and real deals being made—and real progress happening in the nuclear industry. But why is it happening now? One has to put it down to two factors: the rising interest in AI and the realization that electricity demand will grow quite quickly, and a renewable-only grid will be vulnerable. That vulnerability can only be dealt with by investing in more firm power. Just before the election, one only heard about nuclear. Now, when it comes to firm power and rising electricity demand, natural gas is also increasingly coming into the picture.

The increasing acceptance of nuclear energy among the public today could have another underlying and deeper cause. At a more psychological level, nuclear’s rising acceptance could be attributed to the rise in other major risks—the kind associated most with human extinction. Such as environmental factors—foremost among them the rising risk of runaway global warming. Or epidemics—whether from a naturally evolved superbug or one manufactured in a lab. Risks posed by artificial superintelligence that would seek to replace human beings are also not far from our minds these days. These are also the topics of choice when it comes to portraying the end of the world in movies today, just as nuclear armageddon used to be in the 1990s. But these other risks have come to the forefront for the current generation, which is why nuclear might have become more accepted. And lets not forget that it is sometimes seen as a possible solution to solving some of our problems too.

Positioning:

The importance of rare earth minerals in our lives has grown so significantly—and their global control become so imbalanced—that they now stand as ideal candidates for weaponization in international trade.

Rare earth minerals hold a crucial place in today’s economy. A shortage of these often-overlooked and little-understood elements can bring essential sectors to a standstill. Despite their quiet presence, they are indispensable—and China’s dominance over them is nearly absolute, controlling close to 70% of global supply. These minerals are critical components in smartphones, electric vehicles, wind turbines, medical devices, and, most importantly, defense technologies. Their strategic value is rising, and their relevance is only deepening with time.

Sit-rep:

China’s grip on rare earth minerals is so firm that it is now using them effectively as a bargaining chip in ongoing trade talks with the United States.

In these negotiations, the U.S.'s dominance in semiconductor technology is a counter-leverage. But this isn’t the trump card it once appeared to be. Over the past five years, China has developed surprisingly advanced semiconductor capabilities. While it still lags behind the West—particularly in high-performance AI chips like those made by Nvidia—it’s closing the gap at a rapid pace.

The U.S., by contrast, has no immediate alternative to China for rare earth supplies. While efforts are underway to build domestic production capacity, any meaningful progress remains at least a decade away—if not longer.

Short term impact:

U.S. companies are already feeling the impact, with automakers like Ford forced to temporarily scale back production due to shortages of rare earth minerals—shortages driven by China’s tightening export restrictions.

The U.S. isn’t alone. Over the past two years, the European Union has increasingly limited China’s access to its markets, particularly in the green tech sector. In response, China is leveraging its dominance over rare earth supplies to pressure the EU into opening its doors to Chinese businesses.

Long term impact:

The mining capabilities of Western companies will become increasingly valuable in the coming years. Both governments and private sectors will be willing to pay a premium to secure supplies of critical minerals—materials that make up only a tiny fraction of a product’s total manufacturing cost, yet are essential to its production. Electric vehicles, for example, may rely on rare earths that account for less than 1% of the manufacturing cost, but without them, the vehicles cannot be built.

Why such restrictions are only temporary trade war weapons?

In the past, U.S. restrictions on China in semiconductors have only fueled domestic efforts in China to develop its own capabilities—something it has managed to do to a large extent, and quite rapidly. China’s restrictions on rare earths to the U.S. and EU are having a similar effect. They are pushing the U.S. and other Western countries to build supply chains free from Chinese control. So, China’s use of its dominance in rare earth minerals as a weapon will only be effective in the short term—until the U.S. and EU develop their own capabilities. Once that happens, China loses its leverage to use this control as a trade war weapon.

When it comes to using economic weapons in a trade war, there’s something to be said about their diminishing effectiveness over time—a decline that often occurs when there’s either a threat of use or actual use.

If a weapon is never used, and the wielder makes it clear—through trust—that it never will be used, the weapon gains strength, and the holder gains influence. This, of course, assumes that the weapon strengthens over time. If so, only through harsh use does the adversary feel compelled to stop, reassess, and invest in countering the threat—thus reducing the weapon’s long-term effectiveness. But if the weapon is never used, if trust is maintained, it can gain strength quietly, becoming more potent, more devastating, and functioning as a subtle deterrent.

The U.S. built its global hegemony partly by following this logic. Most of its allies have long been more dependent on the U.S. than the U.S. is on them, and until recently, the U.S. maintained that asymmetry. The allies, for their part, were content with the arrangement, as the alternative—a costly realignment—was less attractive. There was mutual trust. That trust has now been eroded by the U.S.’s recent protectionist stance, a stance that has rapidly spread to its allies. Historically, the U.S. had the privilege of using its economic dominance to align global thinking with its own.

We see the same pattern in the realm of dollar-based transactions. Most international trades were once denominated in dollars, but the increasing use of this financial control to impose sanctions on bad actors has pushed more countries to seek alternatives.

If a weapon is used—or even if trust erodes and the possibility of future use becomes real—then the weapon loses its strength, even if it is never actually deployed. It becomes a “use it or lose it” scenario.

If the U.S. had not restricted semiconductor supply to China, some argue companies like Nvidia might be more deeply embedded in Chinese technologies today. China might be more dependent on Nvidia and U.S. tech firms, rather than on its own domestic players—who may never have felt the pressure or received the support to develop local capabilities. One could argue that Nvidia would be a larger company today, with an even stronger network effect working in its favor. The U.S. would have more control over critical technologies used in China. From this line of reasoning, it follows that by restricting Nvidia’s chip supply, the U.S. showcased its dominance—but in doing so, it harmed Nvidia and itself more than it harmed China in the long run. It compelled China to develop its own semiconductor industry, which it has largely succeeded in doing.

The counterpoint is that trust had already been lost—or perhaps never existed. China always intended to build its own technology ecosystem and achieve self-sufficiency. In the past, when it allowed access to Western firms—auto manufacturers, tech companies—it was primarily to absorb their technology, only to eventually replicate it through domestic firms. China has already done this with considerable success.

In the case of rare earth minerals, the U.S. was slow to realize its dependence on China. It always saw China as a competitor, if not a rival superpower, and some had long voiced concerns about China’s dominance in rare earths, but serious efforts to diversify away from China have only recently begun—though arguably, the trend was already underway. China may have sensed that the effectiveness of this particular trade weapon was already declining, and that if it wasn’t used now during negotiations, it might lose its power altogether.

In today’s trade war, China seems to hold a more effective weapon with its control over rare earths than the U.S. does with semiconductors. Any deal between the two is unlikely to be heavily one-sided in favor of the U.S., as may have been expected on “liberation day.” Instead, it will likely be more balanced than the U.S. would prefer.

Frustrated by its inability to lift crude prices, Saudi Arabia has ramped up oil production over the past three months. Even before this latest move, many analysts anticipated a decline in oil prices—spurred by President Trump’s Liberation Day tariff announcements and expectations of slower global growth as a result. The kingdom has repeatedly tried to push prices higher, only to be undercut by fellow OPEC+ members who have failed to honor their production quotas. Their overproduction has blunted the impact of Saudi efforts, fueling Riyadh’s growing frustration. Now, there is rising concern that increasing output in an already fragile macroeconomic environment could flood the market with excess supply. Oil prices have already fallen into the $60s from mid-$80s just a few months ago, and there are concerns that if they remain at that level for long, it could severely hurt higher-cost producers. Ironically, this price decline aligns with President Trump’s desire for cheaper oil. But it also complicates matters for Western producers, who had hoped to expand under his administration after facing tighter restrictions during President Biden’s tenure.

What are companies doing? A recent report from the IEA noted that investment in oil production is expected to decline this year—a rare occurrence not seen in a decade, aside from the COVID-era downturn. The primary driver is lower prices, themselves a result of mounting macroeconomic uncertainty fueled by the trade war and surging OPEC+ output. This drop in investment stands in clear contrast to “drill-baby-drill”. The longer prices remain suppressed, the more pain producers will feel. U.S. oil production— near a record 13.5 million barrels per day—is likely to retreat. Shale producers in particular have begun sounding the alarm. None of this should come as a surprise. Yet whether we’re facing a short-term pause or a prolonged downturn will depend heavily on where oil prices head next. Hopes for a near-term recovery have all but faded, especially with Saudi Arabia ramping up production despite the fragile macroeconomic backdrop.

What is US government doing - encouraging more development? Some of the current administration’s moves run counter to the economic reality facing oil producers. President Trump, for instance, is pushing to lift the ban on Arctic drilling and reopen access to Alaska’s petroleum reserve. This effort hinges on executive orders that reverse Biden-era restrictions on new oil and gas leasing in the region. While executive orders offer speed, they lack permanence. For companies considering multi-billion-dollar investments in one of the harshest environments on Earth, regulatory stability—not political swings—is essential. Ignoring the low oil prices of today, without long-term policy certainty, few firms will risk committing capital to such ventures. Environmental priorities, too, appear cyclical. Just three years ago, ESG investing dominated the energy narrative and such projects were being actively shunned. Today, the pendulum is swinging in the opposite direction. But nowhere is the need for long-range consistency more urgent than in the Arctic—where hesitation will persist unless the policy climate becomes more predictable and durable.

How will low oil prices impact inflation? All else equal, falling oil prices tend to have a disinflationary effect on the economy. However, the extent of that impact is uncertain—and it’s unlikely to offer much relief against the inflationary pressures expected from the trade war over the coming months.

Deus ex machina: The sudden and escalating conflict between Israel and Iran over the past two days has made finding a clear signal in the oil market feel like trying to extract meaning from white noise. The unknowns are overwhelming. Oil prices have risen sharply into the $70s. Will the conflict spiral into a full blockade by Iran, cutting off crude flows through the Strait of Hormuz? Iran’s population is nearly ten times that of Israel—does that demographic weight matter here? Will the U.S. throw its support more openly behind Israel? Will Iran walk away from its nuclear hopes altogether? Could this erupt into a proxy war, with China and Russia backing Tehran? Or perhaps a deus ex machina causes the conflict to halt, and the headlines vanish as abruptly as they appeared. For now, we wait. And watch.

1. The purchase of South Korean company KHNP’s nuclear reactors by the Czech government has been halted by the EU, pending further investigation. Competition in nuclear energy is just beginning to heat up. But is it also starting to get dirty?

2. The cause of the recent country-wide blackout across Spain is still to be revealed. What might the implications be once the truth emerges?

3. President Trump’s recent trip to the Middle East highlighted the region’s ambition to take a stake in AI’s future.

4. Honda has scaled back its EV ambitions amid slowing demand. What does that signal for the future of electric vehicles?

The purchase of South Korean company KHNP’s nuclear reactors by the Czech government has been halted by the EU, pending further investigation. The decision came after French rival EDF alleged that KHNP had received unfair state support from the South Korean government—support that allowed it to underbid EDF for the Czech nuclear power project. The EU’s newly introduced Foreign Subsidies Regulation—invoked in this case—is designed to protect European companies from foreign competitors that benefit from distortive state aid.

Several EU nations are actively exploring the expansion of their nuclear energy capacity. Demand for nuclear power within the Union is poised to rise. Even Germany, long a staunch opponent, has shifted its stance recently—agreeing to categorize nuclear power on par with renewable energy. For European reactor and fuel manufacturers, this could represent a golden moment, a rare alignment of policy, demand, and public will.

But lower-cost foreign alternatives are increasingly viewed as a threat to domestic industrial capabilities. The precedent is clear: consider how China, through aggressive state-backed investments, came to dominate green technologies, rendering EU firms uncompetitive and dependent. Northvolt is merely the latest chapter in that unfolding story.

For the Czech buyer—the national utility—this intervention likely feels unjust. Any prudent buyer would naturally prefer the most cost-effective option. Nuclear plants, after all, are enormously capital-intensive undertakings, even under ideal conditions—which rarely materialize at this scale. EDF’s flagship project, Hinkley Point C in the UK, has suffered from delays and ballooning costs. By contrast, the Barakah Nuclear Power Plant, constructed by KHNP in the UAE, demonstrated a more successful track record, particularly in timely delivery. So the question arises: is EDF genuinely concerned about fairness—or simply trying to protect its neighborhood markets and future demand pipeline?

For Czech ratepayers, an EDF win could translate into higher electricity prices. The broader question is this: What should the EU prioritize? Opting for the lowest bid may entail awarding the contract to a foreign—possibly state-supported—firm. The direct benefit would accrue to EU consumers. In that light, one might see this as South Korea subsidizing Czech electricity bills. But that is a short-term view.

And therein lies the dilemma. Does a short-term economic gain come at the cost of long-term resilience? If EU-based companies lose market share and capacity, energy security risks grow. Again, the example of green tech looms large—one nation and its firms now command an outsized share of global production. That grip was forged not by innovation alone but by aggressive, subsidized expansion, which undercut foreign competition on both price and scale.

Yet even if KHNP did receive unfair state support, is there no advantage in allowing it to build reactors within Europe? Such projects unfold over decades and would likely deepen EU-South Korea strategic ties. State support does not inherently disqualify a company’s technical competence. Even without state support, KHNP may be cheaper and more effective. EDF, by contrast, may be trailing where it matters most.

Rather than issuing outright bans, the EU could consider a calibrated approach: impose targeted financial offsets to level the playing field. This would preserve competition while giving domestic players a real incentive to improve. Protection should not mean isolation. It should mean preparation—so that when the competition arrives, we are not merely shielding weakness, but cultivating strength.

The cause of the recent country-wide blackout across Spain is still to be revealed. What might the implications be once the truth emerges? Some have pointed fingers at the nation’s heavy reliance on renewable energy. Others suggest it may have been a deliberate act—an orchestrated cyber attack. Government officials remain skeptical of both claims, yet concede that a cyber intrusion, however unlikely, cannot be fully ruled out. Ongoing investigations are expected to shed more light.

Spain, owing to its geographic advantage, is rich in solar and wind resources, and has invested heavily in both. Today, nearly 70% of its power grid is supplied by renewables. This makes Spain one of the foremost examples of large-scale renewable integration in Europe. And so, when a nationwide blackout occurs, suspicion naturally falls on the resilience of a system so dependent on intermittent sources.

The question isn’t merely what caused the failure—but whether the grid’s architecture is robust enough to handle the volatility that comes with green energy at scale.

Why is it crucial that the investigation be thorough? It is well understood that increasing renewable penetration places additional stress on transmission infrastructure. Critics argue that Spain’s grid has not sufficiently adapted to the changing dynamics of decentralized, weather-dependent generation. If this blackout stemmed from technical shortcomings rather than malice, then identifying the exact fault line becomes vital—not to assign blame, but to extract lessons. Other countries, many of which are following the same renewable-heavy trajectory, depend on this knowledge to avoid similar vulnerabilities. Spain, in this context, becomes a case study.

But if the cause was cyber sabotage—then who stands behind it? Russia, as always, looms in the background. Spain’s geographic distance from Eastern Europe has long shaped its strategic posture. Unlike Poland or the Baltic states, Spain has not felt the shadow of Russia with the same immediacy. Consequently, defence spending has remained low—among the lowest in NATO—while domestic priorities have taken precedence. In Eastern Europe, public opinion more readily embraces military expenditure; the threat feels near, visceral, unforgotten.

If this was a cyber attack, and if it bore the fingerprints of Moscow, what would that mean?

Geography, once a shield, may no longer offer safety. The invisible front lines of cyber warfare bypass borders, oceans, mountain ranges. What does that realization do to a country’s psyche? To its politics? Does it lead to a reassessment of national security? A rise in defence budgets? Or does the moment pass—filed away as an isolated event, half-remembered by the next season?

President Trump’s recent trip to the Middle East highlighted the region’s ambition to take a stake in AI’s future. Projects like Humain, an AI hub launched by Saudi Arabia, are a step in this direction.

Why does the Middle East want this so badly? The region’s rise over the last five decades has been driven almost entirely by fossil fuels. But in a world increasingly moving away from them, any petronation that fails to reposition itself—fails to diversify its economy—risks years of stagnation and declining wealth. AI is seen as a critical opportunity to shift away from traditional strengths and build a more resilient economic foundation.

What are the Middle East’s advantages? The ability to deliver massive projects quickly has long defined cities like Dubai and Doha. Saudi Arabia’s Neom city—despite recent funding challenges—still stands out for its ambition, unmatched in scale by anything comparable in the West. The region’s autocratic systems provide the centralized authority often needed to push through large infrastructure projects fast. It also has abundant energy—not just oil and gas, but also solar and wind. And NIMBY is not a phrase many Saudis are familiar with. Then there’s capital. Sovereign wealth funds, built on decades of oil revenue, offer a deep pool of investment that AI companies will be eager to access.

The Middle East wants to position itself as a place where AI companies can build data centers quickly, tap into cheap energy, and get to business without distractions. At its core, this is a bet on AI infrastructure.

But the Middle East isn’t alone in its ambition for AI.

The red carpet they rolled out for Trump was a strategic effort—to make the region acceptable for U.S. AI expansion at a time when global dealmaking has become far more difficult. Under Trump’s protectionist stance and tariff threats, such expansion could only have happened with his direct involvement. This was understood clearly by the region. And they acted on it, quietly but effectively.

Honda has scaled back its EV ambitions amid slowing demand. What does that signal for the future of electric vehicles? The company had previously set a goal of making 30% of its car sales electric by 2030, but that target has now been abandoned. Instead, Honda will focus on expanding its hybrid lineup in the near term.

This mirrors a broader trend across the auto industry over the past year. Automakers are seeing a cooling of demand in their EV segments, while hybrid sales continue to grow strongly. The industry also remains highly vulnerable to the trade disruptions triggered by President Trump’s policies. In this climate of uncertainty, companies are leaning toward caution. For many, even without the shocks brought on by tariffs, the energy transition and the rise of Chinese EV manufacturers represent a once-in-a-generation disruption. Faced with that scale of change, automakers are choosing to be conservative with their investments.

The main culprit behind the slowdown in EV sales is that most electric vehicles still target the premium segment. Broader adoption will require customers to feel more confident about range and charging access. Range anxiety remains a stubborn barrier. While many current EV owners enjoy the convenience of a driveway and a private charging port, that’s a luxury not available to all car buyers.

Still, the current slowdown in EV growth shouldn’t be mistaken for a long-term decline. Battery technology continues to improve—costs are falling, performance is rising. As charging infrastructure expands and range anxiety recedes, EVs are likely to regain momentum and grow their market share.

This should be seen as a short-term reorientation. After the post-COVID enthusiasm and investment surge, a period of adjustment was not only inevitable—it should have been expected.

The hydrogen economy story rests on a powerful idea: that demand will emerge broadly across the industrial landscape — especially in hard-to-abate sectors like steel, shipping, and chemicals. Many projections treat hydrogen like a future commodity that will scale everywhere, from Europe to Japan to Australia, with global infrastructure rising to meet global need.

But what if that assumption is wrong?

Steelmaking is supposed to be one of hydrogen’s anchor markets. It’s the poster child for hydrogen demand in most long-term models. But hydrogen-based steelmaking may not happen where the steel industry operates today. It may happen where power is cheap, not where steel is consumed.

The shift from coal-based blast furnaces to hydrogen-based DRI doesn’t just change the fuel — it changes the economics of place. Hydrogen production depends on access to low-cost, renewable electricity. Without it, hydrogen-based steel is simply too expensive to compete.

If hydrogen-based steel production concentrates in a few regions — renewable-rich hubs like Australia, Brazil, the Middle East, or North Africa — the hydrogen economy won’t scale evenly across the map. It will scale where the inputs make sense.

This isn’t just a problem for hydrogen producers and infrastructure investors. It’s a decision steelmakers themselves are facing right now: Do they spend billions retrofitting aging blast furnaces in high-cost power regions like Europe — or do they shift new green production to where the energy is cheap and green from the start?

How that choice plays out could reshape not just hydrogen demand, but the entire geography of global steel.

Why Energy Cost Shapes Steel Geography

The logic of steelmaking has always followed the logic of its energy inputs. In the age of coal-based blast furnaces, steel production naturally clustered near coal mines. Energy was bulky, expensive to transport, and central to the economics of the process.

Hydrogen-based steelmaking reshuffles that map. In this model, coal is replaced by hydrogen — and hydrogen itself is simply a carrier for energy, produced through electrolysis powered by electricity. This puts the cost of electricity, not coal, at the center of the equation.

But not all electrons are created equal.

Electricity costs vary widely between regions. Renewable power in sun-rich or wind-abundant areas like Australia, Brazil, the Middle East, or North Africa can come in at a fraction of the price seen in Europe, Japan, or South Korea. This cost gap matters. Producing green hydrogen via electrolysis is inherently electricity-intensive — so even small differences in power prices cascade into large differences in hydrogen cost.

This shift forces a critical question for steelmakers: If the cheapest hydrogen is available far from home, does it still make sense to retrofit legacy blast furnaces — or is it better to build new capacity where the fuel is cheapest?

The energy input no longer dictates just the emissions profile. It may dictate the geography of production itself.

The Local Hydrogen Risk for High-Cost Regions

Europe, Japan, and Korea are among the world’s largest producers of steel. But they are also among the regions facing the highest electricity costs — and with that, some of the highest green hydrogen production costs.

This creates a fundamental tension. These regions have strong policy commitments to decarbonization, but they may simply not be the cheapest places to make green hydrogen at scale.

That raises a tough strategic question for steelmakers and hydrogen producers alike: Will these regions invest heavily in local hydrogen production and green steelmaking — or will they choose to import semi-finished steel from regions where the economics work better?

If the answer is import, global hydrogen demand doesn’t vanish — but it doesn’t localize. Hydrogen use stays at the export hubs, not at the consumption centers.

This outcome would dramatically reshape hydrogen infrastructure plans. Local hydrogen production, pipelines, and electrolyzer projects in high-cost regions may struggle to find viable offtake if the steelmakers they expect to supply opt instead to source low-carbon sponge iron from abroad.

The risk isn’t just technological or cost-based. It’s a geography mismatch between where hydrogen would be produced and where demand was originally forecast to appear.

Industrial Strategy vs. Pure Economics

On paper, the cost advantage of producing hydrogen-rich steel in renewable-abundant regions looks overwhelming. But steel is not just any commodity. It is foundational to national security, defense industries, and economic sovereignty. And that makes the story more complicated.

Governments may not be willing to let market logic alone decide where steel is made.

The European Union is already moving in this direction. Tools like the Emissions Trading System (ETS) and the Carbon Border Adjustment Mechanism (CBAM) are designed not only to cut emissions but to prevent carbon leakage — where dirty imports undercut domestic producers. Japan and Korea, both major steel consumers, are also debating industrial policies to protect strategic manufacturing sectors.

This raises a critical uncertainty for investors: How far can policy bend the cost curve? And for how long?

Subsidies, tax credits, and protective tariffs can support local hydrogen-based steel production even where renewable power is expensive. But if those supports weaken — or if green steel made abroad becomes dramatically cheaper — local hydrogen demand could collapse.

There’s no guarantee that governments will keep policy levers in place indefinitely. Industrial strategy may hold the line in the short term. But economics have a way of reasserting themselves over time.

For hydrogen producers and infrastructure developers, this isn’t just background noise. It’s the political variable that could decide whether a billion-dollar electrolyzer project finds customers — or sits idle.

What This Means

Hydrogen is often pitched as a globally scalable solution — a flexible decarbonization lever that can fit into energy systems anywhere. But steelmaking exposes a harder truth: hydrogen’s economics are deeply local.

The viability of hydrogen-based steel depends on power prices first, not hydrogen prices. And because renewable electricity costs are geographically uneven, hydrogen demand will be too.

This means hydrogen producers and infrastructure investors can’t rely on the idea that steel demand will translate directly into hydrogen demand wherever they happen to operate. They need to ask a harder question: Will hydrogen demand show up where I’m producing — or will it concentrate somewhere else entirely?

If hydrogen-based steelmaking consolidates in a handful of renewable-rich regions, the size of the hydrogen market in Europe, Japan, and other high-cost areas could be smaller than most forecasts suggest. Local electrolyzer projects, pipelines, and hydrogen infrastructure may struggle to justify their economics if the steelmakers they were meant to supply opt instead to source low-carbon sponge iron or finished steel instead.

This doesn’t mean hydrogen demand vanishes. But it does mean that hydrogen demand may be hub-and-spoke, not grid-like. It may emerge as tightly clustered production zones feeding global supply chains, rather than broad-based regional networks.

For investors, that reshapes the thesis. Hydrogen won’t automatically scale everywhere. The opportunity lies in picking the right geography — not just the right technology.

The hydrogen economy has always been sold as a technological breakthrough for hard to abate sectors — a clean molecule with the flexibility to decarbonize almost anything. But steelmaking shows that the real economic challenge isn’t just the chemistry. It’s the geography.

Hydrogen-based steel doesn’t just need electrolyzers and renewables. It needs the right renewables in the right places at the right price. Without that, the model struggles to compete.

For investors and infrastructure builders, this is more than a footnote. It’s a fundamental design constraint. The success of hydrogen in steel — and perhaps in heavy industry more broadly — may depend not on how good the technology gets, but on where you place your bets.

Hydrogen isn’t automatically global. It may never be.

And for hydrogen producers and their backers, understanding this early — before the capital is committed — may be the difference between riding the first real industrial wave of the hydrogen economy… or standing on the wrong side of a shifting map.

Hydrogen is supposed to be the great decarbonization tool of the energy transition. But most of its future demand remains trapped in projections — pinned on sectors like shipping, aviation, or seasonal energy storage where commercial momentum is still shallow and timelines are long.

Steel is different.

Steel isn’t waiting on hypothetical breakthroughs. It accounts for nearly 9% of global CO₂ emissions today — more than global aviation and shipping combined — and its production volumes are not expected to shrink. Demand for steel will remain high across infrastructure, automotive, wind power, and construction. And unlike many sectors that can lean on electrification, primary steelmaking has no easy substitute. The process of turning iron ore into iron requires stripping away oxygen — historically done with coal, and deeply embedded in industrial systems worldwide.

This makes steelmaking one of the few places where hydrogen is not just one option among many — it is the only industrial decarbonization pathway available right now that allows producers to act without waiting for speculative technologies to mature.

The hydrogen story often sounds like it’s about what might happen in 2040. But in steel, the story is happening now.

Steel’s Emissions Problem

Steel is essential to the modern economy. It’s in bridges and skyscrapers, cars and wind turbines, pipelines and ships. Global demand for steel is expected to remain strong through mid-century — not just because of growth in emerging markets, but because the energy transition itself depends on steel-heavy infrastructure: transmission lines, renewable power installations, and electric vehicles.

But steel also has a problem. It is the single largest industrial source of carbon emissions.

Roughly 2–3 billion tonnes of CO₂ are released every year from steel production, primarily from the blast furnace process that uses coking coal to reduce iron ore into iron. This process hasn’t fundamentally changed in over a century.

Decarbonizing steel is a necessity if global climate goals are to be met. Steel alone contributes nearly 9% of global CO₂ emissions, making it harder to achieve net zero without addressing this sector directly.

While there is an easier decarbonization story for scrap-based steelmaking (using electric arc furnaces powered by renewables), scrap supply is limited. Primary steel — made from iron ore — will remain the majority of global production for decades to come. Recycling alone cannot close the gap.

This is why the decarbonization challenge in steel is structural. Unless there is a viable, scalable replacement for coal in the reduction process, steel will remain locked into its emissions footprint — and so will the broader industrial economy.

The Only Viable Tool

Decarbonizing primary steel production means finding a way to remove oxygen from iron ore without coal.

There are only a few credible pathways on the table for primary steelmaking:

• Natural gas-based direct reduced iron (DRI) process with carbon capture (CCS): This approach uses natural gas instead of coal as the reducing agent and bolts on CCS to catch a portion of the emissions. A DRI plant reduces the carbon footprint compared to coal-based blast furnaces — but does not fully eliminate emissions. CCS remains politically controversial, faces public skepticism, and may not scale fast enough or cheap enough to fully decarbonize the sector. But even without CCS, using natural gas over coal significantly reduces GHG intensity of the process.

• Hydrogen-based direct reduced iron: Replaces natural gas with hydrogen as the reducing agent in DRI processes. Technically feasible today. Several pilot plants are operating, and full-scale commercial projects are already under development. Requires green hydrogen to fully decarbonize — but does not require fundamental reinvention of the steelmaking process. In fact, a natural gas-based DRI plant can gradually move towards hydrogen-based DRI as cheaper hydrogen becomes available.

• Electrolysis of iron ore (direct electrification): Uses renewable electricity to split iron ore directly, without any hydrogen. Attractive in principle — but still experimental and not proven at scale. Even optimistic timelines suggest that large-scale deployment of electrolysis-based steelmaking will take at least another decade or more. The methods most talked about here are electricity-based methods like molten oxide electrolysis (MOE) and electrowinning, both of which offer alternatives to traditional iron ore reduction.

Only hydrogen-based DRI allows the steel industry to begin deep decarbonization today without waiting for future breakthroughs.

It fits into the existing DRI framework, leverages equipment and expertise already present in the sector, and allows for gradual scaling as hydrogen costs decline.

Hydrogen DRI is not a perfect solution — but it is the only viable tool that steelmakers can deploy now to meaningfully cut emissions from primary steel production.

Industrial Momentum

The argument for hydrogen-based steel isn’t just chemistry. It’s already happening on the ground.

A growing number of steelmakers — especially in Europe — are not waiting for perfect technology or flawless economics. They are moving forward with hydrogen-based DRI because it is the only decarbonization option they can act on today.

• SSAB, LKAB, and Vattenfall in Sweden have already produced the world’s first batches of hydrogen-reduced steel at pilot scale, with plans to scale up to full industrial production.

• ArcelorMittal has shown interest in investing in multiple hydrogen DRI projects across Europe and Canada.

• Salzgitter AG has launched its SALCOS program to replace blast furnaces with DRI units and electric arc furnaces powered by renewables.

• The H2 Green Steel project is building a new steel plant entirely designed around hydrogen DRI, aiming for full production in the coming years.

These are not speculative research initiatives. They are capital-intensive industrial projects — backed by real money, real engineering, and real timelines.

The buyer side is also signaling commitment. Large automakers and appliance manufacturers — including Volkswagen, BMW, and Volvo — are signing contracts for green steel to secure low-emission supply. This demand pull reinforces the incentive for steelmakers to move early, even in the face of higher production costs.

Policy is amplifying this momentum. The European Union’s Emissions Trading System (ETS) is raising the cost of carbon, directly penalizing coal-based steel production. The Carbon Border Adjustment Mechanism (CBAM) will make it harder for imported dirty steel to undercut domestic low-carbon production. In the United States, the Inflation Reduction Act (IRA) offers tax credits for clean hydrogen that help close the cost gap.

Hydrogen-based steel is not a future hope. It’s the decarbonization strategy that the sector is already betting on.

What This Means

The hydrogen economy is still heavy on forecasts and light on offtake. But steelmaking stands apart. It’s one of the few sectors where hydrogen demand is not hypothetical — it is structurally necessary and already under development.

This makes steel one of the most credible near-term anchors for hydrogen producers, electrolyzer manufacturers, and infrastructure builders. Unlike sectors like aviation or shipping that are relying heavily on biofuels in the near term, and long-duration storage, where timelines stretch toward 2040 and beyond, the steel industry is moving now because it has few other choices.

That doesn’t mean the opportunity is risk-free. Steel remains a low-margin, highly commoditized business. Hydrogen-based steel production will require either strong carbon pricing, policy support, or buyer willingness to pay green premiums — especially in the early years when hydrogen costs remain high. Investors betting on hydrogen for steel will need to watch these three levers closely.

But this risk is also what makes the opportunity actionable. The decarbonization of steel isn’t a “nice-to-have” marketing story for automakers or wind turbine makers. It’s becoming a regulatory requirement — and those who delay face increasing cost penalties and competitive disadvantages.

Hydrogen supply chains that connect to steelmaking projects are not merely speculative infrastructure. They are tied to the hard reality of industrial decarbonization mandates. And where many hydrogen projects struggle to find credible offtake partners, steel offers one of the clearest demand signals on the table.

For investors deciding where to place early hydrogen bets, steel may be the safest starting point.

Hydrogen has been called the “Swiss Army knife” of the energy transition — a solution for everything from shipping fuel to seasonal grid storage to industrial heat. But much of that promise remains in the future, waiting on policy, infrastructure, and cost curves to align.

Steel is different. Steel doesn’t need the hydrogen story to be perfect. It just needs something that works now — and hydrogen-based DRI is the only tool that does. That makes steel the first real test case for the hydrogen economy.

This isn’t just about emissions accounting. It’s about where capital should flow first. Investors looking for credible scale-up potential shouldn’t start with speculative sectors that might materialize in 2040. They should start where hydrogen demand is already structurally locked in.

Steel may not be hydrogen’s largest market in the long run. But it may be the market that proves whether hydrogen infrastructure can move beyond PowerPoint and into the industrial world.

In the race to scale the hydrogen economy, steel isn’t the endgame. But it may be the first real foothold.

Ammonia is not the easy option. It’s toxic, corrosive, and a gas at room temperature. It must be chilled to -33°C to store as a liquid, and even then, it poses serious inhalation risks. Leaks can be dangerous. Handling it at scale requires care, infrastructure upgrades, and tight regulatory oversight. This is not a drop-in fuel.

And yet: ammonia may be the clearest long-term contender for decarbonizing deep-sea shipping.

Its appeal doesn’t come from perfection — it comes from fit. Ammonia is energy-dense compared to other alternatives like liquid hydrogen or batteries, and unlike methanol, it contains no carbon. That means it produces no CO2 when burned, and if synthesized using low-emission hydrogen, it’s one of the cleanest marine fuels on offer.

Ammonia is already traded globally as a fertilizer feedstock. Tankers and port facilities exist. The industry knows how to move it, store it, and sell it — albeit not yet as fuel. Unlike many next-generation fuels, ammonia isn’t emerging from the lab. It’s being reimagined for a new role.

And most importantly: it’s cheaper to synthesize. While methanol requires captured CO2 — a feedstock that’s both expensive and constrained — ammonia needs only hydrogen and nitrogen. And nitrogen is practically free, pulled from ambient air at scale. That structural simplicity matters when fuels need to scale globally.

Ammonia isn’t ideal. But for the kinds of large, long-distance vessels that dominate maritime emissions, it’s starting to look inevitable.

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Deep-sea shipping — the massive container vessels that cross oceans — represents the beating heart of global trade. It also accounts for nearly 80% of the shipping sector’s greenhouse gas emissions. The industry as a whole emits about 3% of total global CO2, putting it on par with aviation.

That share is expected to grow. Shipping is hard to decarbonize. The vessels are long-lived, the distances they have to travel are vast, and the energy demands are high. The shipping industry is running out of time. With international pressure mounting and climate deadlines approaching, ship operators can’t afford to wait for the perfect fuel. They need something that works today — and increasingly, that something is methanol.

It’s not the cleanest option, or the cheapest. It’s not even guaranteed to be the long-term winner. But methanol is compatible with today’s infrastructure, can be handled with minimal upgrades, and fits with existing ship designs. That makes it uniquely usable.

This isn’t about choosing the best fuel. It’s about moving quickly.

A “Now” Fuel

Global shipping is a high-emission industry with an unusually long memory. A ship ordered today won’t enter service for 2–3 years. Once launched, it may sail for another 35-40. Vessels built today will still be operating in the 2050s. Every delay in fuel adoption ripples forward for decades. And most ports — especially outside Europe — aren’t yet ready for anything radically new.

In the European Union, the FuelEU Maritime regulation is forcing the issue. Vessels must begin reducing greenhouse gas intensity starting in 2025 — with escalating targets through 2050. Ships will face increasingly strict limits on greenhouse gas intensity, with penalties applied to vessels that fail to comply. The regulation doesn’t just reward progress — it punishes hesitation.

The challenge is that most alternative fuels aren’t deployable yet. Hydrogen is immature at scale. Ammonia raises serious handling and safety concerns. Infrastructure is either lacking or theoretical.

What the industry needs is a now fuel — something that works with current infrastructure, fits into existing safety regimes, and gives operators a way to comply without betting everything on the unknown.

Methanol isn’t perfect. But it’s doable. And in a sector driven by engineering conservatism and long-cycle investment, that counts for more than technical elegance.

Practical Fit

What makes methanol different is that it fits the system as it exists today. Unlike alternatives like hydrogen or ammonia, it’s a liquid at ambient temperature. That means it can be transported, stored, and bunkered using infrastructure that ports already understand. Retrofitting older ships to run on methanol is possible, and new dual-fuel engines are already in production.

From a safety and environmental standpoint, methanol is manageable. If spilled, it’s less toxic to marine ecosystems than today’s fossil-based marine fuels. It dissolves in water and biodegrades quickly. That matters in practice — especially in smaller ports or developing markets where leakage and informal bunkering practices remain common.

If you’ve ever seen bunkering operations along the Mekong Delta — small crafts pulling up to ferries with hoses and hand pumps, fuel dripping directly into the river — you know this isn’t theoretical. Leaks happen all the time. What matters is how forgiving the fuel is when it does.

That said, methanol is still toxic to humans — especially if ingested or with prolonged skin exposure. It’s not a harmless fuel. But compared to ammonia, it’s far easier to work with and far less dangerous in practical terms.

Ammonia, by contrast, is far more toxic, especially via inhalation. And being gaseous at room temperature, it requires entirely different handling protocols — not something every operator or port can adopt overnight.

Order Books

After LNG, methanol has become the most popular alternative fuel in the global order book, far ahead of ammonia or hydrogen.

Dual-fuel methanol engines — capable of running on conventional marine fuel and switching to methanol when available — offer flexibility during a transition period. That’s especially valuable in a regulatory environment that’s tightening faster than global fuel supply chains can adapt.

These ships aren’t short-term bets. They’ll be on the water for 35–40 years. And that gives methanol real gravitational pull — not just on engine designs, but on bunkering infrastructure, hydrogen sourcing strategies, and CO2 feedstock investments.

Ammonia might still win in the long run. But it’s methanol that’s shaping the market now. And when infrastructure gets built around a fuel — even a transitional one — it doesn’t disappear quietly.

The Cost Caveat

For all its practical advantages, methanol has a structural cost problem: it’s expensive to make cleanly. Producing e-methanol — the low-carbon version aligned with climate goals — requires two key inputs: green hydrogen and captured CO2. Both come with significant costs.

That CO2 input, in particular, is a bottleneck. Unlike ammonia, which uses nitrogen - the most abundant component of Earth’s atmosphere- pulled from air, methanol relies on carbon — and carbon is harder to find in clean form. Capturing CO2 from industrial sources can reduce emissions but still ties methanol to fossil infrastructure. Capturing it directly from the air is far more expensive. Some producers look to biogenic CO2 from biomass or waste — but that supply is limited and already in demand for SAF, biofuels, and synthetic chemicals.

This constraint creates a ceiling: even if methanol adoption accelerates, the fuel itself may not remain affordable — unless CO2 sourcing becomes cheaper, or synthetic production technologies improve rapidly.

That’s why methanol isn’t just fighting technical alternatives. It’s competing against other industries for the same feedstock. And that competition introduces volatility that shipping operators don’t control — but will eventually have to price in.

What This Means

Despite the cost hurdles, methanol still holds strategic value — precisely because of how shipping works. The industry doesn’t and can't decarbonize in sudden shifts. It moves through long arcs of infrastructure, regulation, and fleet cycles. And methanol, for all its imperfections, lets that arc begin now. Fuel that wins today is not going to be the one that's best in theory, but the one that can be slotted into these cycles with minimal disruption.

Methanol fits that pattern. It doesn’t require a wholesale rebuild of bunkering systems. It doesn’t force a fleet overhaul. It doesn’t demand entirely new safety protocols. For shipowners navigating uncertainty, those are not minor advantages — they’re decisive.

And that’s what gives methanol leverage. Not because it will dominate forever, but because it’s the fuel that enables movement while the rest of the system catches up. It gives ports a reason to act. It gives hydrogen producers a beachhead market. It gives shipbuilders and operators a way to comply without betting everything on what’s next.

Methanol won’t solve everything. But it buys time without freezing progress. It allows the sector to comply, experiment, and decarbonize — without waiting for every variable to be resolved. It’s not a final solution — but it’s one the industry can actually act on now.

But is this a bridge toward better fuels, or a path we won’t backtrack from? Time will tell.

The methanol-vs-ammonia split has consequences beyond shipping. Every methanol-powered ship nudges the system toward greater CO2 sourcing, tighter biofuel competition, and deeper reliance on synthetic carbon pathways. If it pulls too hard on limited biogenic feedstocks, it could drive up costs for sectors like bio-SAF and biodiesel — and that, in turn, could accelerate investment in synthetic alternatives.

By contrast, if ammonia gains ground — especially blue ammonia from natural gas — it eases the pressure on biogenic feedstocks. Biofuels stay cheaper longer. And green hydrogen projects may look less urgent, and even less profitable.

What fuel shipping chooses next doesn’t just shape maritime emissions — it influences timelines across the energy transition.

Methanol might not be the endgame. But it’s shaping the present. And right now, that’s what counts.

We use nearly 100 million tonnes of hydrogen each year today, almost all of it derived from fossil fuels and accompanied by CO2 emissions. Some estimates suggest that by 2050, global demand could grow fivefold — and all of that would need to be low-emission to align with net-zero targets. Hydrogen today is essential for making fertilizers, plastics, and paints, and it plays a significant role in petroleum refining. In the future, its use could expand into sectors like transport, industrial heat, steelmaking, and energy storage. That future isn’t guaranteed — but it’s plausible enough to warrant serious attention. This insight focuses on one specific question within that broader context: whether hydrogen makes economic sense as a long-duration energy storage solution.

Producing low-carbon hydrogen is not easy or attractive — especially when the goal is to use it as an energy storage medium rather than a feedstock. When hydrogen is the required input, such as in fertilizer production or steelmaking, inefficiency in production is tolerable. But when hydrogen is just an intermediary — a way to store electricity and convert it back later — then every step matters. Converting electricity to hydrogen and back to electricity can result in a round-trip efficiency of just 40–45%. That trade-off may still be worth it under certain system conditions — but the bar is high. You need a strong reason to accept that level of energy loss.

For long-duration, infrequent storage — the kind needed to cover seasonal shortfalls in renewable generation — hydrogen has a structural cost advantage over batteries. Battery storage scales linearly with materials: more storage means more lithium, more cells, more capital. Hydrogen storage, by contrast, can scale with space. In salt caverns, marginal increases in storage volume are just that — additional empty volume, not additional material. And in the EU, salt cavern capacity is not a major constraint.

That’s why hydrogen starts to look appealing when we think in terms of months or seasons rather than hours or days. Batteries, for all their round-trip efficiency, become economically punishing when used to store energy that may only be discharged once a year. Hydrogen infrastructure is also underutilized in such cases — but the capital intensity is lower, and the marginal storage cost is dramatically cheaper.

Hydrogen’s role might become to complement a grid that is increasingly shaped by weather. As the share of variable renewables grows, long-duration imbalances emerge from climate-linked generation patterns. Hydrogen’s ability to absorb surplus electricity and release it months later fills a structural gap that batteries and demand response, for all their strengths, aren’t designed to solve.

As renewable penetration increases, overbuilding becomes inevitable — and essential. In a system dominated by wind and solar, redundancy isn’t wasteful; it’s a prerequisite for resilience. To ensure year-round supply, you have to size capacity for the low-generation months. But that means in the high-generation months — long sunny days, strong seasonal wind — you’ll routinely produce more power than the grid can use.

Curtailment is the system’s way of dealing with this imbalance. But curtailment also represents wasted capital. That’s where hydrogen enters the picture — not as a perfect battery, but as a strategic sink. It absorbs the excess, smooths seasonal variation, and stores energy in a form that can be dispatched months later. Unlike batteries, hydrogen doesn’t require costly material scaling to increase duration. It can store energy at volume, cheaply, and indefinitely.

Batteries are excellent for intra-day balancing, even for multi-day shifts. But they don’t scale well across seasons. You don’t charge lithium-ion cells in the summer to discharge them in the winter — the economics simply don’t work. Hydrogen, though inefficient, allows you to shift abundance from one season to another. In this role, inefficiency matters less than timing and cost. If the alternative is wasting the electricity entirely, then recovering even 40% of it — months later, at peak prices — is a rational trade.

When it comes to long-duration, infrequent storage — the kind needed to cover seasonal shortfalls in renewable generation — batteries run into hard economic limits. You can build lithium-ion systems to buffer day-to-day volatility. But building them to store energy for months, only to discharge it once or twice a year, becomes prohibitively expensive.

At some point, duration changes the logic. There is a critical time threshold — determined by both the length of time energy must be stored and the frequency of its use — beyond which hydrogen becomes the superior option. That threshold isn’t fixed. It moves as technologies improve and prices shift. But for seasonal storage, we’re likely already past it.

To illustrate, consider a simple comparison.

A single Tesla Megapack costs about $1 million and stores 4 MWh of energy (source). To store 160 GWh of energy — enough to power roughly 750,000 U.S. homes for a week — would require 40,000 Megapacks, at a cost of $40 billion (source). That’s assuming perfect round-trip efficiency.

Now consider storing that same 160 GWh using hydrogen. To account for conversion losses (with round-trip efficiency around 40%), you’d need to produce and store the energy equivalent of 400 GWh. That amounts to roughly 12 million kilograms of hydrogen. At $5/kg for storage in salt caverns, including the compression costs, the storage cost totals $60 million (source).

You still need to produce the hydrogen and convert it back to electricity. Add another $60 million - at $5/kg - to produce it, and perhaps $1–2 billion for a dedicated gas turbine to dispatch it during peak demand. Even on the high end, the total system cost remains under $2.2 billion. That’s an order of magnitude cheaper than battery storage for the same purpose.

So this isn’t just about efficiency. It’s about system cost, capital allocation, and frequency of use. Spending $40 billion on an asset used once a season is economically irrational — even if it recovers 90% of input energy. Hydrogen systems lose more energy, but cost dramatically less to idle.

For this specific use case, hydrogen could be produced, stored, and consumed on-site. There’s no need for long-distance transport or grid-scale hydrogen pipelines. That keeps logistics simple — and cost controlled.

Here we assume the turbine is used primarily to convert stored hydrogen back into electricity. But in some cases, this turbine could also be paired with a thermal battery system, and hydrogen can act as the final dispatch layer once the thermal energy from the battery is exhausted. That coupling allows hydrogen to extend the duration of an otherwise short-duration thermal battery, while also leveraging shared infrastructure for electricity generation. The economics would improve when both systems are designed together. You could further colocate SAF production and steelmaking to use hydrogen for other purposes.

Even if the economics of hydrogen are still debated, the role it plays in a renewable-heavy grid is becoming more difficult to ignore. It may never match the efficiency of batteries, but it doesn't have to. Its value lies in duration, optionality, and structural fit — not perfection.

Structural Challenge

The near-term setup for European biofuels has improved. But when looking past the horizon of near-term policy mandates, the long-term outlook becomes more difficult to read. What kind of role will these fuels play in a system where e-fuels, electrification, and synthetic pathways are rapidly gaining traction? The sector may not be fading — but it is being outflanked.

That’s partly because biofuel production is structurally constrained. Feedstocks — used oils, fats, residues — are limited. They don’t scale easily. As demand grows, costs rise, and the ceiling comes into view. The sector can’t lean on learning curves the way solar or batteries can. More demand simply pulls harder on a finite supply base.

In theory, policymakers could expand the list of eligible feedstocks — palm oil, for instance, or food-based crops like corn and sugarcane. But doing so undermines the core idea of sustainable fuels. The EU has already drawn a line, banning palm oil-based biodiesel due to deforestation concerns. That line has held so far. Whether it continues to hold under commercial pressure is a live question.

Structural Endgame

E-fuels — including synthetic SAF (e-SAF) — are designed to solve the scalability problem by using renewable electricity to create hydrogen from water, and capture CO2, to synthesize drop-in fuels with no feedstock limitations. They also align more closely with long-term climate goals: e-fuels can be carbon-neutral, do not compete with food production, and avoid the deforestation and traceability concerns that have plagued parts of the biofuel supply chain.

The EU has already begun planning for this transition. Under current rules, 50% of all SAF supplied in 2050 must be e-SAF — a clear signal that Brussels sees synthetic fuels as the long-term solution.

But here lies the next structural challenge: electricity cost. Europe has some of the highest industrial power prices in the world — often double those in the U.S., and far higher than those in energy-rich regions. Since electricity accounts for the majority of e-fuel production cost, this places European producers at a serious disadvantage.

This disadvantage, however, is not necessarily permanent. Europe’s high power prices in recent years have been driven by its former dependence on Russian pipeline gas, followed by a shift to imported LNG, which is more expensive and volatile. But that picture is changing. A global LNG supply glut is beginning to take shape, which could help bring down gas-linked electricity prices in Europe over the next several years.

At the same time, Europe is expanding its domestic low-carbon generation. Countries like France — which operates a nuclear-heavy grid — already have electricity prices below the EU average, offering a clear signal that co-locating e-fuel production near nuclear plants could materially reduce costs in the EU. Offshore wind capacity in the North Sea is also growing, and future projects may be developed specifically to serve e-fuel facilities outside the grid.

In the future, a grid that relies heavily on renewable generation could support hydrogen projects by providing access to electricity that would otherwise be curtailed—at a much lower cost than the average electricity price. In this way, even after the abysmal energy conversion losses inherent in hydrogen production and use, hydrogen salvages energy that would otherwise be cast aside through curtailment.

To compete globally, Europe will need to either develop dedicated low-cost electricity projects (e.g., nuclear-to-fuel or offshore wind-to-fuel infrastructure), leverage policy tools to protect and subsidize domestic e-fuel production, or, pursue external production zones — for example, in North Africa — where solar resources are strong and transport costs back to Europe are low.

In short, e-fuels eliminate the biofuel feedstock bottleneck, but replace it with an electricity bottleneck. Without a strategy to overcome that constraint, European e-fuel producers may struggle to survive in a global market increasingly dominated by low-cost players in more favorable geographies.

Transition Risk

The companies most at risk in the shift to e-fuels are those that fail to secure a long-term cost advantage. While legacy biofuel producers may have infrastructure and offtake relationships, they were built for a feedstock-based world — not one defined by electricity, electrolysis, and synthetic fuels.

The key bottleneck in this transition is electricity cost. Another could be CO2 access. CO2 access — whether via biogenic waste, DAC, or ocean capture — may remain a near-term constraint, but over time it is likely to commoditize as infrastructure and policy catch up. The defining edge in e-fuel production will not be who controls CO2 — but who controls cheap, clean, abundant electricity.

One potential wildcard in this transition is the use of blue hydrogen — hydrogen produced from natural gas with carbon capture. While cheaper than green hydrogen today, it remains controversial. In countries like the U.S., where natural gas is abundant and policy is more accommodative to the fossil fuel industry, blue hydrogen may emerge as an interim feedstock for SAF. But in Europe, the calculus is different.

The EU already imports most of its natural gas — increasingly in the form of expensive LNG — making blue hydrogen not just environmentally questionable, but strategically unattractive. Supporting blue hydrogen for SAF would amount to subsidizing imported fossil fuels while undermining Europe’s goal of building a resilient, low-carbon energy base. By contrast, green hydrogen offers a path to domestically manufactured e-fuels — expensive today, but with falling cost curves and stronger alignment with the EU’s energy and climate priorities.

That is not to say that blue hydrogen could not play an important role in the transition. More advanced blue hydrogen technologies—such as methane pyrolysis—could offer a very low-emission alternative and allow hydrogen demand to develop more fully before a proper shift toward green hydrogen begins. Natural gas reserves within EU borders could also play a more substantial role in the transition by shifting production toward the delivery of blue hydrogen instead.

What This Means

Despite the high electricity cost, there are scenarios in which Europe could succeed: co-location with nuclear plants (e.g. in France), offshore wind-to-e-fuel development (e.g. North Sea), behind-the-meter renewable setups that bypass high grid prices, and strategic partnerships abroad, including in solar-rich regions like North Africa.

Combined with industrial policy and energy security goals, these strategies could support a local e-fuel industry. But they require coordination, capital, and regulatory clarity.

For European producers, the strategic questions are multiplying. Do they double down on biofuels now and use the current policy window to reinvest? Or do they start pivoting toward e-fuels — acquiring location and cheap electricity access, and developing scale before competitors can?

Most players are still watching and waiting. The transition is costly. The demand curve is policy-driven. And timing matters. Enter too early and risk margin compression. Enter too late and risk losing access to offtake agreements and supply contracts. The clock is moving, but not everyone agrees on when to jump.

Over the past three years, the European biofuel sector has endured one of the harshest operating environments in its history. Producers, once buoyed by the promise of clean transport fuels, have faced a toxic mix of collapsing margins, input cost spikes, demand delays, and geopolitical shocks. Many plants have idled. Projects have been paused. And a once-hopeful sector has largely shifted into defensive mode.

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The rapid growth of artificial intelligence (AI) is reshaping the global energy landscape, driving unprecedented electricity demand. As AI data centers scale, energy constraints—particularly grid limitations—have become a critical bottleneck.

While decarbonization goals remain relevant, the immediate need for stable and reliable energy sources will likely lead to a resurgence of natural gas, supported by carbon capture and blue hydrogen technologies over the medium term.

Constraints

AI data centers require a complex ecosystem of components, from Nvidia chips and storage to network equipment and cooling solutions. Supply constraints in any of these components have the ability to hamper growth. But market signals often are able to self-regulate the supply so that any disruption is only short-lived.

The grid is not as flexible and not as adaptable to market signals. Grid expansion is a slow process, mostly because the grid over the past two decades had not needed to fulfill high demand growth. Moreover, compared to the construction time required for AI data centers, which could be as little as a few months, the grid and the power plants can take several years before they start delivering electricity.

So the regulatory process and long construction timelines, although suitable enough for an environment where electricity demand growth is flat, are quite unprepared to deal with the high demand growth environment we are entering now.

There is a high degree of uncertainty among grid operators because the situation is so unprecedented. This has really been a sudden shock to them. There is very little clarity on how fast or to what capacity they must expand. Is this a short-term blip—like a COVID-like event—or is this a permanent trend change?

They don’t know, for example, whether growth in AI data centers’ electricity requirements would be offset by improvements in efficiency—which, over the past two decades, have kept electricity demand growth near flat even though we use many more electronics and rely on the internet far more than we did back then.

The risk grid operators face in overestimating demand growth is that they could end up building excess supply, resulting in stranded assets that ultimately increase costs for the general user.

There would naturally be a tendency to resist such an outcome—to resist being overly accommodating to AI data center growth at the expense of the general user, and to resist creating a public outcry. AI companies would inevitably have more difficulty expanding this way than if they found a way to source their own energy. Several states are already pushing for more regulated data center energy use to protect consumers from higher prices.

Let’s not forget that AI data centers’ electricity demand growth is not the only issue grids are facing. The energy transition is causing rapid electrification of transportation and heating, and the onshoring of manufacturing is also expected to increase electricity usage.

Availability

Natural gas is available in abundance in the U.S. And the industry over the past decade has become quite capable and efficient too. The U.S. today produces more natural gas than Russia and Iran combined, which are the second- and third-largest producers in the world. U.S. LNG is also seen as important for Europe to rid it of Russian gas.

Globally, LNG is entering a period of supply glut, where over the next decade, much more supply is expected to enter the market than the available demand based on current uses. New demand from AI could end up absorbing the excess supply.

Acceptance

In the U.S., there has been growing public support for natural gas projects. Partly, it’s because it helps support European gas needs and reduces its reliance on Russia. But it’s also due to the broader push for energy security—reducing dependence on foreign actors like Russia and China, not just for oil and gas but also for the essential minerals needed in the energy transition.

The Trump administration calling for more drilling is, to an extent, echoing what the public also wants. With this shift in opinion—and now with the Trump administration fully supporting the industry’s growth—more investment will flow into natural gas production and gas-powered electricity generation.

This shift aligns with broader corporate trends, where ESG is increasingly weighed against financial performance rather than treated as an absolute priority. Investor interest in ESG investments has cooled substantially, with fund managers stepping back—not only because of the underperformance of such funds in a high-interest-rate environment but also due to political backlash from many right-leaning states.

As the sustainability rhetoric softens across markets and with Trump’s return, tech companies have more leeway at a time when their priorities are shifting toward maintaining momentum in AI. This will undoubtedly make it much easier for them to pursue natural gas as an energy source to power their data centers.

Updating Priorities

Big Tech companies have historically prioritized sustainability goals to maintain public image and investor confidence. However, AI-driven growth has shifted their priorities. With energy becoming such a critical bottleneck, companies are naturally turning to what is most easily available to ensure they don’t jeopardize their lead in the AI race—or risk being left behind. Investors may forgive companies for missing sustainability targets, but falling behind in AI? That would be their death. No shareholder will forgive them for that.

For Big Tech, owning the energy production pillar is all about reducing risk. Because energy is such an essential requirement for AI, having control over it should be an obvious conclusion. They have explored the possibility of Small Modular Reactors (SMRs) that could be placed next to their large data centers, allowing them to go off-grid. But SMRs are still at least a decade away from widespread deployment. A similar challenge exists with geothermal energy, which, while aligned with fossil fuel expertise, won’t be a major contender until after 2035.

Meanwhile, natural gas has several advantages that Big Tech hopes to utilize to power their data centers. It can easily be bundled with renewables like solar and wind. In fact, using natural gas could allow Big Tech to place data centers next to large solar and wind installations, assisted by battery storage to manage intermittency issues. Intermittency is a serious problem for AI data centers, which prefer firm power, though some flexibility in their electricity use will undoubtedly develop over time. This, again, presents a solution for going off-grid.

Even current natural gas plants—which often sit idle except during peak demand—could become prime sites for data centers. By installing a mix of renewables and battery storage backup, and working alongside the natural gas plant, the data center could draw energy efficiently, without needing the grid. During peak demand, the natural gas power plant could prioritize general consumers while data center batteries could offset any renewable intermittency—or, in extreme cases, AI workloads could briefly scale back.

And while natural gas, as a fossil fuel, is often seen as “dirty” by purists, it can be made much cleaner. Natural gas power stations can capture and store CO2 emissions underground, essentially permanently. These plants can also be converted to run on hydrogen.

Blue hydrogen—produced from natural gas by separating CO2 before combustion—offers another viable alternative. Captured carbon from this process doesn’t have to remain a waste product. Through methane pyrolysis, natural gas can be split into hydrogen and solid carbon, which has industrial applications in rubber, paint, and even battery-grade graphite. With further innovation, this solid carbon could find broader uses, making blue hydrogen both an economical and clean future alternative to natural gas.

So rather than abandoning net-zero goals, Big Tech can use decarbonization levers within the existing natural gas infrastructure. This allows them to balance short-term AI growth with long-term sustainability commitments through carbon capture and blue hydrogen. This is not where part of the world wanted to go five years ago, but it might still offer a chance to keep moving toward this goal.

Green Future 2.0

Phasing out fossil fuels completely was always going to be difficult. You could shame the world into action. You could try to force its hand. But with so much of the world connected to this industry, a net-zero path that excludes it was never going to work.

Despite coal’s decline, the U.S. now produces about 50% more fossil fuel energy—coal, oil, and natural gas—than it did 15 years ago. Production has been growing at 3–4% annually for the past five years, and with Trump’s backing, that trajectory is only set to rise.

Even with increasing natural gas use, a path to net-zero remains. Carbon Capture, Utilization, and Storage (CCUS) and blue hydrogen offer near-term solutions. And with Big Tech prioritizing energy access while keeping sustainability objectives alive—at least on life support—CCUS and the hydrogen economy could see renewed vigor in the U.S. as natural gas production and consumption expand.

Decarbonizing aviation is one of the toughest net-zero challenges in transportation. Airplanes are constrained by both space and weight, meaning the ideal fuel must have high energy density. Sustainable Aviation Fuel (SAF) is seen as the key to solving this challenge. This green fuel is nearly identical to the jet fuel we use today. Because of this, it is considered a drop-in solution.

The biggest advantage of a drop-in solution is that planes are already equipped to use it, making a carbon-free transition far easier. That’s a major benefit—it means the infrastructure for fuel storage, handling, and aircraft operation requires little to no modification. Given the complexity and safety concerns of altering aircraft fuel systems, this is a crucial advantage. It’s ready to go now. The focus must be on producing it at a cost competitive with today’s jet fuel.

SAF is chemically very similar to jet fuel. Today, most SAF is made from biomass like agricultural waste, used vegetable oil, or fats—commonly referred to as bio-SAF. While not entirely carbon-neutral, bio-SAF can significantly reduce greenhouse gas emissions. It is seen as a short-term solution for decarbonizing aviation until e-SAF, which is basically made using clean electricity, becomes more widely available and cost-effective.

Bio-SAF is currently cheaper than e-SAF but has limitations—it is not an unlimited resource. As SAF demand grows, the availability of waste biomass will tighten, leading to supply constraints and potential shortfalls. Feedstocks like waste oils are not widely abundant, and relying on farm-grown sources raises concerns about food security. As bio-SAF supply becomes strained, its cost is likely to rise. Eventually, the rising cost of bio-SAF will surpass the declining cost of e-SAF.

Today, the biggest challenge for e-SAF is that it is significantly more expensive to produce than bio-SAF. This is because e-SAF relies on green hydrogen and captured carbon dioxide—producing both requires abundant electricity and remains costly. But because of the limitations of bio-SAF, by 2050, e-SAF is expected to become more widely available and more affordable than bio-SAF.

Emissions

Reducing emissions boils down to three core actions: avoid what you can, reduce where possible, and offset what remains.

Airplane emissions have declined over the past several decades as aircraft have become more efficient at transporting passengers. Efficiency gains will continue as aircraft become lighter, aerodynamics improve, and engines burn fuel more efficiently. Newer models are already 15–30% more efficient than their predecessors. These advancements help airlines reduce emissions per passenger.

But efficiency alone will never bring emissions to zero without a radical shift in fuel. SAF, as a drop-in solution, can play a key role in aviation’s decarbonization. Current planes can operate with a 50% SAF blend, and with minor upgrades, nearly all could run on 100% SAF. Depending on whether bio-SAF or e-SAF is used, CO2 reductions could range from 50–60% to nearly 100%.

Today, e-SAF remains expensive, so airlines often turn to carbon offsets as an alternative way to reduce emissions. By purchasing offsets, companies fund projects that lower or remove greenhouse gases elsewhere, such as reforestation or renewable energy. In regulated carbon markets, companies can also buy credits from others with unused emissions allowances, effectively paying for the right to emit within a set cap. Given the challenges of reaching net zero through technology alone in the short term, airlines may need to rely on offsets to mitigate part of their emissions. As the cost of these credits rises, investing in e-SAF will become a more attractive option. Increased demand will drive up supply, and as production scales, costs will decline.

Affordability

SAF currently costs at least 3 to 5 times more than regular jet fuel. However, despite high costs, SAF’s drop-in nature allows for gradual adoption in small quantities with minimal impact on ticket prices. As demand rises, supply will expand, economies of scale will develop, and costs will steadily decline through learning and innovation.

Scaling up is crucial to lowering the production costs of green hydrogen and captured CO2. Green hydrogen is extracted directly from water using electrolysis that uses a lot of electricity. The CO2 can be sourced through Direct Air Capture (DAC), from biomass such as trees, or even ocean water—all of which require electricity. A promising approach is extracting CO2 from water. Since water has a much higher CO2 concentration than air, future advancements could make this method significantly cheaper than DAC if scaled effectively.

In the long run, the cost of electricity will be the key factor influencing e-SAF prices. Regions with abundant, low-cost electricity will have a competitive advantage in producing it more affordably. Co-locating e-SAF production facilities with cheap renewable energy sources will help keep costs down. Geography will play a crucial role, as not all regions have access to inexpensive renewable electricity.

Intervention

Airlines and aircraft manufacturers have already committed to SAF. But the governments must recognize the importance of future SAF availability and provide clear guidance on the role of hydrogen. The adoption of SAF faces the classic chicken-and-egg problem seen with other green technologies in their early stages. Without government support, scaling the industry becomes nearly impossible. This makes the role of government crucial. That’s why mandates introduced in the EU, UK, and other regions are so significant.

These mandates set a required percentage of jet fuel that must be SAF, starting small and gradually increasing over the next 30 years. A low initial percentage keeps costs manageable for passengers while providing a clear demand outlook that encourages companies to invest and expand supply. The certainty of future demand is what drives investment and production. The mandated percentage will rise steadily over time. For example, the UK requires 2% of all jet fuel for departing flights to be SAF by 2025, increasing to 10% by 2030 and 22% by 2040. The EU’s mandate is similar but includes a 70% SAF target by 2050.

What This Means

Who buys first? Early adopters of SAF face high costs since the fuel remains expensive. Late adopters will be able to purchase it at a significantly lower price. Does this mean early adopters—such as European airlines—will bear the financial burden? Will late adopters simply reap the benefits without the risks? This is a legitimate concern.

Why should a company be an early adopter? One incentive is technological advantage. Entering the field early allows companies to solve complex challenges and scale solutions, giving them a competitive edge over latecomers. However, airlines aren’t producing the fuel, nor do most have direct investments in SAF production. They are simply the first customers, paying a premium for a fuel far more expensive than conventional jet fuel.

Another incentive is steering the market in a direction that may be costly today but is ultimately cheaper than the alternative. Aircraft manufacturers have a clear interest in promoting SAF. If SAF becomes widely available, they can avoid the immense research and development costs of designing entirely new aircraft to run on alternative fuels. A drop-in solution is simply easier—and conveniently, it also happens to be the optimal one.

But the real force driving European airlines to adopt SAF is government mandates. European countries have set SAF usage requirements, meaning airports must supply blended SAF, and airlines must buy it.

The question of who buys SAF first is no different from who first adopted EVs, solar farms, or wind power. In each case, government intervention helped push an option that was initially more expensive but, in the long run, not only became cost-competitive with fossil fuels but also proved to be the cheaper alternative when considering environmental impact.

At the end, it would likely be the final customer that would bear the cost. Companies like Lufthansa Group have already begun passing SAF costs to customers, introducing a ticket surcharge linked to SAF usage. Airlines, unable to absorb the full cost of the transition, will inevitably seek ways to pass it on to passengers wherever possible.

The cost impact of SAF adoption will be similar to the effect of annual oil price fluctuations caused by Middle East crises—only a few percentage points, but enough to matter. Most airlines will choose to transfer the cost to customers. How they do so will be crucial. For instance, if customers are paying extra for SAF, are they earning more frequent flyer miles? Is the surcharge applied only to business class passengers? Are those paying more receiving perks like priority check-in? And if one airline passes on the cost while a competitor does not, how will that affect ticket sales?

While most of the cost burden will fall on customers, airlines may still absorb some of it—yet not all will be able to afford to do so. This suggests that financially stronger airlines will be better positioned to weather the transition, while weaker ones could become acquisition targets. The airline industry, already far more consolidated than it was 20 years ago, may continue this trend over the next two decades.

The Geopolitical Logic of Nuclear Energy

What Makes Nuclear Different

Nuclear, unlike other energy technologies, demands a long-term, stable partnership between collaborators. Its complexity, combined with the profound need for trust, makes this relationship more than transactional — it becomes a shared custodianship, bound by the responsibility to prevent proliferation, accidents, or worse.

There is a security dimension that surrounds nuclear — a gravity, a sobering awareness, unlike any other energy source. It demands seriousness. For this reason, nuclear trade deals almost always take place between countries that are already close allies — or between nations willing to pledge themselves to that kind of enduring friendship. In this way, nuclear locks in loyalty more firmly than foreign aid, more deeply than fighter jets. It binds nations not just by interest, but by shared fate.

Nuclear energy belongs to a class of strategically vital industries — alongside weapons manufacturing and critical minerals — that China and Russia have increasingly woven into their national strategies. Through these industries, they cultivate long-term dependencies, using economic ties to extend their geopolitical reach.

What sets nuclear apart is its power to embed influence across generations. From constructing a reactor, to operating it for decades, to managing its fuel, its waste, and eventually its decommissioning — the lifecycle can stretch across a full century.

This is a stark contrast to most energy projects, where construction is followed by a relatively quick handoff to local utilities. Nuclear’s sheer technical complexity creates something far stronger: a lock-in not just of technology, but of trust, expertise, and political alignment.

How Russia and China Use Nuclear to Gain Influence

It is Rosatom, Russia’s state-owned nuclear energy company, that leads bids for nuclear plant projects in other countries. Each bid comes wrapped in the full weight of the Russian state’s political and financial backing. Rosatom doesn’t just build the plant — Rosatom engineers operate it. Rosatom supplies the fuel. Rosatom promises to retrieve and manage the waste when the reactor’s life is over. It is a one-stop shop, offering comprehensive nuclear support: planning, construction, operation, and fuel management, all under one roof. This full-service package is further sweetened with generous financing to cover both construction and long-term operation — funding that Western companies simply cannot match.

This subsidized approach, while offering a cheaper option for many countries, ultimately expands Russia’s influence over their energy systems — and often far beyond. The dependency stretches well past energy itself, embedding Russian influence into the country’s broader political and economic fabric, in ways far more enduring than conventional trade relationships. Such a bond gives Russia quiet leverage — the kind that can shape, or even steer, a country’s policy decisions for decades to come.

China is closely following Russia’s playbook. Already a nuclear heavyweight, China has surpassed France to become the world’s second-largest nuclear energy producer, with the most aggressive reactor construction plans of any nation.

In some areas, China’s expertise in building advanced reactors even rivals — or surpasses — that of the United States. Its state nuclear giant, CNNC, mirrors Rosatom’s strategy, bundling reactor projects with state financing and long-term operational partnerships.

China is building nuclear plants in Romania and Pakistan, while steadily expanding its footprint across Africa and Central Asia — financing not only nuclear facilities, but a sweeping array of infrastructure projects, all under the banner of its Belt and Road Initiative.

Today, nearly three-quarters of the nuclear reactors planned or under construction worldwide are being built by Russia and China. The challenge for the US companies, of course, is that Russian and Chinese companies are driven by far more than profit. With the full backing of their states, their motivation is securing influence, not just revenue. Western companies, by contrast, operate without that level of state support, leaving them unable to compete on economics alone. In the end, this imbalance weakens the United States, gradually pushing its influence aside in key regions around the world.

The Fukushima accident in 2011 was a blow to the West. In its aftermath, the entire nuclear industry slipped into stagnation. Planned projects across the globe were paused, reconsidered, or outright canceled. That hesitation gave Russia its opening. With Western companies retreating, Russia stepped in — and today, it holds the largest portfolio of overseas reactors. Russia is building — or has already built — reactors in Turkey, Egypt, India, and across Eastern Europe, steadily expanding its nuclear footprint.

Today, the challenge extends beyond reactor technology — it’s also about fuel. The West cannot even fully supply itself, leaving its nuclear sector still partially dependent on Russian fuel. With its weakened nuclear supply chain, the West is in no position to reliably fuel reactors for other countries either.

The West’s Nuclear Counterstrategy

After Russia invaded Ukraine, the West saw a sudden surge of political will to sever its dependencies on Russia. In the nuclear sector, this dependency centers largely around nuclear fuel. Key developments have followed.

Stockpiling

Anticipating disruptions to Russian supplies, some utilities began independently stockpiling fuel, aiming to keep their reactors running for the next 3 to 4 years. In fact, U.S. imports of Russian nuclear fuel rose in 2023 — exceeding levels from both 2022 and 2021 — as companies rushed to secure supply ahead of a planned 2024 ban. At the same time, the U.S. sharply increased imports from China in 2023, after nearly none since 2020.

A national nuclear fuel stockpile, modeled after the Strategic Petroleum Reserve, could provide a short-term buffer against geopolitical risk. But in the long run, weaning off both Russia and China, and rebuilding a supply chain anchored among trusted allies, may be the only way to shield the industry from future geopolitical shocks.

Sapporo5

In 2023, the U.S. and its allies — Canada, France, Japan, and the UK — came together to form the Sapporo5, a strategic partnership aimed at strengthening nuclear supply chain security and breaking free from Russian influence. Their primary focus has been securing fuel mining, conversion, and enrichment capacity — not just from Russia, but also from “other” foreign influences, a clear reference to China. At the heart of Sapporo5 is the nuclear fuel supply, where the challenge is stark: outside of Russia and China, global enrichment capacity can only meet about 70% of the world’s existing reactor demand.

Banning Russia

In response to Russia’s invasion and the U.S. decision to ban Russian uranium fuel imports, several Western companies — including Cameco, Urenco, and Orano — have announced plans to expand their existing conversion and enrichment capacity. The goal is clear: to eventually eliminate dependence on Russia for nuclear fuel altogether.

The goal of the ban is to force domestic utilities to shift their nuclear fuel contracts to U.S. and European suppliers. By cutting off Russian fuel, the ban creates demand and incentivizes suppliers to expand production and invest in new enrichment capacity. Right now, U.S. enrichment capabilities are severely limited — the country relies on foreign providers for more than 75% of its enrichment services. Russia, by comparison, holds over five times the enrichment capacity of the United States.

Defence of Eastern Europe

Several Eastern European countries remain heavily dependent on Russian-fabricated uranium fuel rods, a legacy of the Soviet-era reactors still in operation. Across Europe and Ukraine, there are more than 30 Russian-built reactors still running today. Among them, Ukraine stands out as the most dependent. Situated on Russia’s doorstep, and having already endured the costs of relying too heavily on Russian gas since 2022, these countries are now eager to achieve full energy independence.

Over the past two years, companies like Urenco and Orano have expanded their fuel supply capabilities, working to reduce Europe’s reliance on Russian uranium fuel.

Ukraine has more reason than most to cut itself free from Russian influence. For decades, its nuclear sector was entirely dependent on Russia — from fuel supply to reactor technology. That is now beginning to change. Cameco, the Canadian uranium giant, recently signed a 10-year agreement to supply uranium hexafluoride for Ukraine’s reactors. Meanwhile, Westinghouse has stepped in to fabricate fuel rods compatible with Russian-built reactors. Together, these moves could finally liberate Ukraine’s nuclear industry from Russian control, creating a crucial pillar of its broader push for energy independence.

Countering Russia and China elsewhere

Ukraine’s dependence on Russia, significant as it was, pales in comparison to what new customers of Rosatom or China’s CNNC will face in the future. Ukrainian reactors were operated by Ukrainian engineers, not Rosatom staff. Ukraine relied on Russia mainly for fuel and replacement parts — a difficult dependency to break, but not insurmountable.

For countries now signing deals with Russia and China, the entanglement runs far deeper. When Rosatom or CNNC controls everything — from reactor construction to operations, and in some cases even owning the plants themselves — severing ties becomes vastly more complicated.

So far, the U.S. has shown reluctance to follow the path taken by Russia and China, offering generous financing to secure nuclear energy deals abroad. Instead, the U.S. has focused on promoting SMRs to its allies in Asia — a strategy that leans more on technology than financing.

But matching the sheer aggressiveness of Rosatom and CNNC, with their state-guaranteed loans, is a far greater challenge for the U.S., where nuclear remains a largely private-sector industry, with only minimal government backing — even at home.

Today, the cost of nuclear remains out of reach for many developing nations, driving their reliance on foreign financial support. That landscape, however, is shifting. In the U.S., rising interest from Big Tech — particularly to power AI data centers — is accelerating new momentum for nuclear development. In time, if cost-effective SMRs emerge that can outcompete on both technology and price, they could become the U.S.’s answer, allowing nuclear exports to ride the wave of AI-driven demand.

What This Means

A growing divergence is becoming clearer by the year — with two spheres of influence emerging: the U.S. and its allies on one side, Russia and China on the other. For the nuclear industry, however, this fractured world holds unexpected opportunities.

With foreign fuel suppliers like Russia pushed out, domestic companies involved in uranium mining, conversion, and enrichment find themselves facing new opportunities. For companies in nuclear energy, this is a rare chance to strengthen their competitive moat.

Producing fuel for nuclear reactors is no simple task. The scientific hurdles are steep. The operational demands are unforgiving. Handling nuclear fuel requires safety credentials and proven experience — trust that new entrants struggle to earn.

By banning Russia, the few companies capable of filling that void have the chance to expand both their offerings and their expertise.

There is also an opportunity for the U.S. government to step in with funding assistance for international nuclear projects — a move that companies can lobby for, but ultimately one that lies beyond their direct control. If such support materializes, it would open new markets and also expand the pool of potential customers for U.S. nuclear firms. A strong domestic nuclear industry also gives the US government a lever to create geopolitical influence.

There are several challenges that face companies in the nuclear industry. Capital investment in nuclear typically requires large scale, with returns spread over decades, meaning risk must be carefully understood before any commitment.

The central concern is clear: if a peace treaty with Russia is signed in the future, could Russian uranium return to the American market? Without a clear, binding signal from the U.S. government that this risk has been eliminated, investors will hesitate — unwilling to gamble billions on an uncertain future.

U.S. nuclear capacity could more than double by 2050, meaning demand for uranium fuel will climb sharply over the next 25 years. Achieving this while preserving energy independence will be no small feat. For an industry that, until recently, hadn’t seriously planned for even a single new reactor, and had only built enough capacity to serve existing plants, this is an ambitious — almost radical — shift.

The challenge grows steeper with Russian fuel off the table. The U.S. nuclear supply chain, which today operates at a fraction of its 1990s strength, is essentially starting from scratch. Rebuilding that capacity — and scaling it to meet a doubling of reactors — will be extraordinarily difficult, almost impossible without deep cooperation from European and Japanese partners.

The Incredible Capabilities of the Modern Airplane

The airplane has come a long way since the days of the Wright brothers. Its modern capabilities would have seemed like science fiction to the pioneers of the late 19th and early 20th centuries. The Wright Flyer, built and flown in 1903, could stay aloft for no more than a minute, covering barely a thousand feet—if a tailwind was generous. And their feat was made possible, in no small part, by the high energy density of the gasoline that powered it.

The longest non-stop flights today span over 15,000 kilometers (49,212,598 feet), lasting more than 18 hours—routes like Singapore to New York. Qantas plans to launch an even longer journey in 2026: a non-stop flight from Sydney to London, covering over 17,000 kilometers in 20 hours, making it the longest commercial flight in history.

Can you imagine? A plane carrying over 200 passengers, staying aloft for 20 hours without refueling? To the Wright brothers, such a feat would have been pure fantasy. Yet today, point-to-point air travel to virtually anywhere on the planet is a reality. And while this achievement owes much to the ingenuity of engineers, the sophistication of modern aircraft, and a century of efficiency gains, it has been made possible, in no small part, by the extraordinary energy density of jet fuel.

One must remember that an airplane’s amazing capabilities is not just in the distance it can cover in a single flight. A Zeppelin could rival that. What sets it apart is speed—the sheer ability to transport you from the familiarity of your city to the foreignness of another world in less time than a leisurely afternoon.

The Titanic carried passengers across the Atlantic in about a week—seven days, give or take. The fastest Zeppelin crossing, with a strong tailwind, took nearly two days, though it was often longer. By the 1980s and ’90s, the Concorde shattered those limits, making the same journey in under three and a half hours, while conventional jets still required seven or more.

Concorde represented the pinnacle of commercial aviation speed, flying at more than twice the speed of sound. At a cruising altitude of 60,000 feet, passengers could see the curvature of the Earth—experiencing flight in a way no other commercial aircraft had ever allowed.

While the Wright Flyer was a fragile wooden frame draped in fabric, barely lifting off the ground, Concorde was a supersonic marvel, a triumph of engineering. Its delta-wing design, afterburning turbojet engines, and heat-resistant materials enabled sustained supersonic travel—an achievement still unmatched in commercial aviation.

It’s almost surreal to think it first took flight in 1969. But placed alongside the other feats of that era, it seems less surprising. This was the decade of the Apollo missions, an age when humanity touched the Moon. Even the futuristic visions of "The Jetsons" belonged to the ’60s—a time when the impossible seemed within reach.

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The Quiet Revolution in Nuclear Energy

The nuclear industry is undergoing a tectonic shift—one that few outside the field truly recognize. Today, nuclear energy enters discussions mostly due to AI or its critical role in achieving net-zero emissions. AI companies favor it for its ability to provide firm, round-the-clock power, making it ideal for data centers. As a result, they are investing in next-generation Small Modular Reactors that can be placed directly next to their facilities, bypassing the grid entirely. Others view it as a key stabilizer for intermittent wind and solar energy. Few, if any, discuss it in the context of energy security. Even fewer acknowledge the West’s heavy dependence on Russia for fueling nuclear reactors.

What Does It Take to Produce Nuclear Fuel?

Nuclear fuel production has long been shrouded in secrecy due to its technological overlap with atomic bomb manufacturing. Preparing uranium for use in reactors involves three key steps before it can be fabricated into fuel pellets, which are then assembled into fuel rods.

First, uranium must be mined. This can be done through traditional open-pit and underground mining, as seen in Canada, or via the newer in situ leach method, where a solution is injected underground to dissolve uranium from surrounding rock and sand before being pumped back up for extraction—common practice in Kazakhstan.

Second, mined and milled uranium is converted into uranium hexafluoride gas, a crucial input for the enrichment process.

Third, uranium is enriched to increase its fissile U-235 content—from 0.7% to 3-5% for LEU fuel used in current reactors and 5-20% for HALEU fuel used in next-generation reactors.

After enrichment, uranium is processed into pellets, which are then used to manufacture fuel rods.

Who Controls the World’s Uranium Supply?

Half of the world’s identified uranium reserves are concentrated in just three countries: Australia (28%), Kazakhstan (13%), and Canada (10%). Russia holds approximately 8%.

Canada was once the world’s largest uranium producer, but since 2010, with the rise of in situ leach mining, Kazakhstan has overtaken it.

In 2022, Kazakhstan—a former Soviet state and close Russian ally—accounted for over 40% of global uranium production. Russia produced 5%.

In 2023, the U.S. produced less than 0.5% of the global uranium supply—just 23 tonnes. A far cry from its Cold War peak. The U.S. has uranium-rich deposits in the Colorado Plateau, and in the 1980s, it produced over 15,000 tonnes annually. In 2022, nearly half of the uranium used in U.S. reactors came from Russia, Kazakhstan, and Uzbekistan.

Change is slowly underway. In 2024, the U.S. saw the first new uranium mines open in nearly a decade.

Who Holds the Power in Uranium Enrichment?

After uranium is mined and extracted from ore, the next critical steps—conversion and enrichment—are far more complex. Many nations have attempted to master this process, but only a few have succeeded.

Currently, Russia and China control just under half of global conversion capacity and together produced over half of the world’s uranium hexafluoride in 2022. The U.S. holds around 10% of conversion capacity, while its allies France and Canada account for the rest.

In the U.S., enrichment capabilities were first developed during the Manhattan Project to produce atomic bomb cores. During the Cold War, the U.S. expanded enrichment primarily to support its nuclear weapons program and counter the Soviet threat. However, the U.S. relied on a more energy-intensive and costly method—gaseous diffusion—while the Soviets developed a cheaper alternative using centrifuge technology. After the Cold War, the U.S. relied on cheap, downblended uranium from Soviet-era warheads under the Megatons to Megawatts program, while Russia’s more cost-effective centrifuge technology further undercut U.S. enrichment facilities, leading to their slow decline.

Russia controls 40-50% of global enrichment capacity, and together with China, they account for around 60%. China is rapidly expanding its capacity to support its fast-growing nuclear fleet.

Russia supplies one-quarter of the enriched uranium used by U.S. nuclear reactors. In the U.S., enrichment has so far been limited to a single facility in New Mexico, owned by Urenco—a company jointly held by the British and Dutch governments and two German utilities. Now, new facilities are beginning to emerge. Centrus, a U.S.-owned company, is making strides in enriching HALEU fuel in Ohio. Orano, owned by the French government, is heavily investing in enrichment capacity at Oak Ridge, Tennessee. Cameco, a publicly traded Canadian company and the world’s second-largest uranium producer, is working with Silex Systems of Australia on laser enrichment—a breakthrough technology that could give Western nations a strategic edge.

How Fukushima Stalled the West’s Nuclear Revival

Before the Fukushima nuclear accident in 2011, a second nuclear renaissance was taking shape. After two decades of stagnation since the 1980s—driven by rising nuclear plant costs and slowing electricity demand—there was renewed enthusiasm. By the early 2000s, new investments were flowing into next-generation reactors, and nuclear energy’s low-carbon credentials aligned nicely with the global efforts to curb greenhouse gas emissions.

But after Fukushima, the momentum collapsed. Japan and Western nations abruptly halted funding for new nuclear projects and withdrew investment from the supply chain that sustained the industry. It was as if a wrench had been thrown into the machinery. Meanwhile, Russia and China pressed ahead, expanding their nuclear programs and domestic supply chains while the West scaled back its reliance on nuclear energy. Westinghouse Electric, once a cornerstone of the industry, was forced into bankruptcy.

Despite today’s renewed enthusiasm for nuclear power, past setbacks have left many surviving companies risk-averse, hesitant to take the bold action needed to rapidly scale up fuel and reactor supply chains independent of Russia and China. Russia and China continue to dominate the nuclear energy landscape, with China likely a decade ahead of the U.S. in deploying next-generation reactors at scale. As a result, the U.S. and much of the world remain increasingly dependent on Russia and China for nuclear fuel.

The U.S. Push to End Russian Nuclear Dependence

As a result of Russia’s invasion of Ukraine, and recognizing Russia’s grip on the uranium fuel trade and its implications for energy security, the U.S. in 2024 passed a bill to ban Russian-produced uranium fuel. But given the heavy dependence on Russian imports, an immediate ban would have been suicidal. With U.S. nuclear reactors holding about three years’ worth of fuel supplies, waivers were granted until 2028 to allow continued imports from Russia.

The goal of the ban is to force U.S. utilities to sign contracts for domestically produced nuclear fuel. By creating demand certainty, the policy aims to encourage companies to invest in domestic supply.

This protectionist shift in nuclear energy mirrors trends in other strategic industries, such as rare earth minerals, where the U.S. remains heavily dependent on China. It reflects a broader disentangling from the one-way trade links formed during globalization, shifting instead toward a diversified network that favors U.S. allies.

Several forces have fueled this protectionist push in recent years. The COVID-19 pandemic exposed the fragility of global supply chains, proving that reliance on a single country is a dangerous gamble. China’s dominance in green technologies and its control over critical mineral supply chains—essential for semiconductors, electric motors, solar panels, and batteries—has become a national security concern. China’s expanding influence in strategic regions—from the South China Sea to the Panama Canal, Malacca Strait, Africa, and South America—has made it a geopolitical rival to the U.S.

In nuclear energy, the wake-up call was Russia’s invasion of Ukraine, which forced nations to reconsider their energy security. Even at the height of the Cold War, natural gas shipments from the Soviet Union to Europe never faced the same disruptions and restrictions triggered by Russia’s 2022 invasion.

The importance of a resilient grid cannot be overstated. Our dependence on electricity is so absolute that even a few hours without it feels unthinkable. Nearly every aspect of modern life runs on it, and as time goes on, more and more of our lives will be powered by it and it alone. A modern civilization, as we know it, cannot function without electricity. After just a few hours without power, life begins to resemble a pre-industrial world. The simple acts of preparing food, accessing clean water, staying cool in summer, or warm in winter—things we take for granted—become difficult, if not impossible.

The need for resilience has been highlighted before here and here. Climate change-driven extreme weather events are becoming more frequent. As our reliance on the grid grows, disruptions come with ever-increasing economic and social costs.

A resilient system doesn’t need to be foolproof or indestructible. The idea is rather to build a system that would have the ability to deal with extreme events gracefully.

What does that mean exactly? When an extreme event or a shock that has the ability to cause major disruption happens, the grid should have the ability to manage it in a way that minimizes impact on the user, for example by isolating the impacted region and stopping the outage from spreading. And where the limited outage does occur, the grid should have the ability to quickly recover from it.

Resilience also means continuous learning and improvement. This requires studying past disruptions in detail and preparing the grid today for the shocks of tomorrow. The system should be in a constant state of evolution.

Growing Threats to the Power Grid

The grid faces countless threats simply because it is one of the most exposed systems we rely on. Whether dealing with physical dangers or cyberattacks, it must constantly strengthen itself to remain dependable. The severity of these threats is also increasing. Extreme weather events, intensified by climate change, are becoming more frequent in certain regions. At the same time, cyber threats are expected to grow as we adopt smarter systems to monitor and manage the grid.

The vast majority of the grid has little to no physical protection. We pass by it every day without a second thought. A single pole driven to the ground can all but guarantee a local blackout. Local substations, too, remain largely unguarded against sabotage. Most of us instinctively avoid wires, poles, and electrical equipment—not just because of the danger symbols they don like epaulets on a general’s uniform, but because we don’t fully understand the risks and would rather keep our distance than gamble with electrocution.

Weather-related damage can easily bring down the grid. Climate change is already driving more frequent floods and drought-induced wildfires, a trend that is expected to worsen. Some regions will see extreme rainfall and flooding, while others will endure prolonged dry spells.

Traditionally, the grid has managed flooding by elevating critical equipment above expected flood water levels and using overhead wires, which are quicker to repair after an event. However, overhead wiring is highly vulnerable to high winds, especially those from hurricanes. As ocean temperatures rise, hurricanes are expected to grow more intense.

Wildfires are becoming an increasingly frequent threat to the grid, especially in western North America. California has recently seen wildfires raging dangerously close to downtown Los Angeles. Fires that damage key infrastructure—such as generation stations or critical transmission substations—can lead to prolonged blackouts.

Beyond physical threats, the digitization of grid infrastructure—from smart meters and controllers to a vast network of sensors—has increased the risk of cyberattacks. The growing reliance on software, and now AI, to manage grid operations supports the integration of distributed energy resources but also introduces new vulnerabilities.

Building a Resilient Grid for the Future

Natural and man-made shocks to the grid should be seen as inevitable.

Sabotage will always pose a risk, as there will always be those who seek to spread chaos and suffering. Natural threats like hurricanes cannot be prevented either; they will remain a seasonal reality for the foreseeable future. The grid must prepare for high precipitation, powerful winds, and frequent flooding.

The assumption should not be that some miracle of weather engineering will lessen these events. Instead, we must expect climate change to intensify and increase their frequency across many regions.

Wildfires should also be considered a major threat, though proactive forest management and mitigation efforts may become routine, making their impact on the grid more controllable than disasters like hurricanes or earthquakes.

Although most natural shocks to the grid cannot be controlled as wildfires might be, utilities can implement various strategies to mitigate their impact.

Hardening components—making everything as strong as possible—is the most straightforward way to reinforce the grid. This includes strengthening transmission towers to better withstand failure. Techniques like installing extra-tough dead-end structures at intervals help prevent a domino effect, where a single fallen tower pulls down its neighbors, potentially collapsing an entire line for kilometers.

Utilities are increasingly burying power lines to strengthen the grid. Overhead wires have become a rare sight in urban areas. However, the decision to underground wires must be carefully considered. In flood-prone regions, it may do more harm than good, as buried lines remain vulnerable to water damage. Undergrounding is also costly, and repairs are more complex. Yet in areas prone to ice storms or strong winds, it may be the ideal solution.

Strengthening the grid requires careful analysis. Making infrastructure stronger can also sometimes make it harder to repair or replace quickly. This tradeoff is evident in the decision between undergrounding wires and installing them overhead.

But resilience isn’t just about preventing failures—it’s also about enabling a swift recovery. A key aspect of resilience is ensuring that critical equipment, such as transformers, has sufficient spare reserves for rapid repairs and replacements after a disruption.

Another key feature to enable resilience is redundancy. Redundancy is a common element of design in complex machines and construction projects where failure is not an option. For example, airplanes have two engines but can still fly if one fails. Rockets incorporate redundancy in nearly every critical component, from engines and launch computers to sensors.

In the power grid, redundancy enhances reliability. This is especially true on the distribution side, particularly in urban areas where high network density makes redundancy more cost-effective to achieve. With multiple pathways available, disruptions can be isolated and sectioned-off while alternate routes continue carrying the load.

A key takeaway from this discussion should be that the threats to the grid are growing - as weather disruptions and cyber-attacks become more common - even as our reliance on it grows. This highlights the growing need for resilience in the future. A less resilient grid will create economic costs for businesses and individuals, while at the same time, it will create new opportunities for off-grid solutions such as microgrids to tackle this emerging problem.

Climate adaptation solutions like levees to fend off flood water and aggressive forest management to manage wildfire risk will also see growing interest in the future as weather disruptions become a more frequent phenomenon.

Bibliography
National Academies of Sciences, Engineering, and Medicine. 2017. Enhancing the Resilience of the Nation's Electricity System. Washington, DC: The National Academies Press. https://doi.org/10.17226/24836

High Upfront Costs Can Limit Expansion

Microgrids present a range of opportunities, benefiting both end users and utilities in numerous ways, as discussed before. However, the microgrids in operation today are costly, requiring significant upfront investments in specialized generators, advanced controllers, and additional backups to ensure power reliability and resiliency independent of the main grid. For some users, these high costs may be justifiable, but for the majority, the initial expense is prohibitively steep.

A microgrid is far more complex than simply pairing rooftop solar panels with battery storage, along with demand response systems, and a controller to tie it all together. While such a basic setup might serve households or communities by providing limited vital power during extended outages, it falls short of meeting the demands of critical infrastructure such as hospitals, data centers, or military bases, where multi-day uninterrupted power is non-negotiable.

To serve these high-stakes purposes, microgrids must include controllable power sources—such as fossil fuel generators or hydrogen fuel cells—to counteract the variability of renewables. They also require additional backup systems to enhance the reliability of the microgrid itself. If demand response cannot sufficiently smooth demand peaks, specialized generators may be necessary to handle these peak requirements.

The layers of redundancy and robustness needed to ensure a microgrid can endure storms, prevent outages, and sustain critical infrastructure during extended blackouts significantly add to the overall cost. When factoring in the additional expenses required to supply power continuously for multiple days, microgrids become a far less appealing option for many users—especially if resiliency is the only benefit they deliver.

One way for end users to gain the benefits of microgrids without facing the challenge of high upfront costs is by utilizing microgrid-as-a-service offerings from specialized providers. This approach removes the initial expense and associated risks from the user. Instead, users sign a power purchase agreement, making recurring payments—similar to utility bills—directly to the microgrid operator. At the end of the contract term, users can decide whether to continue using the service.

Microgrid-as-a-service providers can integrate existing customer systems—such as rooftop solar or storage—or supply their own equipment, including additional generators, storage, and controllers. The system can be tailored to meet the specific needs of the user. Some users may prioritize zero-carbon energy generation, while others may focus on ensuring reliability and resiliency under all circumstances. This flexible approach allows providers to fulfill the unique requirements of each customer.

Utility Concerns Over Grid Stability and Rising Costs

A significant concern utilities face with private microgrids is their potential to undermine the reliability and resiliency of the broader grid for general users.

Industrial users on the grid typically pay premium rates for electricity. Their presence effectively subsidizes the costs for the average user, keeping rates more affordable. Without these high-paying customers, the average user would face significantly higher costs. The rise of private microgrids raises fears that premium users may abandon the grid entirely.

Private microgrid providers offer industrial users, data centers, and similar entities a path to operate almost entirely off-grid. As these high-paying customers leave, the financial burden on remaining users increases. With fewer resources available for maintenance and upgrades, the grid could become even more fragile—leaving it vulnerable to outages and less capable of meeting future challenges.

However, in most cases, a fully private microgrid is far more expensive to operate than one connected to the grid. This is because off-grid microgrids must arrange their own backups and plan for peak seasonal demand—an event that may occur only once a year, or even less frequently.

A grid-connected microgrid, by contrast, avoids these challenges. Instead, it can prioritize reliability, resiliency, and uninterrupted operation during blackouts.

Grid-connected microgrids also provide additional economic benefits—as noted earlier—including the ability to trade excess power with the grid, creating a more dynamic and cost-effective energy system.

Managing the Challenge of Variable Demand in Net-Zero Microgrids

A key challenge for net-zero microgrids lies in incorporating dispatchable generation to meet variable demand. Currently, most dedicated microgrid installations rely on fossil fuel generators—such as diesel or natural gas—to supply at least part, and often all, of the load.

Renewable energy resources face limitations that don’t always align with the needs of private microgrids, which must provide power consistently, under all conditions. Geography plays a significant role in these constraints. In some areas, wind energy variability is highly seasonal, while in others, solar energy faces similar seasonal challenges. Even the daily fluctuation between day and night can pose a serious obstacle.

Even when paired with storage solutions, renewable systems may require large-scale installations to handle demand across all seasons and scenarios. Such setups can quickly become cost-prohibitive, complicating efforts to achieve reliable, sustainable microgrid operation.

A net-zero replacement for fossil fuel generators—one capable of quickly supplying a variable load of any size—would enable the construction of microgrids that can fully support critical facilities reliant on them. Since these systems wouldn’t need to operate continuously, they ideally shouldn’t come with high initial capital costs. Instead, the opposite is preferable—a solution with minimal upfront capital investment but higher operating expenses.

Regardless, the optimal solution will be one that effectively handles variable demand while remaining affordable over the long term.

Addressing variable demand in a net-zero way—without relying on the grid—remains a complex challenge. Could natural gas with carbon offsets provide a short-term solution? Would hydrogen or biofuels prove effective in managing this variability over the long term? And how might nuclear SMRs, traditionally suited for baseload power, fit into this scenario?

Perhaps the answer lies in a combination: inexpensive batteries, occasional curtailment, and aggressive demand response. Only time will reveal the most viable path forward.

What This Means

The primary challenges facing microgrids are all ultimately solvable. However, the problems microgrids themselves could address are far more consequential.

The current grid is poorly equipped to manage the sharp rise in power demand already underway—a trend expected to accelerate in the coming years. Beyond the rapid growth of data centers, the onshoring of manufacturing is emerging as a major tailwind for power demand. This surge could severely strain the grid’s ability to keep up.

Additionally, extreme weather events driven by climate change are becoming more frequent, leading to a surge in blackouts over the past decade. For utilities, the challenge of balancing demand growth with resiliency and reliability will be a daunting puzzle to solve.

In situations where business expansion is hindered by unreliable or insufficient power, one logical solution will be to establish a microgrid and generate power independently. Ideally, such microgrids wouldn’t disconnect users entirely from the grid. Instead, they would supplement it, ensuring high-quality power when the grid falls short.

Microgrid-as-a-service offerings could make this an attractive and convenient solution for the growing number of users who find themselves in this position.