The International Energy Agency has always built its authority on policy. Its World Energy Outlook models are maps of intent: what governments say they will do, not necessarily what markets or industries are already doing. That worked when energy transitions moved at a bureaucrat’s pace. But today, the engine of change is industrial, not political. China — through sheer manufacturing scale and global electrification reach — is driving a transformation that the IEA’s scenarios struggle to capture.

The agency dropped APS from the World Energy Outlook 2025, saying that national commitments are too uneven to model reliably. Instead, it focused on the Current Policies and Stated Policies Scenarios. In effect, the IEA narrowed its gaze to a future far more friendly to oil and gas. A world that changes, but only as fast as formal policy permits. Yet the real world is moving faster, driven not by pledges but by production lines and industrial policy.

China: The Electrifier-in-Chief

Over the past decade, China has fused state planning, industrial finance, and scale to build the world’s most powerful clean-energy ecosystem. In 2024 alone, it sold 12.8 million New Energy Vehicles and exported 1.3 million more. It now accounts for roughly 60 percent of all new renewable capacity installed globally each year. Its solar panel manufacturing capacity will soon exceed the United States’ total electricity demand.

This is not just an energy story; it is an industrial one. Chinese automakers — BYD, SAIC, Geely, Changan — are flooding the Global South with affordable sub-$20,000 EVs, the ubiquitous two- and three-wheelers, bundled with charging networks, battery-recycling plants, and joint-venture factories. Beijing’s “industrial diplomacy” is electrifying emerging markets in the way Western aid once sought to wire them for fossil fuels.

The IEA sees policy diffusion as the main driver of energy transitions. China shows us something else: industrial diffusion. What the IEA calls “infrastructure limitation” in Africa, Southeast Asia, and Latin America is being dismantled by Chinese capital, logistics, and engineering. Electrification is becoming an export commodity.

The Physics of Scale

The story that the IEA’s model misses is not ideological; it’s arithmetic. Every doubling of cumulative solar production cuts costs by about twenty percent; every doubling of battery output by roughly eighteen percent. Those learning curves compound faster than politics can keep up. In 2010, a battery pack cost over $1,000 USD per kilowatt-hour; by 2023, $130. By 2030, it may hit $60. Solar module prices have fallen by over ninety percent since 2010.

Once parity arrives, substitution accelerates. Each ten million EVs on the road displaces around half a million barrels of oil demand daily. At projected adoption rates, that’s the equivalent of erasing an entire Saudi Arabia of oil demand within a decade.

This is the industrial feedback loop that OPEC, ExxonMobil, and the U.S. Energy Information Administration have consistently failed to model. Their scenarios assume hydrocarbons’ dominance and treat innovation as exogenous, a polite way of saying “someone else’s problem.” The IEA broke from that orthodoxy with the APS, which embedded learning curves and cost feedback. Yet by retreating from APS in 2025, the agency risks losing sight of the very dynamics that once made it the gold standard.

The Global South’s Leapfrog

Look beyond Beijing. Across the Global South, Chinese-financed solar farms, grid-stabilization projects, and electric-mobility programs are rewriting development logic. In Kenya, rooftop solar is offsetting diesel generation. In Brazil and Indonesia, low-cost Chinese EVs are scaling faster than policy incentives can track. In the Middle East, Chinese firms are co-building battery-storage complexes once thought decades away.

This diffusion matters because it shifts the geometry of the transition. For decades, energy modernization flowed North to South. Today, it runs in reverse. China’s overcapacity — derided in Western policy circles — is accelerating global deployment by forcing prices down. The IEA’s models, calibrated to declared policies rather than industrial momentum, under-represent this structural feedback.

Capital Flows Tell the Truth

Follow the money. Global clean-energy investment surpassed $2 trillion USD in 2024 and continues rising about 6–7 percent annually. Fossil-fuel investment, meanwhile, has plateaued or declined. Capital allocation now looks more like APS than like the new CPS (Current Policies Scenario), or even the still conservative Stated Policies Scenarios (STEPS). Markets are already betting that electrification, not hydrocarbons, defines the mid-century energy mix.

If the IEA’s CPS and STEPS project fossil demand growth into the 2040s, they describe a world that capital markets have already abandoned. APS aligns more closely with where investors are placing real money — grids, storage, batteries, renewables, and electrified transport.

The Model and the Machine

What’s unfolding is a divergence between two kinds of forecasting: the model built on policy, and the machine built on production. The model counts regulations; the machine multiplies learning. The IEA’s WEO 2025 treats electrification as an outcome of government intent. But China’s industrial ecosystem shows it is increasingly a self-propelling system — feedback, not fiat.

This is not to diminish policy. Without it, China’s ecosystem would not exist. But policy there functions as scaffolding for industry, not a ceiling. The IEA’s omission of APS makes sense within its institutional DNA; it reflects what can be officially promised. Yet it leaves unmodelled the real-world force now shaping the transition: manufacturing momentum.

The Consequences for Analysts and Policymakers

For analysts, the lesson is simple: the energy transition is being built, not legislated. The baseline for understanding it is no longer the pace of policy but the speed of industrial learning. For policymakers, particularly in countries like Canada still investing billions in hydrocarbon expansion, the implication is brutal. The world is electrifying faster than you can permit a pipeline.

The APS still fits the facts because it embeds the physics of feedback. The IEA may have stopped publishing it, but China is still proving it — one gigafactory, one grid, one EV fleet at a time.

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By Michael Barnard – Energy Mix Guest Writer

The French philosopher Bruno Latour once said technology doesn’t succeed because it works. It succeeds because enough people act like it does.

For nearly a decade, that’s exactly what happened with green hydrogen as an energy carrier. The story was so compelling, the coalition so wide, the urgency so real, that for a time, it barely mattered that the physics didn’t cooperate.

Now, in 2025, the act is ending. Major energy firms are quietly walking away. Government strategies are being rewritten. Even the loudest champions of hydrogen-fuelled futures have stopped performing certainty. And Latour would recognize every step of this collapse.

How Technologies Become ‘Blackboxed’

Actor-Network Theory (ANT), Latour’s signature contribution to science and technology studies, doesn’t look for simple causal chains. It doesn’t ask whether a technology is good or bad, efficient or wasteful. Instead, it traces how coalitions of people, tools, policies, expectations, and diagrams—actors, both human and non-human—come together to make something seem real, viable, and inevitable.

When that network holds, the object becomes “blackboxed.” Its underlying complexity is hidden. Everyone just uses it, funds it, believes in it. When the network fails, the box opens. The myths spill out.

One well-known example is the case of the pasteurization of milk in France, which Latour analyzed in his book The Pasteurization of France. He showed how Louis Pasteur’s scientific work succeeded not merely because of laboratory discoveries, but because it aligned with the goals of public health officials, military hygienists, farmers, politicians, and media outlets. Pasteur became a central actor in a broad network that collectively transformed microbial theory into national infrastructure. The bacteria weren’t defeated by science alone, but by a network that enrolled everything from hospitals to dairies into a shared protocol of cleanliness and control.

Another example, widely analyzed through an ANT lens by others, is the adoption of electronic medical records (EMRs) in health care systems, something I was involved in professionally for a decade. In countries where EMRs failed to take hold, it wasn’t due to poor software design alone, but due to a failure to align physicians, hospitals, insurers, IT departments, and regulatory frameworks into a coherent network. The technology, in effect, had no actors willing to perform it into widespread use.

In contrast, in places where EMRs succeeded (like Estonia or parts of Scandinavia), the network included strong political will, patient buy-in, standardized interfaces, and legal frameworks that made digital records the obligatory passage point for healthcare interactions.

Belief Pumps Up Hydrogen

Green hydrogen’s rise between 2015 and 2022 was a textbook case of such network formation. It began with climate targets that demanded something—anything—that could decarbonize hard-to-electrify sectors. Industrial heat, long-haul transport, seasonal storage, aviation. Each problem became an actor in need of a solution.

Hydrogen, long the bridesmaid of energy debates after the early 2000s hype cycle, fit the bill. Governments began publishing hydrogen strategies with cost targets and gigawatt dreams. Electrolyzer firms received infusions of capital. Startups promised hydrogen-powered trucks, ships, planes, even entire economies. Reports from respected agencies forecast dramatic cost declines. Roadmaps used 2030 as a kind of magical threshold, just far enough away to absorb the uncertainties. The European Commission, the Japanese government, the Australians and Koreans, as well as Californians, all signed on.

At the same time, oil majors saw in hydrogen a rare opportunity to stay relevant. Shell, BP, TotalÉnergies, and others joined industry alliances and launched pilot projects. They saw a chance to repurpose gas infrastructure, rebrand fossil assets, and secure public subsidies in the name of climate progress.

The Hydrogen Council, launched at Davos in 2017, became the face of this alignment. A forum where oil CEOs, automakers, and government ministers could all agree that hydrogen was the path forward. That unanimity wasn’t evidence of inevitability. It was evidence of enrollment.

Meanwhile, a host of non-human actors reinforced the narrative: Electrolyzer prototypes at trade shows, shiny infographics showing hydrogen pipelines spanning continents, funding mechanisms with lofty acronyms, and cost curves pointing downward with the confidence of gravity.

Policy documents functioned like scripts in a play. If you were a policymaker, you had to say the lines. If you were a company, you had to audition for funding. If you were a journalist, you had to report the boom. By 2020, green hydrogen was not just a possibility. It had become an expectation. A technology made real through repetition.

The Promise Deflates

And then, the disarticulation began. Not all at once, and not dramatically. That’s not how these networks unravel. Instead, they fray.

BP quietly dissolved its hydrogen mobility unit. No press release, just a subtle change in direction. Airbus delayed its hydrogen aircraft program, likely permanently. The math didn’t work. The infrastructure didn’t exist. British Columbia, which had once flirted with seven major green hydrogen energy projects, walked away from all of them. In Australia, the government shifted from dreams of exporting green hydrogen to Japan and Korea to a more sober focus on domestic industrial use—steel, ammonia, chemicals. In Norway, the showcase hydrogen ferry ended up emitting more carbon dioxide than the diesel vessel it was meant to replace. The maritime pivot stayed for now, but the broader transportation ambitions faded.

Then came the signal moves in Europe and the United States. In France and Germany, top-level economic advisory bodies issued a joint recommendation: stop funding hydrogen in road transport. Focus on battery-electric trucks instead. The advice wasn’t controversial in economic circles. It just punctured the public narrative. In the United States, the Department of Energy under the Trump administration began considering cuts to four of the seven federally supported hydrogen hubs, including the one in California, which had been focused on hydrogen for transportation. Whether motivated by ideology or economic realism, the effect was the same: another leg of the hydrogen-for-energy stool kicked out.

Latour would not be surprised. These weren’t technical failures, strictly speaking. Electrolyzers still electrolyze. Pipelines still transport. Fuel cells still function. What changed was the willingness of actors to keep performing the alignment. When the financial returns didn’t arrive, when the infrastructure costs mounted, when alternative technologies outpaced hydrogen on key metrics, the incentive to stay in character disappeared. The performance unraveled.

And with it, the black box opened. Inside was a technology that made sense for some things—fertilizer production, chemical feedstocks, methanol synthesis—but not for many of the things it had been promised to revolutionize. The round-trip efficiency remained poor. The cost per kilogram remained stubbornly high. The competition, particularly from electrification, kept advancing. Every government that pulled back, every company that shifted focus, every analyst who updated projections was part of the same Latourian process. They stopped reinforcing the illusion. They exited the network.

A Niche Technology

What remains is a smaller, more stable version of the hydrogen story. Green hydrogen is still useful, but it is not universal. It is not the Swiss Army knife of decarbonization. It is a niche tool, appropriate for specific applications where no better alternative exists. Industrial use, not energy fantasy. The actor-network will persist in that narrower form. Fewer players, fewer speeches, fewer renderings of hydrogen planes and trucks. More spreadsheets. More quiet deployments. Less theatre.

There’s a lesson here, and it’s not that hydrogen is bad or that its supporters were wrong. It’s that techno-economic narratives are not objective truths waiting to be discovered. They are constructed, maintained, and occasionally dismantled by networks of aligned actors. When everyone agrees, it’s often because disagreement has been designed out. And when the story collapses, it does so not with a bang but with a quiet shifting of feet, a few missing names on the conference agenda, a line item dropped from the budget.

Green hydrogen for energy was a compelling narrative. It enrolled resources, focused attention, and gave policymakers a sense of direction. But it wasn’t grounded in competitive fundamentals. It was performed into existence, and it’s now being performed back out. Not because it never had value, but because the value was always contingent on everyone believing at once.

For half a decade I’ve been one of the people on the wrong side of the narrative, along with people like BNEF founder Michael Liebreich, chemical engineer Paul Martin, road decarbonization expert David Cebon and many others that I know. We’ve been trying to tell people what was obvious to us because we looked at the reality, not just the story.

But Latourian networks are self-healing. Until they aren’t.

The network is no longer holding. The actors are stepping away. And as Latour would remind us, that’s when you see what was keeping the whole thing alive.

This opinion piece originally appeared on Cleantechnica. Republished with the author’s permission.

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A wind turbine manufacturer in Chengdu, China has unveiled the world’s biggest offshore wind turbine, a 26-megawatt machine with more than 30,000 parts that is nearly 10 MW larger than the previous record-setters.

The announcement by state-owned Dongfang Electric took the offshore wind industry by surprise, Bloomberg News reports, at a time when stiff competition has triggered a price war across the industry.

“Turbine manufacturers are looking to increase the size of offshore equipment to reduce costs by generating more power from fewer units,” Bloomberg says. “Lower prices are still needed because the technology remains more expensive than fossil fuels such as coal in most parts of the world,” and “Chinese manufacturers also face fierce competition from their peers.”

Dongfang, which also produces an 18-MW turbine, said the blades on the new units measure 310 metres in diameter. The device covers a swept area of 53,100 square metres, “roughly the size of seven standard soccer fields,” writes REVE. A single turbine can deliver 62 million kilowatt-hours of electricity per year, enough to power 37,000 households and cut carbon dioxide emissions by 62,000 tonnes.

“With its semi-submersible floating platform and mooring system, enhanced by smart control and sensing technologies, the turbine extends wind power’s reach into deeper waters, ensuring stable operation,” REVE adds. “The turbine offers customizable options for various water depths, providing optimized solutions for deep-sea wind power resources.”

In its announcement, Dongfang called the turbine “the latest achievement of the rapid technological progress of the entire industrial chain of China’s wind power equipment,” adding that it “provides strong technical support for helping China build a new power system and achieve the ‘dual carbon’ goal.” That government objective calls for the world’s biggest present-day source of climate pollution to peak its emissions by 2030 and hit carbon neutrality by 2060.

The turbines can also withstand a Category 17 typhoon, packing winds of up to 220 kilometres per hour, using technology that withstood Super Typhoon Makar in early September, Dongfang said. Makar, known elsewhere as Super Typhoon Yagi, killed two people and injured 92 others “after what’s likely the strongest storm to hit southern China in a decade made landfall,” BNN Bloomberg reported at the time.

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By Mitchell Beer

Hydrogen “hype” is coming down to earth, with a major export deal stalling out in Atlantic Canada while a highly-touted investment goes on hold in the West.

Earlier this month, the Globe and Mail reported that plans to ship renewably-produced “green” hydrogen from the East Coast to Germany had been delayed by at least a year, possibly longer, due to “a supply-demand mismatch and the largest wave of global inflation in decades.” Shipments were supposed to begin next year. But out of 10 “promising production projects” in the Atlantic provinces, “none have secured a final investment decision yet,” the Globe wrote, citing Jens Honnen, the energy policy adviser leading implementation of the German-Canadian energy partnership on behalf of the German government.

“The aim is still to have the first shipments happen in the mid-2020s, probably around 2026, 2027 or 2028,” Honnen said.

Less than a week later, Australian mining giant Fortescue Ltd. announced it had withdrawn a green hydrogen project in Prince George, British Columbia from environmental review. “Australian billionaire Andrew Forrest, the founder and executive chairman of Fortescue, has run into challenges globally in trying to diversify the company, whose businesses include iron ore mining, and transform it into a clean energy powerhouse,” the Globe wrote.

“Fortescue recently completed an evaluation of our global project portfolio, with an aim to prioritize the projects in locations with favourable green energy policies and affordable and reliable renewable energy,” wrote Fortescue’s North American president Andrew Vesey, in a September 26 letter later released by the B.C. Environmental Assessment Office.

“We have focused our energy project portfolio to include a pipeline of commercially viable projects to carry us forward and meet future demand, while acting in the best interests of our shareholders,” he added. “With that, we have decided to put on hold our Project Coyote in Prince George until we are able to secure more favourable power pricing and availability.”

Prior to those announcements, the complications and challenges associated with the projects had begun to pile up. In B.C., climate campaigners warned the Prince George project would require a daunting 900 megawatts of electricity to produce the hydrogen through electrolysis and another 100 MW to convert it to ammonia.

“To put that in perspective,” the Globe and Mail wrote, “the C$16-billion Site C hydroelectric dam in northeastern B.C. will add 1,100 megawatts of capacity when fully completed in 2025,” decades after it was first proposed.

In Nova Scotia, meanwhile, local residents who say they support wind energy development to meet local electricity needs and reduce the province’s greenhouse gas emissions have been speaking out against Canada’s biggest wind farm to date, a 404-turbine, 64,000-hectare project proposed by Halifax-based EverWind Fuels, intended to power its proposed green hydrogen production facility in Point Tupper.

“It needs to happen to help us get off coal, but these massive projects have nothing to do with that,” Marsha Plant, a co-founder of Protect Guysborough, told The Energy Mix in July.

“Let’s be clear, Nova Scotia needs more renewable energy,” stated the Green Nova Scotia First website. “But wind turbines for hydrogen/ammonia export are not the answer. Hydrogen and ammonia production requires vast resources including land, water, and energy, and will not help reduce Nova Scotia’s greenhouse gas emissions.”

Too Much Hydrogen

In August, EverWind signed an offtake agreement with its partners in Germany, state-owned utility Uniper and private gas and electricity provider E.On, to supply 500,000 tonnes of green ammonia per year. That was after chemical engineer and Hydrogen Science Coalition member Paul Martin questioned whether the project would be cost-competitive against the thousands of hydrogen production projects being proposed around the world.

“Many other locations (i.e. western Australia, north or west Africa, Chile, etc.) will be able to make ammonia far more cheaply, with a carbon intensity even lower than that achievable by these wind-only projects, because they have access to better quality wind plus solar resources,” he told The Mix in July. “These will allow the same investment in hydrogen and ammonia production equipment to generate twice as much hydrogen and hence more ammonia on the same site, for the same investment of capital.”

By contrast, “a few dedicated wind energy projects would produce a lot of power to permit decarbonization of Nova Scotia’s grid, without the need for capital subsidy toward hydrogen production,” he added.

The same cost considerations were at the heart of Fortescue’s decision in Prince George.

“What really sets Fortescue apart is we know the system; we know the play, because we are a huge operator ourselves,” Mark Hutchinson, CEO of Fortescue Future Industries, told investors and analysts on a call in June. “Fortescue is steadfast in our commitment to green hydrogen,” he added, and sees green hydrogen as “what the world ultimately needs” over the longer term.

“However, our financial discipline always comes first. We will never do projects that are not economically viable. As the green hydrogen market develops around the world, it is really clear that the cost of green power, which is obviously the way you start with green hydrogen, has to be in the US$30 range [per megawatt-hour] to make projects viable.”

Where prices fall above that threshold, he said Fortescue would move to help drive them down by “producing electrons” in places like West Australia and Queensland. Hutchinson’s office declined an interview request to elaborate.

‘Series of Headwinds’

Canada is not the only place where green hydrogen development is running into headwinds. In the United States, a year after the Biden administration announced a US$7-billion plan to jump-start clean hydrogen projects across the country, there’s mounting concern that the work is falling behind.

“The goal of this startup money? To help the hubs attract tens of billions more in private sector investment to pay for construction costs,” Canary Media wrote this week.

“There’s still little publicly available information to indicate whether these ‘clean hydrogen hubs’ are likely to attract the needed private sector investment, however. Just as opaque are their potential community and climate impacts,” the news story states. “Environmental groups, community advocates, and energy experts have grown concerned that the projects are off track — and increasingly dismayed that the [U.S. Department of Energy] and the hub projects are not giving them the transparency needed to confirm or deny these worries.”

A week earlier, Canary Media reported delays in launching a green hydrogen hub in southern Mississippi, where Jackson-based Hy Stor Energy had proposed “gigawatts’ worth of wind, solar, and geothermal capacity” to produce “zero-carbon renewable” hydrogen, store it in underground salt caverns, and supply it exclusively to a local green steel plant owned by Swedish steelmaker SSAB. Hy Stor cancelled a deal to buy more than a gigawatt of electrolyzer capacity to convert the incoming electricity to hydrogen.

“The green hydrogen market has faced a series of headwinds that have resulted in it taking longer than anticipated to bring our lead project to fruition,” Eric Reidel, managing director of Connor, Clark & Lunn Infrastructure, Hy Stor’s controlling shareholder, told Canary Media in a statement. “Because of this, it did not make sense for us to make the upcoming capacity reservation payments that would have been due.”

Meanwhile, HeatMap is reporting the collapse of a hydrogen production plant in the Buffalo-Rochester area, once expected to be the largest in the northeastern U.S.

The difficulties also extend to “blue” hydrogen, the version derived from natural/methane gas, a process that critics say could produce 50 per cent more global warming than just burning fossil fuels. Last month, multinational oil and gas company Shell announced it was cancelling what it called a “low-carbon” blue hydrogen plant on Norway’s west coast, citing insufficient market demand, just days after Norwegian state oil company Equinor scuttled plans to export blue hydrogen to Germany, citing high costs and low demand.

Touting Hydrogen to Delay Electrification

The delays and setbacks may come as little surprise to analysts and advocates who’ve long questioned whether hydrogen is the best way to meet the dozens of different energy service needs that its strongest proponents like to pitch—or whether it’s suitable at all for many of those uses. In 2021, Bloomberg New Energy Finance founder Michael Liebreich said fossil fuel companies are happy to hype “uncompetitive” uses of hydrogen in cars and home heating if it means delaying the shift to electric vehicles and heat pumps that are practical and affordable.

Around that time, Liebreich published a hydrogen “ladder” that showed a seven-point scale for potential hydrogen applications, from “unavoidable” uses like fertilizer and some industrial applications to “uncompetitive” notions like light aviation, home heating, hydrogen buses, subway cars, and two- and three-wheelers.

“If you’re an oil and gas company, in a way, talking about hydrogen is kind of a two-way bet because if it works, then you’re embedded in the hydrogen industry—but if it doesn’t work, you’ve delayed the transition to the thing you don’t make, which is electricity,” Liebreich told Recharge News at the time. “At worst it creates confusion, which is great [for them]. And these companies have an interest in this [electrification] stuff not moving too fast, I’m afraid—for all their good words.”

In early 2023, Liebreich was sharply critical after the British Columbia Investment Management Corporation (BCI) and Sydney, Australia-based Macquarie Asset Management bought a 60 per cent share in Britain’s gas transmission network, National Gas, which had announced plans to use hydrogen for home heating. BCI manages the retirement savings of 715,000 British Columbians.

“If the price you paid was driven by hydrogen for space heating, then this will end up as one for the history books—and not in a good way,” Liebreich on LinkedIn.

“Unless, of course, it’s a cynical bet that the UK’s Net Zero 2050 plan will be delayed or derailed (with the help of lashings of lobbying), and the asset can be milked indefinitely,” he added. “But only a cynic would think it could be that, and luckily I’m not a cynic.”

The root of the problem, Martin explained at the time, is that hydrogen is too small and volatile a molecule to be safely or effectively transmitted, distributed, or used with existing gas pipelines, turbines, boilers, cooktops, or burner jets. That reality would translate into huge retrofit costs, and likely serious energy efficiency losses in homes, if hydrogen were used for all the purposes its biggest backers have been suggesting.

So when utilities pitch hydrogen heating as an option, they’re likely talking about 20 per cent blends of hydrogen added to standard fossil gas, leading to at best a 7 per cent reduction in greenhouse gas emissions.

Even if the product is “green” hydrogen from solar panels or wind turbines—as opposed to the “blue” variety that depends on deeply uncertain carbon capture and storage technology to reduce emissions—it will still be more expensive and deliver less energy value than using the electricity directly, Martin said.

“If you deploy those energy production assets efficiently by means of heat pumps and the electrical distribution grid, you get a multiplier, because you’re using electricity to pump heat from a cold place to a warm place and getting three units of energy for every unit you put in,” he said. “If you go with hydrogen, a fractional energy return for every unit of energy invested is the best you’re ever going to get.”

So “every time you involve hydrogen,” he added, “you get not small losses, but large, substantial losses.”

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By Yaxin Zhou

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By Emi Bertoli, Energy Analyst, Silvia Laera, Energy Policy Analyst, Floris van Dedem, Energy Analyst

Islands experience unique energy challenges

Small and remote islands are subject to an array of energy challenges. As they are often isolated from mainland power grids, many face difficulties balancing supply and demand. They tend to be heavily dependent on imported fossil fuels, which can lead to high costs and energy security risks. And, despite their limited contributions to global emissions, they are disproportionately affected by the impacts of climate change, including extreme weather events.

These dynamics create major inequities. Electricity generation on islands can cost 10 times more than on mainland territories and countries. In 2021, island nations had the most expensive average cost of electricity in the world; in the Solomon Islands, for example, electricity cost almost seven times more than in the United States, while electricity tariffs in Caribbean countries are more than double the US average. This can negatively impact socio-economic development. In Pacific island countries, fuel imports accounted for up to 13% of GDP in 2019.

Islands – including those that make up the group known as Small Island Developing States (SIDS) – also need to upgrade their energy infrastructure so that it is resilient to higher temperatures, more frequent natural disasters and flooding related to rising sea levels. At the same time, aging power systems are often inadequate to accommodate growing electricity demand due to economic growth and increased air-conditioning usage. Consequently, many systems are prone to load shedding events and recurrent outages, such as in Sint Maarten, Guam and Dominica, the latter of which was left without electricity for months in 2017 after Hurricane Maria damaged its long-distance grid.

With more than 730 million people living on 11 000 permanently inhabited islands across the world, and with the number of natural disasters rising sharply in recent decades, it is crucial to find solutions to these issues and meet the energy needs of island residents in a secure, sustainable and affordable manner. Expanding the deployment of clean energy technologies, including renewables, therefore presents a major opportunity, while increasing the efficiency and digitalization of energy systems could also deliver major benefits if harnessed.

Distributed energy resources and energy efficiency can make power systems cleaner and more secure

Small and remote islands, which often have abundant renewable energy resources, have the potential to become hubs of clean energy innovation. While a study performed on 36 small island economies showed that the majority generated less than 10% of their electricity from renewable sources, encouraging trends are visible. Total installed renewable energy capacity in Small Island Developing States more than doubled between 2010 and 2022, reaching 4.6 gigawatts (GW) – with plenty of room for additional growth. In Caribbean SIDS alone, the development potential for solar PV is estimated at nearly 72 GW, equivalent to the installed solar PV capacity for all of Latin America in 2023.

Distributed energy resources – or small-scale energy resources that are usually situated near sites of electricity use, such as rooftop solar – could play an important role in boosting the deployment of renewables on islands, increasing the security, resilience and affordability of power systems while accelerating decarbonisation.

However, this will also require complementary technologies, such as an expansion of battery energy storage systems (BESS). These systems can help facilitate the integration of variable renewable energy sources (which is particularly complex on islands due to limited grid infrastructure), maintain grid stability, and provide intraday flexibility  – supporting not only single households, but also larger configurations of distributed energy resources and even utility-scale renewable plants.

Microgrids, or decentralized energy systems that can be isolated from the main grid because they have their own sources and loads, and Virtual Power Plants (VPPs) – networks of decentralized power generating units, storage systems and flexible demand – can also help optimize the allocation of distributed energy resources, while promoting energy efficiency and improving resilience.

Efforts are underway to deploy these technologies on some islands already. In Adjuntas, Puerto Rico, 1 000 solar panels are set to power 17 small businesses as part of a battery-supported community microgrid, bolstering the local economy and standing ready to provide electricity in the event of fresh natural disasters. Meanwhile, the VPP4ISLANDS project is integrating virtual energy storage technology, as well as digital twin and distributed ledger technology, to enable enhanced VPPs and the creation of smart energy communities on Gökçeada Island in Türkiye and Formentera in Spain.

At the same time, increasing energy efficiency measures in end-use sectors can contribute to further reductions in energy costs and carbon dioxide (CO₂) emissions in Small Island Developing States, while also enhancing the resilience and reliability of energy systems and leading to local job creation. For example, implementing Minimum Energy Performance Standards and Labels (MEPSL) for appliances – which boost the efficiency of products on the market and provide greater transparency for consumers – allowed Fiji to save around 9.3 gigawatt-hour (GWh) of electricity in one year, comparable with electricity generated in the country from solar in 2021. Expanding the product coverage of the Fiji’s MEPSL programme could allow the buildings sector to save 17% of its electricity demand annually by 2030, according to analysis by the Copenhagen Centre on Energy Efficiency.

Digitalization can help leverage local flexibility and optimize opportunities

Electricity systems on small islands are frequently over-sized, with high reserve power generation capacity and ancillary services needed locally to respond to daily and seasonal fluctuations, such as changes in demand resulting from high and low tourist seasons.

Digitalization therefore offers opportunities to optimize electricity systems at the local level through better planning, management and operation. Geospatial databases, such as the UNDP Data Platform for Small Island Developing States, can help policy makers leverage data and analysis to make more informed decisions. Artificial intelligence can also deliver benefits. Curaçao is testing the use of AI for renewable energy forecasting and the predictive maintenance of electricity infrastructure.

Meanwhile, digitally-enabled demand response can help leverage local resources to optimize or defer grid investment. For example, implementing direct load control mechanisms targeted at high-consuming appliances, such as water heating and cooling in commercial and residential buildings, can help reduce peak consumption. Islands such as Barbados, King Island, Guadeloupe and La Réunion and Hawaii are already testing demand response approaches.

Islands are stepping up efforts, but international cooperation remains key to accelerating clean energy transitions

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By Mitchell Beer

Bonnie Gao, Sunehra Mehrun, Tai Vo, and Wren Droesse are the recipients of the inaugural round of grants from the Trellis Fund, a new student award program for women who plan to enter green energy careers.

Gao is studying with the Social Exergy and Energy Lab at the University of Victoria. Mehrun is enrolled in the Automotive and Vehicle Engineering Technology at McMaster University, with a focus on electric vehicles. Vo has entered the Construction Engineering Technician Program at Toronto’s George Brown College. And Droesse is already in the field as a wind turbine technician after completing the training program at Lethbridge Polytechnic in Alberta. They’ll each receive a one-time grant of $2,500 to support their studies or their shift into the work force.

Apart from geographic diversity and a mix of different industries, the eight-member advisory committee behind the award was looking for what inspired applicants to enrol in clean energy programs, explained eco-entrepreneur Rebecca Black, who launched the fund in memory of her mother, Veronica.

“We wanted to see thoughtfulness,” she said. “We wanted to be convinced that they were going to pursue what they set out to do. We wanted to know that they might make an impact. And we were interested in their entrepreneurial or creative spirit, balanced with the idea that a lot of the jobs are not entrepreneurial, they’re very infrastructure-focused, so how confident they were studying for a job where they would be able to find employment.”

All of those factors were important at a moment when women only hold 28 per cent of the jobs in the energy sector. “There’s a big gap between the potential and what we’re actually seeing on the ground, when we all know that resilient solutions have a diverse group of decision-makers at the table,” Black said. “So whether you want to be a power line worker, work on clean energy policy in government, or pivot your business career into the clean energy transition, we were accepting applications.”

The advisory committee was also looking for applicants with a strong, practical interest in implementing climate and energy solutions.

“We have the technologies,” Black said. “What we don’t have is the systemic will, and that calls for different ways of thinking about and solving problems.”

Gao and Mehrun both said the grant would make a big difference in helping them complete their studies.

“The next two years are critical in ensuring that the energy transition is equitable and inclusive,” Gao wrote in an email. “The work force in the electricity and energy sector is rapidly changing, and it is critical that opportunities are being created to ensure under-represented groups can enter the work force and participate in the low-carbon energy transition.”

“My goal is to leverage my engineering skills and knowledge to help mitigate the environmental impact of the automotive industry and promote a greener, more sustainable future,” Mehrun said. This grant is crucial for me because the current job market is incredibly challenging, and securing a job to support myself during the school year has been difficult.”

Being a Trellis grant recipient “not only alleviates financial pressure but also boosts my confidence and motivation to excel in my academic and professional pursuits,” she added.

Advisory board member Mary Warner, co-executive director of the Toronto Renewable Energy Co-op, said the Trellis Fund helps address a gap that makes it harder for women to enter clean energy jobs.

“We’ve collectively seen the power of having a support system as you navigate an industry that is not female-led,” she said. “Those connections are so important, to have people to bounce ideas off of.” That’s an areas where the advisory board members, who originally met a decade ago through Toronto-based Women in Renewable Energy (WiRE), are hoping to support grant recipients with informal advice, encouragement, and trouble-shooting.

“We’ve done it ourselves, so it’s to see that replicated,” Warner said.

Black said the Trellis Fund launched at a moment of powerful potential for the energy transition.

“Times have changed,” she said. “Working in climate, there have been some tough years. But right now, I feel a great sense of optimism for many of the things happening out in the world in areas like grid development, affordability, implementation of renewable energy, and in calling out greenwashing. And we’re starting to see the activism that was halted by COVID starting to bubble up again.”

All of those positive developments add up to “a really great time to try and put effort in,” she said. “This is a good time to be busy, and to be on the right side of it. Despite all the difficulties in the world, there’s just so much to do and to be positively focused on.”

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The project represents Canada’s first commercial green hydrogen and ammonia production facility and will include the development of up to 530-turbine wind farm with the ability to generate 3.5 gigawatt (GW) of electricity and 150 megawatt (MW) solar photo voltaic (PV).

Upon completion, the facility is expected to have the capacity to produce 165kta of hydrogen and 5000 metric tons per day of ammonia.

“The agreement is testament to McDermott’s industry-leading delivery and installation expertise, and the breadth of our capabilities across the energy transition,” said Rob Shaul, McDermott’s Senior Vice President, Low Carbon Solutions. “Our century of experience, from concept to completion, and integrated delivery model, means we can offer Abraxas a repeatable modular implementation solution that is expected to drive cost savings, reduce risk and provide quality assurance.”

Under the scope of the agreement, McDermott will provide front-end engineering design (FEED), engineering, procurement, and construction (EPC) execution planning services, and open book EPC cost estimate for the hydrogen production, ammonia processing, and product storage portion of the project.

The company says the work will be led from McDermott’s Houston office with support from its Gurgaon office in India.

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