The core insight of the analysis is deceptively simple. The cost of producing hydrogen through electrolysis varies enormously across the planet, driven by the price and availability of renewable electricity, which itself depends on solar irradiance, wind capacity factors, land availability, grid carbon intensity and the timing of renewable generation. Electrolytic hydrogen produced in regions with abundant, cheap wind and solar power can cost a fraction of hydrogen produced where renewables are scarce or expensive. At the same time, the value of hydrogen differs sharply by end use and location: it is highest in industrial clusters that already consume large volumes of grey hydrogen, in ports serving international shipping, and in electricity systems where seasonal storage can displace gas-fired peaking capacity. Policies that flatten this spatial variation — for example, uniform national subsidies or undifferentiated production targets — waste public money by supporting projects in places where hydrogen will never be competitive, while starving the locations where early markets could actually take off.

The authors frame this as a coordination problem. Green hydrogen faces a classic chicken-and-egg dilemma: producers hesitate to build electrolyzers without guaranteed offtakers, while industrial consumers hesitate to convert their processes without assured, affordable supply. Spatially informed policy, the analysis contends, can break this deadlock by concentrating early support in a limited number of well-chosen hubs where production potential and demand density overlap. In such hubs, a single policy package — combining production incentives, offtake guarantees, shared pipeline and storage infrastructure, and streamlined permitting — can achieve economies of scale and learning effects that diffuse, geographically blind support schemes cannot. The approach mirrors lessons from other infrastructure transitions, where clustering early adopters around shared assets proved far more effective than scattering investments across the map.

Technically, the analysis builds on a growing body of spatially explicit energy system modeling. Unlike traditional national or regional models that average costs over large territories, spatially resolved models disaggregate the energy system into grid cells, each characterized by its own renewable resource profile, land constraints, water availability, existing infrastructure and demand density. When hydrogen production, conversion, transport and end use are optimized across thousands of such cells, striking patterns emerge. The cheapest production sites are often far from the largest demand centers, creating a transport cost gradient that fundamentally shapes which supply-demand pairings are economically viable. Hydrogen transport by pipeline is comparatively cheap over land but expensive across oceans, particularly if the hydrogen must first be converted to ammonia or a liquid organic carrier and then reconverted at the destination. These conversion penalties — often amounting to 30 to 50 percent of the delivered energy — mean that imported hydrogen will frequently struggle to compete with hydrogen produced close to where it is used, a conclusion with profound implications for the many national hydrogen strategies built around ambitious import targets.

This spatial lens also reframes the debate over which end uses should be prioritized. The analysis emphasizes that hydrogen’s value density varies by sector and by place. In fertilizer production, where ammonia plants are already concentrated in specific industrial regions, switching from grey to green hydrogen delivers immediate emissions reductions with minimal new infrastructure. In steelmaking, direct reduction of iron with hydrogen is technically mature and can be deployed where existing mills and skilled labor are located. By contrast, speculative uses such as blending hydrogen into natural gas grids or heating buildings deliver low carbon abatement per kilogram of hydrogen and are spatially inefficient, because the gas grid spreads demand thinly across territories where dedicated hydrogen infrastructure makes little economic sense. A spatially informed policy framework would therefore direct scarce green hydrogen toward dense, high-value industrial nodes first, allowing demand to scale before the fuel is asked to serve diffuse, low-value applications.

The policy instruments proposed in the analysis are correspondingly place-based. Production-side support, such as premium payments or contracts-for-difference for green hydrogen, should be calibrated to local production costs rather than set at a single national level, ensuring that support is sufficient to trigger investment in high-cost regions only where strategic value justifies it. Demand-side mandates and quotas should be phased in where industrial consumers are concentrated, creating guaranteed markets that de-risk private capital. Infrastructure planning should prioritize corridors connecting the best renewable resource zones to major industrial clusters and ports, with shared, open-access pipelines and storage lowering the entry barrier for smaller producers and users. Permitting regimes, often the silent killer of clean energy projects, should be accelerated within designated hydrogen hubs. The authors argue that such spatial targeting is not industrial policy by another name; it is simply an acknowledgment that energy systems are physical, and that the physics and economics of hydrogen are inseparable from geography.

The analysis also confronts the equity and geopolitical dimensions of spatial targeting. If green hydrogen production concentrates in a handful of resource-rich regions — the sun belts and wind corridors of the world — there is a real risk of replicating the fossil fuel era’s patterns of extraction and dependency, in which a few exporters supply many importers. The authors note that spatially explicit planning can mitigate these risks by identifying a broader portfolio of viable production regions, including many in the Global South that possess excellent renewable resources but lack the infrastructure and institutional support to exploit them. Development finance, capacity building and technology transfer targeted at these regions could diversify global supply, capture local value added, and prevent the green hydrogen economy from hardening into a new oligopoly. Conversely, importing countries that overestimate their future hydrogen needs and lock in long-term import contracts may find themselves stranded with expensive supply as domestic production costs fall.

Timing emerges as another critical variable. The analysis stresses that early demand creation matters more than early production capacity, because demand signals are what attract private investment along the entire value chain — electrolyzer manufacturing, renewable buildout, storage and transport. Policies that subsidize supply without cultivating committed offtake have, in the authors’ assessment, produced a global landscape of announced but unbuilt projects. Spatially informed demand-side instruments — such as quotas requiring a rising share of green hydrogen in ammonia, methanol and refinery feedstocks within defined industrial clusters — create the bankable revenue streams that financiers require. Once a handful of hub markets reaches critical mass, learning curves in electrolyzer manufacturing and renewable deployment can drive costs down globally, and the geography of competitiveness will gradually expand outward from the initial strongholds.

For researchers, the analysis issues a methodological challenge: energy models that cannot resolve space are increasingly inadequate for hydrogen policy design. The authors call for wider adoption of high-resolution, open datasets on renewable resources, grid infrastructure and industrial demand, and for model intercomparison exercises that test how sensitive policy conclusions are to spatial assumptions. For policymakers, the message is more direct. The green hydrogen transition will not be won by the country with the most generous blanket subsidy or the most sweeping national strategy, but by those who identify the right places, match supply to demand with physical infrastructure, and concentrate support where each public dollar buys the most abatement. In a technology where costs remain high and margins thin, geography is not a detail — it is the strategy.

Subject of Research: Spatially informed policy design to accelerate green hydrogen demand

Article Title: Spatially informed policies can accelerate green hydrogen demand

Article References: Spatially informed policies can accelerate green hydrogen demand. (n.d.). https://doi.org/10.1038/s41560-026-02139-x

Image Credits: AI Generated

DOI: 10.1038/s41560-026-02139-x

Keywords: green hydrogen, spatial policy, electrolysis, hydrogen hubs, renewable energy, industrial decarbonization, energy system modeling, hydrogen infrastructure, energy transition, hydrogen demand, Spatially, informed

The core idea is elegantly simple in principle. When renewable electricity floods the grid and prices collapse, electrolysers can split water into hydrogen and oxygen. Rather than storing that hydrogen directly, which is hampered by hydrogen’s low volumetric energy density and its tendency to leak through even metal pipelines, the gas can be reacted with carbon monoxide and carbon dioxide contained in the producer gas generated by gasifying biomass. In the presence of a nickel-based catalyst, this methanation reaction yields methane, chemically identical to the natural gas already flowing through national grids. The result is a seasonal energy store of almost unlimited scale, using infrastructure that already exists, while simultaneously recycling biogenic carbon that would otherwise escape to the atmosphere.

The review found enormous variation in how efficiently this chain of conversions performs on paper. Reported Bio-SNG production efficiencies ranged from a disappointing 26 percent to a striking 86.4 percent on a lower heating value basis, reflecting stark differences in gasifier type, feedstock, and the sophistication of system integration. The standout performers were dual fluidised bed gasifiers, which indirectly heat the biomass with steam rather than burning it directly with air, operated in a thermal sweet spot of 750 to 850 degrees Celsius. At these moderate temperatures, exemplified by studies modelled on the landmark GoBiGas plant in Sweden and the Güssing facility in Austria, researchers consistently reported efficiencies above 80 percent. By contrast, oxygen-blown and entrained flow gasifiers operating at temperatures approaching 1,300 degrees Celsius often delivered substantially lower returns, sometimes falling below 40 percent.

Technological preferences across the literature were strikingly clear. Of the studies analysed, dual fluidised bed and circulating fluidised bed gasifiers dominated, largely because they produce nitrogen-free product gas of a quality suitable for methanation while achieving high efficiency at medium scale. On the methanation side, the TREMP process, a multi-stage fixed-bed catalytic design with interstage cooling, appeared in seven studies as the workhorse configuration. When it came to electrolysis, the solid oxide electrolysis cell, or SOEC, was the most frequently modelled technology, followed by mature alkaline electrolysers and the faster-responding polymer electrolyte membrane units. SOECs appeal to modellers because they can exploit high-temperature heat recovered elsewhere in the plant, boosting overall conversion efficiency and lowering operating costs compared with low-temperature alternatives.

One of the review’s most valuable contributions is its dissection of system integration strategies. The authors classified plant layouts by where electrolytic hydrogen is injected and how oxygen reaches the gasifier. The most popular arrangement, adopted in nine studies, adds electrolytic hydrogen into the main methanation stage after a pre-methanation step, while the co-produced oxygen supports gasification, often with buffering storage. This proved something of a design sweet spot: injecting hydrogen early shifts both carbon monoxide and carbon dioxide toward methane, raising carbon utilisation and reducing the burden of carbon dioxide removal, but it demands rigorous heat management because methanation is strongly exothermic. Adding hydrogen later simplifies thermal control yet pushes a larger carbon dioxide separation problem upstream. Roughly equal numbers of studies explored variants relying on air separation units or hybrid oxygen supplies.

The methodological landscape tells its own story. Equilibrium models based on Gibbs free energy minimisation, implemented overwhelmingly in the Aspen Plus simulation environment using the ubiquitous RGibbs reactor block, accounted for 17 of the 27 studies reviewed. These models compute the theoretical end-state of reactions and are computationally cheap, making them attractive for rapid screening of plant concepts. However, they ignore reaction kinetics, catalyst behaviour, and temperature gradients, which means they can flatter real-world performance. A minority of ten studies adopted hybrid kinetic-equilibrium frameworks, pairing equilibrium gasification with kinetic sub-models for methanation, and these delivered more realistic predictions in multi-stage systems where heat removal and reaction rates genuinely constrain methane yield. Only one study in the entire corpus, work by Di Salvo and Wei on industrial decarbonisation in California, went beyond zero-dimensional black-box modelling to include a one-dimensional spatial description.

Validation emerged as a recurring weakness that the review’s authors flag as a serious barrier to commercialisation. Only a minority of the modelled systems were benchmarked against pilot-scale or industrial data. Notable exceptions include the Menin and colleagues studies, which anchored their gasification models to experimental data from the Güssing plant, and the Al Zakwani work, which achieved deviations below 5.5 percent for major gas species against the historic ADAM I methanation project. Many other studies relied purely on literature comparisons or theoretical consistency checks, leaving real confidence in their absolute efficiency claims difficult to establish. Compounding the problem, system boundaries and efficiency definitions varied wildly between papers, with only one study explicitly clarifying whether reported figures were net of the plant’s own auxiliary power consumption for oxygen production and gas compression.

Perhaps the most glaring gap concerns the very reason power-to-gas exists in the first place. Nearly all reviewed models assumed steady-state operation, yet the input electricity from wind and solar is inherently volatile. Only the Rivarolo and Massardo study performed a year-long, time-dependent thermo-economic simulation, and only the Katla work explicitly analysed buffer storage of hydrogen and oxygen alongside three distinct operating states, from abundant renewable input to a fallback mode where gas is diverted to combined heat and power when the wind stops blowing. The review argues that dynamic simulation capturing start-up, shutdown and fluctuating hydrogen supply is central to assessing power-to-gas viability, and that flexible methanation reactors and appropriately sized hydrogen buffers must become standard elements of future models rather than afterthoughts.

The authors conclude that the modelling foundation for power-to-gas integrated with biomass gasification is strong but incomplete, and they set out a clear research agenda: validated kinetic models for both gasification and methanation, dynamic simulations reflecting genuine renewable input profiles, techno-economic assessments that incorporate carbon pricing and declining electrolyser costs, and operational strategies for managing variable hydrogen supply. Several megawatt-scale demonstration plants producing Bio-SNG have already operated in Denmark, Sweden, Germany and France, and European pilot projects have shown that the approach can balance coupled electricity and gas networks. If the modelling community can close the validation and dynamics gaps, the dream of storing a summer’s worth of surplus sunshine and wind as pipeline-grade renewable methane, closing the carbon cycle in the process, could move from simulation screens to commercial deployment in decarbonised energy networks.

Subject of Research: Modelling of power-to-gas energy storage systems integrated with biomass gasification for bio-synthetic natural gas production

Article Title: A review on modelling of power-to-gas energy storage integrated with biomass gasification

Article References: Naderi, M., Reynolds, A., & Doherty, W. (2025). A review on modelling of power-to-gas energy storage integrated with biomass gasification. Discover Biotechnology, 2(1), Article 36. https://doi.org/10.1007/s44340-025-00045-8

Image Credits: AI Generated

DOI: 10.1007/s44340-025-00045-8

Keywords: power-to-gas, biomass gasification, Bio-SNG, methanation, electrolysis, dual fluidised bed, renewable energy storage, SOEC, process modelling, synthetic natural gas, energy transition, Aspen Plus

The work comes from SUPREN, a research group at EHU that is leading a large-scale European project known as UnLOHCked, focused on the social, environmental and economic assessment of large-scale green hydrogen supply chains in Europe. Victoria Laura Barrio, full professor at EHU and lead researcher of the project, explains that one of the central challenges facing these supply chains is deceptively simple: how to move and store the gas itself. Hydrogen contains a vast amount of energy per kilogram, but as an ultra-light gas it occupies an enormous volume, which makes transporting and storing it both technically awkward and expensive. Solving that logistics problem is widely seen as a prerequisite for building an international hydrogen market.

One of the most promising answers is a family of materials known as liquid organic hydrogen carriers, or LOHCs. These are organic liquids that behave much like conventional oils, into which hydrogen is incorporated through a straightforward chemical reaction. Because the hydrogen is chemically bound within a pumpable liquid, it can be stored and transported using existing oil and gas infrastructure, a fact that could dramatically lower the barriers to international trade. At the destination, the hydrogen is released from the carrier through a reverse process, and the carrier liquid can be returned for reuse. The researchers emphasise the technology’s considerable potential and foresee it playing a key role in the global green hydrogen trade in the near future.

The strategic logic of LOHC-based trade is already shaping national planning. Several countries are developing future strategies for the production, export, import and consumption of hydrogen, and Barrio notes that it would make particular sense to bind hydrogen to the liquid carrier in southern Europe or Africa, where solar energy is highly competitive, or in regions with strong wind energy potential. The hydrogen could then be shipped easily in the form of LOHC, riding on infrastructure originally built for fossil fuels. In this vision, sun-belt and wind-belt exporters become the energy suppliers of a decarbonising world, while industrial importers in northern Europe and East Asia plug into those flows.

To test whether such flows can truly be sustainable, EHU researcher Irene Rey carried out a detailed sustainability assessment of these international supply chains, now published in the Chemical Engineering Journal. The team performed a life cycle assessment of every stage involved in generating green hydrogen, hydrogenating it into the carrier liquid, transporting it by sea to the end consumer, releasing it at its destination and returning the carrier liquid, while excluding the final use and consumption of the hydrogen itself. The analysis contemplated different configurations of producing countries with high renewable potential, including Namibia, Saudi Arabia, Norway and Spain, and consumer countries such as Germany, the Netherlands, Japan and Italy, alongside maritime transport routes and different types of land-based distribution.

The study’s principal innovation lies in what it added to the conventional toolkit. Life cycle assessment and techno-economic analysis are standard instruments for evaluating energy systems, but the researchers also incorporated a social risk analysis of the supply chains, an aspect that has been little studied until now. Because hydrogen production would be located in countries with markedly different social, economic, political and institutional conditions, the production stage shows a high variation in potential social risks. Labour standards, governance quality, human rights conditions and community impacts all vary enormously between candidate exporter nations, meaning that two hydrogen molecules with identical carbon footprints can carry very different social burdens depending on where and how they were made.

The technical results point clearly to where improvement efforts should be concentrated. The researchers found that further work is needed to improve the efficiency of green hydrogen production and of the release of hydrogen from the carrier, since both stages involve high energy consumption and are the most critical links in the supply chain. Electrolysis powered by renewable electricity and the dehydrogenation step at the point of import together determine much of the overall energy penalty, emissions profile and cost of delivered hydrogen. Gains in these two stages would ripple through the entire system, improving every sustainability dimension simultaneously.

Yet the study’s most sobering conclusion is that no configuration emerges as a winner on all fronts. According to Rey, the results show that there is no perfect scenario delivering benefits across the social, environmental and economic dimensions at once. Instead, she argues, a balance should be achieved across the entire supply chain, with priority not given only to economic aspects. Routes that minimise delivered cost may concentrate social risk in vulnerable producer regions, while configurations that maximise environmental performance may struggle to compete commercially. Designing the future trade will therefore require explicit trade-off analysis and policy frameworks that internalise social and environmental performance alongside price.

The stakes of getting this right are considerable. Hydrogen could account for up to 14 percent of global final energy consumption by 2050, with an ever-increasing share traded internationally as new value chains emerge, a shift likely to reconfigure global energy trade much as oil did in the twentieth century. Regions with abundant renewable resources, such as Africa, Latin America, the Middle East and Oceania, are increasingly viewed as potential exporters, while Europe, Japan and South Korea are expected to become key importers. Rey cautions that designers of green hydrogen corridors must do more than simply reduce carbon emissions and production costs; they must also consider the geopolitical and social implications of the flows they create.

Her question cuts to the heart of the energy transition’s equity dilemma: how can a future hydrogen trade be developed without reproducing the resource extraction dynamics in which the Global South supplies raw energy for the benefit of the technological and economic development of the Global North? The EHU study, conducted as part of Rey’s doctoral thesis at the Chemical and Environmental Engineering Department of the Bilbao School of Engineering under the direction of Ion Agirre and Professor Barrio, and carried out in collaboration with the Polytechnic University of Milan, offers a springboard for answering it. By demonstrating that social risk can be quantified and integrated into supply chain design alongside environmental and economic metrics, it provides policymakers and industry with a practical framework for building a hydrogen trade that is not only clean and competitive, but also just.

Subject of Research: Sustainability assessment of international LOHC-based green hydrogen supply chains

Article Title: The design of the future global trade in green hydrogen should also consider social and environmental aspects

Article References: The design of the future global trade in green hydrogen should also consider social and environmental aspects. (n.d.). Original publication

Image Credits: AI Generated

DOI: Not provided

Keywords: green hydrogen, liquid organic hydrogen carriers, LOHC, hydrogen supply chains, life cycle assessment, social risk analysis, energy transition, renewable energy, global hydrogen trade, sustainability, electrolysis, energy policy

The heart of conventional aluminum production is the smelter, a vast hall filled with electrolytic cells known as pots. Inside each pot, an electric current is passed through a molten mixture of alumina and cryolite, an aluminum fluoride electrolyte, causing liquid aluminum metal to separate out at the cathode. The problem sits at the other electrode. Conventional anodes are made from petroleum coke, coal tar pitch, and recycled anode material, and the electrolytic reaction consumes their carbon, releasing carbon dioxide as a direct chemical byproduct. For every ton of aluminum produced, industry consumes roughly 410 to 420 kilograms of carbon anode material, forcing smelters to replace anodes every 25 to 28 days. The process also triggers occasional reactions with the fluoride electrolyte that emit perfluorocarbons, chiefly CF4 and C2F6. These gases are vanishingly small in mass, less than 0.003 percent of total emissions, but on a carbon dioxide equivalent basis they account for roughly 18 percent of the smelting stage’s climate impact because of their extraordinary warming potential.

Inert anodes promise to rewrite this chemistry entirely. An inert anode is a carbon-free substitute that is not consumed in the reaction, so instead of carbon dioxide the cell exhales pure oxygen. The concept has been under development since the 1990s, but the technology is now closer to commercial reality than ever, with Alcoa, Rio Tinto, Rusal, Arctus, and Hydro all funding pilot deployments in Canada, Russia, and Germany. Major engineering hurdles remain, however. The ideal material is still undecided, with candidates spanning oxide ceramics, metallic alloys, and ceramic-metal composites called cermets, all of which must survive one of the most hostile environments in industrial chemistry: a corrosive molten salt bath operating at extreme temperatures. Equally contested is the energy question. Published studies disagree on whether inert anode electrolysis demands more or less electricity than the carbon anode process it would replace, with estimates ranging from roughly 43 to 61 megajoules per kilogram of liquid aluminum compared to a reported carbon anode range of 48 to 63.

Against that backdrop of uncertainty, researchers at Argonne National Laboratory have produced the first published life cycle assessment of primary aluminum production using inert anodes, modeling the entire production chain with the R&D GREET 2024 framework developed at the laboratory. The study compares a conventional carbon anode against a deliberately conservative synthetic inert anode across North American operating conditions. Because no single guaranteed benefit of inert anodes exists beyond eliminating direct electrolysis emissions and slashing anode replacement rates, the team built their analysis around those certainties and then swept the uncertainties with sensitivity analyses.

Modeling the inert anode required changes at two stages of production. In the smelting stage, the researchers zeroed out the electrolysis-related carbon dioxide, CF4, and C2F6 emissions that dominate the carbon anode baseline. To capture the dramatic reduction in anode consumption, they combined the best-case carbon anode consumption rate of 1.5 centimeters per day with a worst-case inert anode corrosion rate of 40 millimeters per year and a dense metallic anode composition of 8.47 grams per cubic centimeter. Even under this deliberately pessimistic combination, the inert anode replacement rate works out to just 3.86 percent of the carbon anode it replaces, a more than 25-fold reduction in anode material flowing through the plant. For smelting energy, the team adopted the North American average of 50 megajoules per kilogram as the carbon anode baseline and tested inert anode values up to 61 megajoules per kilogram, the highest figure in the literature.

The most methodologically inventive element of the study is its treatment of anode manufacturing. Because no frontrunner inert anode material exists, a detailed inventory of upstream processing impacts would be premature. Instead, the researchers scaled the energy and emissions of anode production relative to the carbon anode baseline, using a carbon-anode-equivalent multiplier spanning 1x, 2.5x, 5x, 7.5x, 10x, 25x, 50x, 75x, and 100x. This heuristic absorbs unknowns such as the recyclability of future anode materials and the industrial-scale energy cost of producing ceramics or specialty alloys. Combined with ten different electricity grid mixes, including eight continental U.S. regions defined by the North American Electric Reliability Corporation plus representative North American and Chinese smelter mixes from the International Aluminium Institute, the framework generated a total of 90 distinct modeling scenarios.

The headline result is striking. Under a representative North American smelter grid, which draws heavily on hydropower at roughly 93.6 percent, switching to inert anodes cut total life cycle carbon dioxide equivalent emissions by 37 percent, even when smelting energy was raised to the pessimistic 61 megajoules per kilogram. Net energy use still fell by about 1 percent, thanks chiefly to the collapse in anode replacement demand. The reason is straightforward: eliminating direct carbon dioxide and perfluorocarbon emissions from electrolysis removes an enormous share of the smelting footprint that no amount of grid decarbonization alone could address, since the anode consumption itself is a chemical source of emissions.

The sensitivity analysis then delivers the study’s most practically valuable output: boundary conditions for engineers. For a North American smelter on the hydro-rich average grid, inert anode smelting can tolerate up to 61 megajoules per kilogram of liquid aluminum before total energy use or emissions exceed the carbon anode baseline, provided the inert anode itself is manufactured with an impact equivalent to a carbon anode. If manufacturing the inert anode is ten times more impact-intensive, that ceiling drops to 57 megajoules per kilogram, still 14 percent above today’s North American average. On the least favorable U.S. grids, those in the Southeast served by the SERC and FRCC regions, the allowable smelting energy falls to roughly 56 megajoules per kilogram at carbon-anode-equivalent production impact, and 53 at ten times that impact. Critically, if inert anode production impact exceeds 25 times the carbon anode baseline, the maximum allowable smelting energy falls below the current average of 50 megajoules per kilogram for every U.S. grid mix studied, meaning the technology would deliver no net benefit at all unless both anode manufacturing and cell efficiency improve together.

The authors are candid about their simplifications. The study assumes that swapping anodes requires no redesign of the cell or cathode, an assumption challenged by ELYSIS, the Alcoa-Rio Tinto venture, which has stated that commercializing its inert anode technology required reworking the entire smelting process. Anode corrosion products may accumulate on the cathode, and tighter anode-to-cathode spacing could accelerate cathode wear, shortening its lifespan and adding hidden energy and emissions costs. Aluminum purity is another open question, as laboratory experiments with inert anodes have yielded metal ranging from 93.8 to 99.8 percent purity, and any additional downstream purification would erode the environmental gains. The analysis also assumes the same emission-to-energy ratio and recycling rate in inert anode manufacturing as for carbon anodes, choices the researchers justify as the only way to keep the scenario space tractable given the near-total absence of industrial-scale manufacturing data.

Those caveats aside, the study offers the aluminum industry something it has not had before: a quantified map of the tradeoff between how hard it is to make an inert anode and how efficiently it must smelt. With demand for the metal set to double by mid-century and the industry staking its competitive future on low-carbon products, the message from the analysis is that inert anodes can deliver at least a 37 percent cut in greenhouse gas emissions per ton of primary aluminum on North American grids, but only within a well-defined envelope of anode durability, manufacturing intensity, and cell energy efficiency. Future research, the authors argue, should focus on cathode lifespan, metal purity, industrial anode production processes, and recycling rates, the very variables that will determine whether the oxygen-breathing smelter becomes the norm or remains a laboratory promise.

Subject of Research: Life cycle assessment of carbon-free primary aluminum production in North America using inert anodes

Article Title: Life cycle assessment of primary aluminum production in North America using inert anodes

Article References: Ahmed, O. Y., Kolodziej, C. P., Iyer, R. K., & Kelly, J. C. (2026). Life cycle assessment of primary aluminum production in North America using inert anodes. Environmental Advances, 26, Article 100754. https://doi.org/10.1016/j.envadv.2026.100754

Image Credits: AI Generated

DOI: 10.1016/j.envadv.2026.100754

Keywords: inert anodes, primary aluminum, life cycle assessment, aluminum smelting, greenhouse gas emissions, R&D GREET, carbon anode, perfluorocarbons, electricity grid mix, decarbonization, electrolysis, critical minerals

The research team, led by Moritz Langhorst, modeled the transformation of a plant modeled on publicly reported production data from SSAB’s facility in Oxelösund, Sweden, producing around one million tonnes of liquid steel per year. In the conventional blast furnace-basic oxygen furnace system, the plant consumed roughly 1,325 kilotonnes of iron ore pellets and 579 kilotonnes of coal annually, generating about 1,570 kilotonnes of direct carbon dioxide emissions from iron and steelmaking alone. The rolling mill added another 70 kilotonnes. Crucially, the study also tracked the energy-rich process gases—coke oven gas, blast furnace gas, and basic oxygen furnace gas—that integrated plants routinely recycle as fuel, providing over 1 terawatt-hour per year of surplus energy for power generation and district heating.

When the researchers modeled the shift to the hydrogen-based route, the picture changed dramatically. Direct emissions from iron and steelmaking fell by 94 percent, and total greenhouse gas emissions across the system, including indirect emissions from electricity, dropped by 84 percent under Sweden’s low-carbon electricity mix. When hydrogen combustion replaced natural gas in the rolling mill’s reheating furnaces and heat treatment was electrified, the reduction climbed to 89 percent, cutting emissions intensity from 1.94 to 0.25 tonnes of carbon dioxide equivalent per tonne of plate. That is well below the near-zero emission threshold of 0.33 tonnes proposed by the International Energy Agency for primary steel production. But the transformation came at a steep energy price: electricity demand rose eighteen-fold, from roughly 260 gigawatt-hours to more than 4,600 gigawatt-hours per year, driven overwhelmingly by the alkaline electrolysers producing hydrogen on site.

This electrification shock is the study’s central tension. The additional 4.42 terawatt-hours of annual electricity demand would equal roughly 2.7 percent of Sweden’s entire electricity generation in 2023. In countries with carbon-intensive grids, the climate arithmetic collapses: under the average European electricity mix of 242.3 kilograms of carbon dioxide per megawatt-hour, the emission reduction shrinks from 84 percent to just 30 percent. The authors stress that the promise of hydrogen steelmaking therefore depends entirely on locating production in regions with abundant clean electricity—at least until Europe’s power sector approaches climate neutrality around mid-century. It is a caveat with real-world bite, given that several announced green hydrogen and green steel projects have already been delayed or cancelled across Europe.

The study goes further than previous analyses by treating the steel plant as a single, interconnected organism rather than a collection of independent processes. When the blast furnace disappears, so do the process gases that once fueled the rolling mill, forcing downstream operations to rely on external natural gas, hydrogen, or electricity. This structural coupling means that changes upstream ripple through the entire production chain, and it is precisely where the researchers found unexpected leverage. Material efficiency measures—reducing iron losses in the electric arc furnace, improving casting yields from 96.5 to 98 percent, and raising cutting yields in the rolling mill from roughly 91 to 95 percent—trigger cascading reductions that travel all the way back to the hydrogen demand of the direct reduction plant.

The numbers are compelling. Improving the electric arc furnace iron yield from 89.5 to 95.7 percent, a level typical of scrap-based operation, reduced direct reduced iron demand by nine percent and cut the hydrogen needed for direct reduction by 166 gigawatt-hours per year. Energy efficiency measures worked differently: upgrading electrolyser efficiency from 58.7 percent to a projected 2050 value of 69.94 percent cut the specific electricity demand for hydrogen production by 16 percent, while oxyfuel combustion in the reheating furnace trimmed hydrogen use for that process by 15 percent. Because energy efficiency measures act locally while material efficiency measures propagate upstream through the entire chain, the two strategies proved complementary rather than redundant.

Combined, all modeled efficiency measures reduced the plant’s hydrogen demand by ten percent and its electricity demand by twenty percent—savings of 6.3 kilotonnes of hydrogen and 920 gigawatt-hours of electricity per year. In a world where green hydrogen remains scarce, these percentages matter enormously. The study notes that without efficiency measures, the modeled plant would require up to 63.3 kilotonnes of hydrogen annually, while only about 31 kilotonnes of electrolytic hydrogen were produced across the entire EU, EFTA, and the United Kingdom combined in 2023, out of nearly 8 million tonnes of total hydrogen production that was over 90 percent fossil-based. Every tonne of hydrogen saved through smarter material flows directly expands the number of plants that can realistically decarbonize within the constrained supply expected this decade.

The researchers are careful to acknowledge the limits of their model. It does not include techno-economic assessment, and without carbon pricing or financial support, hydrogen-based direct reduction remains uncompetitive with conventional routes. Yield assumptions for the electric arc furnace fed with direct reduced iron may prove optimistic, since oxide gangue in the DRI limits achievable yields, and electrolyser efficiency projections for 2050 have already been revised downward. Still, the model’s emissions estimate for the reference case closely matched SSAB’s reported 2023 figures, and the qualitative findings proved robust across variations in electricity mix and scrap share. The authors also emphasize that scrap-based electric arc furnace recycling, which would cut electricity demand by over 70 percent compared to hydrogen-based production, remains limited by the availability of low-impurity scrap needed for high-quality flat products.

What emerges from this work is less a prediction than a planning instrument. By quantifying material, energy, and carbon flows across an entire production chain under different decarbonization strategies, prospective plant-level material flow analysis gives steelmakers, grid planners, and policymakers a common physical baseline for site-specific roadmaps. It reveals where emissions migrate as the transition proceeds—the rolling mill’s share of plant emissions jumps from four percent to nearly thirty percent—where hydrogen scarcity will bind hardest, and where operational improvements yield outsized systemic returns. As Europe’s steel industry confronts the largest industrial transformation since the invention of the blast furnace, the message of this study is clear: the technology for near-zero-emission steel exists, but its success will be decided in the details of yields, electrolysers, and every kilowatt-hour in between.

Beyond the headline figures, the study’s methodological choice deserves attention. Material flow analysis has a long pedigree in industrial ecology, where it has been used to map the flows of substances through economies and industrial systems for decades. What distinguishes this application is its prospective character: rather than auditing an existing facility, the framework is designed to simulate structural transformations that have not yet occurred, embedding process-level detail within a plant-wide accounting boundary. This allows the researchers to capture interactions that fall through the cracks of both regional-scale models, which lack operational resolution, and single-process studies, which isolate technologies from their surroundings.

The Swedish setting is not incidental. The country combines an unusually clean electricity grid with pioneering industrial initiatives in hydrogen-based ironmaking, making it a plausible early adopter. Yet even under these favorable conditions, the modeled plant’s electricity appetite rivals that of a mid-sized city, underscoring why grid capacity and electrolyser siting have become central concerns for industrial planners. The finding that the rolling mill’s relative share of plant emissions rises sharply after decarbonization of ironmaking also illustrates a broader principle: as the dominant emission sources are eliminated, previously marginal processes become the next targets, requiring successive waves of intervention rather than a single technological switch.

The distinction between the two families of efficiency measures carries practical implications for how decarbonization investments are sequenced. Material efficiency gains, such as yield improvements, propagate upstream and shrink the entire hydrogen production system needed at the front of the plant, while energy efficiency gains act locally but aggregate into substantial electricity savings. Because hydrogen production dominates the new electricity load, improvements in electrolyser performance translate almost directly into reduced pressure on the power system. For policymakers designing support schemes, the analysis suggests that funding yield optimization and electrolyser development together yields compounding benefits that neither achieves alone, effectively stretching a constrained green hydrogen supply across more tonnes of decarbonized steel.

Subject of Research: Plant-level material flow analysis of the transition from blast furnace steelmaking to hydrogen-based direct reduction and electric arc furnace steelmaking

Article Title: A prospective plant-level material flow analysis to assess systemic efficiency in the transition to hydrogen-based steelmaking

Article References: Langhorst, M., Billy, R. G., Song, X., & Müller, D. B. (2026). A prospective plant-level material flow analysis to assess systemic efficiency in the transition to hydrogen-based steelmaking. Journal of Industrial Ecology. https://doi.org/10.1007/s44498-026-00166-1

Image Credits: AI Generated

DOI: 10.1007/s44498-026-00166-1

Keywords: hydrogen steelmaking, green steel, material flow analysis, decarbonization, electric arc furnace, direct reduced iron, resource efficiency, electrolysis, steel industry emissions, energy efficiency, Sweden, industrial ecology