The study addresses a question that has become urgent for developing economies worldwide: how can a nation expand electricity access to power industrialization and urbanization while simultaneously bending its emissions curve downward? Pakistan offers a striking case. The country accounted for 0.6 percent of global CO2 emissions in 2018, ranking twenty-seventh among the world’s emitters, and its electricity sector alone reached 155.55 MtCO2 in 2024, with oil, coal, and natural gas contributing 65, 41.9, and 48.75 MtCO2 respectively. Compounding the problem, Pakistan imports roughly 88.87 percent of its fossil fuels from the Gulf region, tying its energy security to volatile international markets and a growing import bill.

To untangle the drivers of low-carbon electricity generation (LCEG), the team applied the LMDI decomposition technique to annual time-series data spanning 1985 to 2024, organized around Pakistan’s Five-Year National Economic Planning periods. Rather than relying on econometric models that estimate statistical relationships, decomposition analysis mathematically breaks down changes in low-carbon electricity into six distinct contributing factors: the low-carbon structure of the electricity mix, electricity generation intensity, energy security, energy intensity, carbon productivity, and CO2 emissions themselves. The method’s chief advantage is that it produces complete, residual-free attributions—every unit of change in low-carbon electricity generation can be assigned to one of the six factors, making the results directly interpretable for policymakers.

The decomposition results reveal a turning point. Over the full four decades, aggregated low-carbon electricity generation grew by 415.95 Mtoe, with positive and significant growth in every planning period except 1995 to 1999, when a consumption boom spurred electrical appliance use and energy imports. The most dramatic gains came in the current 2020 to 2024 period, which recorded 167.68 Mtoe of growth. The low-carbon structure factor alone contributed 157.20 Mtoe in this phase, reflecting the start of the China-Pakistan Economic Corridor (CPEC) power projects that have filled historical gaps in electricity production. Before 2013, renewable energy was essentially absent from Pakistan’s electricity mix; today, hydro, nuclear, renewable, and thermal sources account for 25.4, 8.4, 6.8, and 59.4 percent of generation respectively, according to the Pakistan Economic Survey 2023-2024.

The carbon productivity factor tells an equally important story about the economy itself. When carbon productivity rises, a nation generates more economic output per unit of CO2 emitted—the hallmark of decoupling growth from pollution. The study found positive trends in several planning phases, indicating that Pakistan’s economy is improving due to substantial advancements in low-carbon electricity generation. A clear reduction of 23.77 percent in the current phase suggests the country is making genuine progress toward commitments such as the Paris Agreement. Meanwhile, the CO2 emissions factor showed aggregated emissions of 462.90 Mt affecting low-carbon electricity generation over 1985 to 2024, though the most recent phase recorded a reduction of 0.49 percent, equivalent to 35.94 Mt.

For the forward-looking half of the analysis, the researchers turned to the LEAP model, an energy-environment simulation framework developed at the Stockholm Environment Institute. LEAP operates as a bottom-up accounting framework that tracks both demand-side and supply-side technologies, simulating how electricity is generated, substituted, and consumed under different assumptions about fuel types—hydro, thermal, nuclear, and renewable. The team calibrated the model with 2013 as the base year, chosen deliberately because renewable electricity from biofuels, solar, and wind first entered Pakistan’s mix that year, and extended projections to 2035 under three scenarios: business as usual (BAU), low demand, and high demand, each tested at a 5 percent significance level.

The demand scenarios expose the divergent fates of each fuel. Total electricity consumption, which grew from 6.25 Mtoe in 2013 to 9.60 Mtoe in 2024, is projected to keep expanding through 2035. Hydroelectricity shows a zigzag pattern with modest average growth of 0.14 percent between 2025 and 2035, constrained by precipitation variability and water security concerns. Thermal electricity, by contrast, is the clear loser: it declined by 0.58 percent annually from 2013 to 2024 and is projected to fall by 0.85 percent on average through 2035, with a 3 percent decline by 2035 under the low-demand scenario as renewable substitution takes hold. Nuclear electricity demand, which grew 4.85 percent from 2013 to 2024, continues rising at 0.77 percent through 2035, while renewable energy—solar, wind, and biomass—grew 7.62 percent during the historical period and is projected to advance at 0.75 percent on average through the forecast window.

The headline finding emerges from the CO2 mitigation scenario. Under the low-demand pathway, in which all low-carbon electricity sources except thermal operate at full advantage and no power plants run below capacity, electricity-related CO2 emissions fall by 6.45 percent yearly between 2013 and 2035, even as electricity output increases at an average rate of 4.34 percent per year. If the maximum share of low-carbon electricity becomes available from 2025 onward, the reduction in CO2 emissions until 2035 reaches 68.551 percent in the mitigation scenario, with the abstract’s headline figure of 63.40 percent representing the projected cut under the study’s central assumptions. Thermal generation turns negative in the projections from 2025 onward, meaning fossil-based electricity is progressively displaced rather than merely reduced.

The policy implications are concrete. The authors recommend long-term investment in renewable energy technologies and dam reconstruction for hydroelectricity, noting that roughly 250 engineering structures—including dams, ponds, spillways, and drainage systems—are under consideration to raise electricity efficiency. Pakistan has set a target to mitigate carbon emissions by 50 percent by 2030, and the government has committed to adding about 6,000 MW of photovoltaic solar capacity to accelerate pollution reduction from energy generation. The Private Power Infrastructure Board is currently easing 24 power generation projects, 22 of which are based on renewable energy, signaling that the regulatory framework is shifting toward incentivizing private sector investment in clean electricity.

For a country long trapped between expensive fuel imports and chronic power shortages, the study’s message is that decarbonization and energy security are not competing goals but mutually reinforcing ones. Substituting fossil fuel electricity with hydro, nuclear, wind, biofuels, and photovoltaic solar simultaneously cuts emissions, reduces exposure to Gulf oil and gas markets, and strengthens domestic energy self-sufficiency. The researchers acknowledge limitations—low-carbon electricity costs and sectoral cost information were not available—and call for future work using machine learning approaches for renewable energy, load, and cost forecasting, incorporating external inputs such as population, income, and technology. But the core conclusion stands: with disciplined carbon mitigation policies and sustained technical development, a transitional economy can grow its electricity system fourfold in output terms while cutting its carbon footprint by nearly two-thirds within a single decade.

Subject of Research: Low-carbon electricity generation and CO2 emission mitigation scenarios for Pakistan's electricity sector through 2035

Article Title: Low-carbon electricity generation through demand and carbon neutrality prediction 2035 of a transitional economy: decomposition and LEAP learning approaches

Article References: Low-carbon electricity generation through demand and carbon neutrality prediction 2035 of a transitional economy: decomposition and LEAP learning approaches. (n.d.). https://doi.org/10.3389/fsuep.2026.1766522

Image Credits: AI Generated

DOI: 10.3389/fsuep.2026.1766522

Keywords: Pakistan, low-carbon electricity, CO2 emissions, LMDI decomposition, LEAP model, Energy Vision 2035, renewable energy, carbon neutrality, electricity demand scenarios, energy security, CPEC, decarbonization

The research, led by Jawad Chahine of the Australian University in Kuwait together with colleagues at Shanghai International Studies University, the Lebanese International University, and Beijing Foreign Studies University, arrives at a moment of acute geopolitical anxiety. Recent escalations in the Gulf region have driven war risk insurance premiums for shipping fleets to roughly five times their stable-condition levels, according to the study’s review of recent assessments. The Strait of Hormuz now records the highest geopolitical risk exposure index in the world, with a score of 264 attributed to persistent regional tensions. Analysts warn that continued instability could abruptly halt the distribution of twenty percent of global liquefied natural gas supplies if key production facilities declare force majeure. Against this backdrop, the question of whether the world should keep betting on a single narrow passage has moved from academic curiosity to strategic urgency.

What makes the new study distinctive is not the identification of the problem, which has occupied maritime security scholars for years, but the way it goes about answering it. The team combined Geopolitical Risk Theory with a complex-systems approach, treating transport networks not as isolated shipping lanes but as interconnected systems whose performance emerges from the interaction of external pressures and internal structure. To operationalize this idea, they built a multi-scale analytical framework spanning three levels. At the macro level, geopolitical risk acts as an external stress variable shaping the probability and intensity of disruptions. At the meso level, the structural properties of the network, including route diversification, rerouting capacity, and flow concentration, determine how shocks propagate. At the micro level, everything is distilled into a quantitative measure the authors call the Weighted System Performance Index, or WSPI, which converts network characteristics into comparable scores.

The baseline numbers are stark. The chokepoint-centered configuration, in which nearly all Gulf energy exports funnel through Hormuz, scores just 0.27 on the resilience-oriented index. The prospective multimodal corridor, by contrast, scores 1.67, more than six times higher. The reason lies in the arithmetic of redundancy. Alternative pipeline routes through Saudi Arabia and the United Arab Emirates can handle only about 2.6 million barrels per day, roughly thirteen percent of the volume transiting the strait. That means approximately 87 percent of the flows passing through Hormuz have no immediate rerouting option in a disruption scenario. The system operates in what the authors describe as binary fashion: either full operation or severe collapse, with little middle ground.

The multimodal alternative tells a different story. By distributing flows across sea, rail, and land routes, the hypothetical Gulf–Levant–Europe corridor eliminates single-point dependency entirely. Under the study’s scenario assumptions, between fifty and seventy-five percent of disrupted flow could be operationally rerouted, and transit times could fall by up to forty percent compared with the traditional Suez route, from roughly twenty days to about twelve. Crucially, the system’s behavior under stress shifts from binary to gradual: instead of catastrophic failure, the network degrades progressively while operators adaptively reroute cargo. The largest single node would carry only twenty to forty percent of total flow, rather than the eighty percent or more concentrated at Hormuz.

To ensure these comparisons were not artifacts of favorable assumptions, the researchers subjected their model to a battery of robustness tests. They recalculated the index with equal weights across all indicators, and the ranking held. They applied a deliberately conservative scoring rule that penalized the multimodal corridor on every indicator, which shrank its advantage from 1.67 to 0.85 but still left it well above the chokepoint system’s 0.27. They ran a hybrid continuous-ordinal specification blending measured values with ordinal classifications, and again the ranking persisted. Finally, they allowed every indicator score to vary by one point in either direction, producing uncertainty ranges of 0.20 to 0.61 for the maritime system and 0.85 to 3.80 for the corridor. The ranges did not overlap. Under every specification tested, the diversified configuration retained the higher resilience score, though the magnitude of its advantage swung considerably with the assumptions.

A notable technical contribution is the Python-based computational tool the team developed to run these calculations in real time. The program processes normalized indicator scores, applies theory-informed weights, computes the weighted resilience and vulnerability components, and generates visual outputs including comparative indicator distributions and sensitivity assessments. Its sensitivity-analysis module can automatically recalculate results under equal weights, conservative scoring, hybrid specifications, and bounded score uncertainty. The authors emphasize that the tool’s reproducibility extends only to executing the stated calculations with the supplied inputs; it does not independently validate the assumptions behind those inputs. Still, the approach represents a step toward the kind of dynamic, scenario-based modeling that static risk assessments have long lacked.

The study is equally notable for what it declines to claim. The authors are explicit that their analysis does not demonstrate that a global transition away from maritime chokepoints is actually underway, nor that geopolitical risk is the primary causal driver of any such shift. The Gulf–Levant–Europe corridor they evaluate is a prospective scenario, not an operational system, and several of its scores rest on analytical assumptions rather than observed measurements. Infrastructure readiness, border-crossing efficiency, security conditions, legal and customs compatibility, political stability, insurance costs, and cargo-handling capability are all acknowledged as unresolved implementation constraints, particularly acute because parts of the proposed route traverse geopolitically sensitive and post-conflict regions. The higher WSPI score signals a structural resilience advantage under the model’s assumptions, not commercial viability or the capacity to handle volumes comparable to Hormuz’s twenty million daily barrels.

Perhaps the most intellectually important finding is a conceptual one: diversification does not eliminate risk, it redistributes it. The multimodal configuration does not make geopolitical threats disappear; it spreads exposure across a wider geographical and political space, reducing the likelihood of total system failure while introducing new complexities such as coordination challenges, regulatory fragmentation, and uneven infrastructure quality. In the language of the systems framework the authors adopt, safety is not achieved by eliminating risk but by managing it, emerging as a property of network structure rather than of any single transport mode. A system lacking alternative routes is inherently susceptible to cascading failures, a dynamic well documented in the literature on interdependent networks, where the failure of one node can trigger domino effects across the whole system.

The implications ripple outward from the Gulf. The Strait of Hormuz is not alone: the Straits of Malacca and the Suez Canal feature prominently in the same literature on maritime chokepoints, and scholars continue to debate how replaceable each one is. Some analyses suggest the Malacca disruption impact is modest because the Sunda Strait offers an alternative; others classify it as a highly state-dependent route that is difficult to fully replace, a discrepancy the new study attributes to differences between fleet cost optimization models and actual vessel traffic density analyses. What the current research adds is a transferable template: a multi-scale framework that lets policymakers compare any two network configurations, maritime or terrestrial, on common resilience terms. Whether the world’s trading powers act on that template, and whether a corridor through the Levant can ever clear the formidable political and logistical hurdles in its path, remains an open question. But the mathematics of the argument is now on the table, and it suggests that the cheapest route is not always the safest one.

Subject of Research: Scenario-based comparison of maritime chokepoint versus multimodal trade corridor resilience under geopolitical risk

Article Title: Evaluating alternative trade network configurations under geopolitical risk: a multi-scale systems approach

Article References: Chahine, J., Guangda, W., Ghosn, F., Suliman, L., & Nissi, Y. (2026). Evaluating alternative trade network configurations under geopolitical risk: a multi-scale systems approach. Frontiers in Political Science, 8, Article 1973066. https://doi.org/10.3389/fpos.2026.1973066

Image Credits: AI Generated

DOI: 10.3389/fpos.2026.1973066

Keywords: Strait of Hormuz, geopolitical risk, supply chain resilience, multimodal corridors, trade networks, maritime chokepoints, systems modeling, WSPI index, energy security, Gulf–Levant–Europe corridor, Python simulation, route diversification

The numbers behind that argument are stark. The Strait of Hormuz, the narrow maritime chokepoint through which roughly a fifth of the world’s oil supply passes, has been repeatedly disrupted, constraining hydrocarbon exports and sending crude prices from around $70 to more than $110 per barrel by March 2026, before easing back to around $80 in July as the market absorbed the volatility. According to the analysis, attacks on shipping in the strait have curtailed up to 20 million barrels per day of exports, generating substantial daily revenue losses for producing states. For consumers, the same disruption translated into higher petrol, diesel and jet fuel prices; for producers, it meant a paradoxical combination of elevated prices and collapsing export volumes.

Iran’s response to Israeli and American strikes on military, nuclear and some energy facilities included attacks on targets across the region, among them energy infrastructure within the Gulf Cooperation Council states. The analysis documents physical damage and, in some cases, temporary suspensions at key sites such as Ruwais in the United Arab Emirates, Ras Tanura in Saudi Arabia, Bapco Energies in Bahrain and Mina Al-Ahmadi in Kuwait, alongside disruptions to Qatari liquefied natural gas production. These are not marginal facilities. They anchor the export capacity of some of the largest hydrocarbon producers on Earth, and their vulnerability exposed a structural weakness at the heart of the Gulf’s economic model.

That weakness, as Bayoumi and Mason frame it, is a circular dependency. For years, Gulf states, particularly Saudi Arabia and the UAE, have invested heavily in renewable and clean energy as part of broader economic diversification strategies. But the hydrocarbon revenues that fund that diversification are precisely the revenues most exposed to geopolitical disruption. Despite elevated oil prices, revenue losses, rising defence expenditure and inflationary pressures are weighing on gross domestic product, national budgets and planned investments across the region. The severity of the impact depends on how long the conflict lasts, but a prolonged disruption could force governments to reprioritise, potentially squeezing the very clean energy programmes designed to reduce their dependence on oil income.

The authors place the 2026 conflict in a longer historical pattern of energy shocks driving policy change. The oil crises of the 1970s and the 1979 Iranian revolution quadrupled prices and pushed the United States to expand fossil fuel production, including opening new fields in Alaska and loosening drilling regulations. The price surge of the early 2000s led many oil-importing countries to subsidise fuel prices while the US and Canada expanded output. More recently, the Russia-Ukraine war prompted the European Union to diversify its energy sources and increase investment in renewables through its REPowerEU programme. Each shock, in other words, produces a short-term scramble for supply followed by a longer-term restructuring of the energy system.

What distinguishes the current moment, the analysis argues, is the revelation of a persistent policy failure: governments continue to treat energy security primarily as a supply problem rather than a demand-side transformation challenge. The distinction matters technically. Supply-side responses, stockpiling, diversifying suppliers, subsidising fuel, leave economies exposed to the next disruption because demand for globally traded fuels remains intact. Demand-side transformation, by contrast, reduces the volume of traded fuel an economy needs in the first place, through efficiency, electrification of transport and heating, and deployment of domestic renewable generation whose fuel cost is zero and whose supply chain is local. Repeated geopolitical shocks strengthen the strategic case for exactly that approach.

The differential outcomes among importing economies illustrate the point. China has fared better than many East Asian economies thanks to strategic stockpiles and more resilient supply chains, and its firms hold dominant positions in solar photovoltaics and electric vehicle manufacturing, positioning them to benefit if sustained high oil prices accelerate global electrification. In the European Union, natural gas prices have risen more than 70 percent and refined products such as jet fuel have experienced extreme price volatility, prompting the bloc to tell member states to prepare for prolonged disruption. Europe, already reshaping its energy system after the war in Ukraine, has diversified gas supplies across Norway, Qatar, Algeria and, at reduced levels, Russia, with Azerbaijan emerging as an additional supplier, while oil imports are spread across the United States, Norway, Kazakhstan and Middle Eastern producers.

Yet the transition is not a zero-sum contest between West and East. Cross-border clean energy investment has become a central pillar of energy security in its own right. The UAE’s Masdar and France’s TotalEnergies operate an approximately $2.2 billion joint venture across Asia, combining capital and technology. Saudi Arabia’s ACWA Power is partnering with European firms to export solar electricity and develop transmission links, while hydrogen projects such as the Yanbu green hydrogen project aim to supply European markets, with similar initiatives underway in the UAE and Oman. Gulf funds and firms have already financed multi-gigawatt solar projects in emerging markets, especially in Africa and Asia, and the UAE is leading cooperation with a South Korean KEPCO consortium on nuclear power. These partnerships suggest that the clean energy economy is being built through networks of interdependence rather than blocs of exclusion.

In the near term, the authors expect governments to respond to price shocks in familiar ways: subsidising fossil fuels, rationing, promoting remote working and demand-reduction measures, and in some cases reverting to more carbon-intensive options such as coal. Such measures echo past crises and may temporarily raise emissions. But over the longer term, the logic of energy security points in the opposite direction. Reducing dependence on globally traded fuels, not merely diversifying their sources, will be critical, the analysis argues, and governments that shift to clean technologies will benefit from adoption curves already driven by falling costs and rapid innovation. Recent research on electric vehicles has even identified evidence of a cascading positive tipping point, in which growing uptake reinforces itself through infrastructure, consumer expectations and manufacturing scale.

The central lesson the authors draw is that electrification and clean power are no longer just climate strategies but instruments of economic resilience and national security. Countries that move fastest will not only reduce emissions but also insulate themselves from future geopolitical shocks, whether those shocks come from a strait closed by war, a pipeline sabotaged, or a supplier weaponising exports. The 2026 Iran war, in this reading, is less a detour on the road to decarbonisation than a demonstration of why the road exists at all: an energy system built on concentrated, contested, globally traded fuels will remain a strategic liability, and every crisis makes that liability harder to ignore.

Subject of Research: The impact of the 2026 Iran war and Gulf energy infrastructure disruption on global energy security and the clean energy transition

Article Title: Conflicts and energy transitions: The case of the 2026 Iran War

Article References: Bayoumi, M., & Mason, R. (2026). Conflicts and energy transitions: The case of the 2026 Iran War. PLOS Sustainability and Transformation, 5(8), e0000265. https://doi.org/10.1371/journal.pstr.0000265

Image Credits: AI Generated

DOI: 10.1371/journal.pstr.0000265

Keywords: energy transition, energy security, Iran war, Strait of Hormuz, Gulf Cooperation Council, renewable energy, electrification, oil prices, geopolitics, Masdar, ACWA Power, PLOS Sustainability and Transformation

The research team, led by Franck Hervé Akaffou and colleagues, set out to solve a persistent problem in climate impact studies: single models tend to capture only part of the complex, lagged relationships between weather and river behavior. Rain that falls in a basin today may take weeks or months to reach a reservoir, and temperature drives evaporation losses that further complicate the picture. To handle these dynamics, the team built a five-step framework that begins with a broad pool of fifteen machine learning algorithms and progressively narrows and combines them into stronger predictive systems.

Central to the approach is what the authors call a multi-lag integration of precipitation and temperature. Rather than feeding a model only the current month’s weather, the framework incorporates rainfall and temperature from preceding periods, allowing the algorithms to learn how antecedent conditions propagate through a watershed into reservoir inflow. This matters enormously in West African basins, where seasonal monsoon dynamics and long hydrological memory mean that a wet season’s signature can appear in dam inflows long after the rains have ended.

The selection process was deliberately competitive. All fifteen candidate models were first evaluated on their ability to reproduce historical inflow and generation patterns, and only the top performers advanced to the next stage. Through iterative ensemble stacking, in which the outputs of strong models are themselves combined and retrained, and through the systematic elimination of weak learners that added noise rather than signal, the team refined its predictions layer by layer. The result was a marked improvement in accuracy and efficiency across the modeling chain, with the coefficient of determination and the Nash-Sutcliffe efficiency, two standard measures of hydrological model skill, both exceeding 0.6 for all inflow simulations and for the energy simulations at the Bagre, Nangbeto, and Taabo dams.

To train and validate the models, the researchers drew on the CHIRPS and CHIRTS datasets, which provide high-resolution satellite-based and station-calibrated records of precipitation and temperature from 1983 to 2014. This three-decade historical window gave the algorithms a rich sample of West Africa’s climate variability, including major droughts and wet years, against which to learn the relationships between climate and dam performance. Once calibrated, the models were turned toward the future using projections from twelve bias-adjusted CMIP6 climate models, the latest generation of global climate simulations, together with their ensemble mean.

The future scenarios spanned three emissions pathways: SSP1-2.6, a low-emissions world consistent with ambitious mitigation; SSP2-4.5, an intermediate pathway; and SSP5-8.5, a high-emissions trajectory with continued reliance on fossil fuels. Projections were made for two future periods, a near future from 2036 to 2067 and a far future from 2068 to 2099, allowing the team to distinguish changes likely to emerge within the working lifetime of today’s dams from those that may arrive by century’s end.

The climate projections themselves are stark. Under the highest emissions scenario, temperatures across the study basins could rise by as much as 4.5 degrees Celsius, a level of warming that would sharply increase evaporation from reservoir surfaces and alter the intensity and timing of monsoon rainfall. Precipitation changes, by contrast, are spatially heterogeneous: some basins are projected to become wetter while others dry out, and the direction and magnitude of change vary across scenarios and time horizons. This patchiness is precisely why basin-by-basin machine learning assessments are valuable, since a single regional average would obscure the divergent fates of individual dams.

For reservoir inflows, the projections reveal a region divided. Buyo faces the steepest declines, with inflows projected to fall by up to 24 percent, while Nangbeto could see reductions of up to 13 percent. Reduced inflow means less water passing through turbines, and the knock-on effects for electricity generation are severe: hydropower output at Nangbeto may decline by up to 19 percent, and at Taabo the projected drop reaches a remarkable 58 percent, a loss that would ripple through national grids that rely on these plants for a substantial share of their supply. Yet the picture is not uniformly grim. Manantali and Taabo are projected to experience inflow increases, and Bagre may actually see energy gains of up to 42 percent under the high-emissions scenario, illustrating how climate change can create winners as well as losers even within a single region.

These contrasting outcomes carry important implications for how West African countries plan their energy futures. A dam projected to gain generation capacity may be able to shoulder more of the regional load, but planners cannot simply reallocate risk from one basin to another, because the projections are scenario-dependent and the high-emissions pathway that produces the largest gains at Bagre also produces the most dangerous warming elsewhere. The authors argue that the findings underscore an urgent need for adaptive management strategies: strengthening the resilience of hydropower systems themselves, diversifying national and regional energy portfolios, and integrating additional renewable sources such as solar, which is abundant across the Sahel and largely uncorrelated with hydrological variability.

For hydropower managers and policymakers, the message is that proactive measures must begin now, well before the mid-century projections materialize. Reservoir operating rules calibrated to a stable twentieth-century climate may become maladaptive as inflow patterns shift, and the long lead times for infrastructure investment mean that decisions made this decade will determine whether the region’s power systems bend or break under climate stress. By demonstrating that machine learning ensembles can skillfully link climate projections to dam-level outcomes, the study offers a practical template for the kind of granular, basin-specific risk assessment that energy security in a changing climate will increasingly demand.

Subject of Research: Climate change impacts on reservoir inflow and hydropower generation in West African dam basins assessed with ensemble machine learning

Article Title: Integrating machine learning to assess climate risks on reservoir’s inflow and hydropower generation across West African basins

Article References: Akaffou, F. H., Obahoundje, S., Diedhiou, A., Kouassi, K. L., Diallo, D., Amoussou, E., Yamegueu, D., & Ofosu, E. A. (2026). Integrating machine learning to assess climate risks on reservoir’s inflow and hydropower generation across West African basins. PLOS Climate, 5(9), e0000986. https://doi.org/10.1371/journal.pclm.0000986

Image Credits: AI Generated

DOI: 10.1371/journal.pclm.0000986

Keywords: hydropower, machine learning, climate change, West Africa, CMIP6, reservoir inflow, ensemble modeling, SSP scenarios, CHIRPS, energy security, adaptive management, PLOS Climate

The study, published in the journal Meteorological Applications under the title The influence of sudden stratospheric warmings on extreme European electricity demand, found that SSWs raise the likelihood of extreme electricity demand, defined as demand at least 20 percent above the average, by a factor of 1.5 to 3 in northern and central Europe. The mechanism is straightforward once the physics is understood. During an SSW, temperatures in the stratosphere over the pole rise sharply as the normal westerly winds weaken or even reverse. This upheaval aloft can disturb the jet stream and the pressure patterns below it, allowing cold Arctic air near the surface to spill southward into Europe and North America in the weeks that follow.

Crucially, that surface cold does not arrive immediately. The chain of events that links the stratosphere to the ground typically unfolds over a period of a few weeks after the polar winds shift. That delay is what gives SSWs their potential value as a forecasting tool. Governments, grid operators and energy suppliers do not learn of the elevated risk only when the cold snap arrives; they can receive a signal weeks in advance, giving them time to secure fuel supplies, arrange additional generation capacity and prepare public communications before demand surges.

The clearest recent illustration came in February 2018, when the polar vortex split in two. Dr Regan Mudhar, who led the new study and is now based at the University of Lausanne, recalled the sequence of events. These events do not always affect surface temperatures, he noted, but the 2018 split was followed by severe cold weather in the United Kingdom and much of northern Europe, the episode popularly remembered as the Beast from the East. The frigid conditions that swept across the continent disrupted transport, closed schools and workplaces, and drove heating demand sharply upward, straining energy systems in several countries.

To move beyond anecdote, the research team analysed the relationship between SSWs and extreme electricity demand across Europe, with heating demand as the key driver of the connection. The analysis revealed a clear statistical link: in the weeks following stratospheric warming events, the probability that electricity demand would reach extreme levels increased substantially in the northern and central parts of the continent. Because heating is such a dominant component of winter energy consumption, the coldest post-SSW periods translate directly into the highest stress on power networks, particularly where electricity and heating are tightly coupled.

One of the most important findings of the study is that the size of the demand response varies considerably from country to country. Scandinavian nations, which are largely well adapted to extreme cold thanks to decades of investment in insulation, district heating and cold-resilient infrastructure, saw a comparatively smaller increase in energy usage when temperatures fell after SSWs. Their systems are engineered with severe winters in mind, so an additional degree of cold produces a more modest increment in consumption. France, by contrast, experienced a much steeper increase in demand. The country operates a highly electrified energy system, with electric heating widespread in homes and businesses, meaning that cold weather feeds almost immediately into electricity consumption rather than being partly absorbed by gas or other fuels.

This national variation carries a pointed lesson for countries in the middle of energy transitions. Dr Hannah Bloomfield of Newcastle University, a co-author of the study, observed that the United Kingdom is relatively well adapted to cold weather at present because of its reliance on gas central heating, which decouples much of the winter heating burden from the electricity grid. However, she cautioned, as the country moves toward net-zero emissions, a great deal of that traditional gas heating must be electrified, for example through the replacement of gas boilers with heat pumps. Once that shift occurs, periods of cold weather combined with low wind will become increasingly challenging for keeping the lights on at a low cost to consumers, because the same meteorological episode will simultaneously drive up electricity demand and potentially suppress wind generation.

The compounding nature of that risk is what makes the stratospheric signal so valuable. A sudden stratospheric warming does not merely raise the chance of cold temperatures; in a decarbonised system it could coincide with the worst possible combination of high demand and reduced renewable output. Anticipating such episodes weeks ahead would allow grid operators to raise reserve margins, coordinate interconnector flows between countries, top up stored energy and schedule maintenance away from the vulnerable window. In effect, the stratosphere offers a long-range heads-up that no conventional weather forecast at the surface can match, because the disturbance originates tens of kilometres above the Earth and its influence propagates downward over time.

The findings also sit within a broader conversation about climate change and extreme events. Dr Mudhar emphasised that the world is, and will continue to be, warmed by greenhouse gas emissions, but SSWs will very likely still happen, bringing cold weather with them. A warming climate does not eliminate the possibility of severe cold snaps in Europe; the stratospheric circulation will continue to vary, and when it breaks down, the familiar pattern of polar air escaping southward can still unfold. This means that although cutting emissions remains crucial for mitigating climate change, it is equally important, in his view, to consider how prepared societies are for extreme events of this kind as they transition toward renewable energy sources. Adaptation and mitigation, in other words, must proceed together.

The research was funded by the Natural Environment Research Council through its GW4+ Doctoral Training Partnership, and it adds a distinctive strand to the growing field of research that connects stratospheric dynamics to societal impacts on the ground. For energy planners, the message is that the atmosphere provides warnings in layers: the first sign of a potentially costly cold spell may appear not in a ten-day forecast but in the behaviour of winds circling the pole at altitudes where airliners rarely venture. Learning to read that signal, and building it into the operational planning of electricity systems that are becoming more weather-dependent by the year, could mean the difference between a manageable cold snap and a genuine energy crisis the next time the polar vortex decides to fall apart.

Subject of Research: The influence of sudden stratospheric warmings on extreme European electricity demand

Article Title: Stratospheric winds can warn of extreme energy demand in Europe

Article References: Stratospheric winds can warn of extreme energy demand in Europe. (n.d.). Original publication

Image Credits: AI Generated

DOI: Not provided

Keywords: stratospheric polar vortex, sudden stratospheric warming, electricity demand, extreme cold, Europe, energy security, heat pumps, net-zero transition, renewable energy, weather forecasting, Beast from the East, University of Exeter

The scale of the challenge is what makes the transition so dramatic. India is among the world’s fastest-growing energy consumers, with an expanding economy, a rising middle class, and hundreds of millions of people whose demand for electricity, transport, and industrial goods continues to climb. For decades, that growth has been fueled overwhelmingly by coal and imported oil, leaving the country exposed to price volatility, supply disruptions, and the mounting physical risks of climate change. The research frames India’s push into renewables as a deliberate attempt to break this dependence, coupling long-term energy security with the climate commitments the country has made on the international stage. In this reading, every gigawatt of solar capacity installed is simultaneously an environmental measure, a balance-of-payments decision, and a geopolitical signal.

Technically, the transition rests on a portfolio of technologies rather than a single silver bullet. Solar photovoltaics and onshore wind form the backbone of current expansion, exploiting India’s exceptional solar irradiance across the subcontinent and strong wind corridors in states such as Gujarat and Tamil Nadu. Hydropower contributes dispatchable generation and grid stability, while nuclear energy offers a low-carbon baseload option that can complement the intermittency of renewables. Perhaps the most forward-looking element is green hydrogen—hydrogen produced by electrolysis powered with renewable electricity—which the study identifies as a potential pillar of future industrial decarbonization, particularly for sectors like steel, fertilizers, and long-haul transport that cannot easily be electrified directly. Together, these technologies aim to reduce fossil fuel dependence while maintaining the reliability that a modern economy demands.

The geopolitical upside of this build-out, according to the analysis, is already visible. Expanding renewable capacity enhances India’s standing as a global climate leader, giving New Delhi moral and diplomatic weight in international negotiations that it historically lacked as a major coal consumer. The study highlights how the clean energy agenda strengthens strategic partnerships, pointing specifically to India’s participation in the Minerals Security Partnership, a multinational initiative designed to secure responsible and diversified supply chains for the critical minerals that underpin batteries, wind turbines, and electric vehicles. It also supports regional cooperation in the Indo-Pacific, where energy infrastructure, maritime trade routes, and technology transfer increasingly intertwine with security policy. In effect, clean energy becomes a diplomatic instrument, allowing India to deepen ties with partners who share both its climate goals and its interest in balancing regional influence.

Yet the same technologies that promise independence create new dependencies, and this is where the study’s critical edge lies. The renewable energy sector is built on a supply chain that is strikingly concentrated. Critical minerals—lithium, cobalt, nickel, and the rare earth elements essential for permanent magnets in wind turbines and electric motors—are mined and processed in a handful of countries, and India possesses limited domestic production of most of them. The paper identifies dependence on imported critical minerals as a central vulnerability, one that could substitute a new form of resource insecurity for the old one. Where the twentieth century saw nations compete for oil fields, the twenty-first may see them compete for lithium brines, cobalt concessions, and rare earth processing plants, and India enters that competition as a relative newcomer.

Technological reliance compounds the mineral problem. The study explicitly discusses India’s technological dependence on China, which dominates not only mineral refining but also the manufacturing of solar photovoltaic modules, battery cells, and many of the intermediate components that make up a modern renewable energy system. Even if India installs vast solar capacity, a significant share of the value chain—from polysilicon to wafers to finished panels—runs through factories beyond its borders. This concentration gives an exporting country considerable leverage, whether through pricing, export controls, or simple market dominance, and it means that a disruption in one country’s industrial output could ripple through India’s entire decarbonization schedule. Supply chain vulnerability, the authors argue, is therefore not a peripheral technical detail but a core strategic risk that must be managed alongside the transition itself.

Beyond materials and manufacturing, the paper catalogues a set of governance and security challenges that emerge during the shift itself. Geopolitical competition over clean energy markets and technologies is intensifying, with major powers racing to set standards, capture industries, and secure influence in energy-importing regions. Policy coordination within India presents its own difficulties: energy policy spans central ministries, state governments, regulatory bodies, and public utilities, and aligning their incentives around a coherent transition pathway is a formidable institutional task. The study also flags energy security concerns during the transition phase—a period in which the country must keep the lights on for a growing economy while simultaneously retiring or reducing fossil fuel capacity, scaling up renewables, and building the storage and grid infrastructure that variable generation requires. Managing that balancing act without compromising reliability is arguably the hardest engineering and political problem of the entire endeavor.

What emerges from the analysis is a picture of transition as strategy. The authors argue that India’s clean energy shift is not merely an environmental objective but a geopolitical process shaped by global power dynamics and technological transformation. That framing carries real implications for how the transition should be pursued. If the goal is only emissions reduction, the cheapest and fastest route might involve maximum imports of Chinese panels and batteries. But if the goal is also strategic autonomy, then domestic manufacturing, mineral diversification, technology partnerships, and stockpiling become integral parts of energy policy rather than industrial policy afterthoughts. The study suggests that India’s leaders must weigh these trade-offs explicitly, because decisions made now about supply chains and industrial capacity will determine how much leverage others hold over India’s energy future for decades.

The regional dimension adds another layer of complexity and opportunity. The Indo-Pacific has become the arena where energy, trade, and security interests converge, and India’s renewable expansion positions it to cooperate with neighbors on grid interconnections, green hydrogen trade, and shared technology standards. Such cooperation can anchor India’s role as a provider of clean energy solutions to the developing world, reinforcing the climate leadership the study describes. At the same time, the region is home to intense competition among major powers, and energy infrastructure projects are increasingly viewed through a strategic lens. India’s ability to translate renewable capacity into regional influence will depend on whether it can offer partners reliable technology, financing, and expertise—capabilities that, in turn, depend on resolving the very supply chain and manufacturing vulnerabilities the paper identifies.

Ultimately, the research offers a sober but constructive assessment. India’s transition toward clean energy is portrayed as a genuine transformation of its economic, environmental, and geopolitical landscape—an undertaking comparable in ambition to any in the country’s modern history. The opportunities are substantial: enhanced global standing, stronger strategic partnerships, reduced fossil fuel exposure, and a leadership role in the technologies of the coming century. The risks are equally real: imported mineral dependence, technological reliance on a single dominant supplier, fragile supply chains, and the delicate task of maintaining energy security mid-transition. The study’s central message is that these two sides cannot be separated. How India manages the interplay between decarbonization and geopolitics will shape not only its own future but the broader architecture of global power in an era when the energy systems of nations—and the influence that flows from them—are being rebuilt from the ground up.

Subject of Research: The geopolitical dimensions of India's clean energy transition

Article Title: India’s transition towards clean energy and its emerging geopolitical implications

Article References: Adsul, A. S., Jaybhaye, R. G., & Lad, R. M. (2026). India’s transition towards clean energy and its emerging geopolitical implications. Discover Sustainability. https://doi.org/10.1007/s43621-026-04496-9

Image Credits: AI Generated

DOI: 10.1007/s43621-026-04496-9

Keywords: India, clean energy, geopolitics, renewable energy, energy security, critical minerals, green hydrogen, solar power, supply chains, Indo-Pacific, climate policy, China

The study, conducted by Marzouqa Lamsaf and Mariem Liouaeddine of the Laboratory of Economic and Public Policy Sciences at Ibn Tofail University in Kénitra, Morocco, takes an unusual approach to a sprawling subject. Rather than analyzing energy systems directly, the researchers analyzed the scientific literature itself. They examined 107 documents indexed in the Scopus database, all published between 2010 and 2025, that address Africa’s renewable energy transition. Using two widely adopted bibliometric software packages, VOSviewer and Bibliometrix, they mapped publication trends, identified the most influential works, charted the scientific actors and collaboration networks, and reconstructed the keyword structures that reveal how researchers have framed the problem over fifteen years.

Bibliometric analysis of this kind works by treating publications, citations, and keywords as data points that can be clustered and visualized. When researchers repeatedly cite the same papers or use the same terms, those items group together in network maps, revealing the intellectual architecture of a field. In this case, the analysis surfaced four dominant research clusters. The first, labeled Technological Decarbonization and Energy Systems, covers the engineering and systems-level questions of deploying solar, wind, hydropower, and other renewable technologies across African grids. The second, Green Finance and Economic Development, addresses the capital flows, investment frameworks, and growth strategies needed to fund the transition. The third, Energy Access, Poverty and Security, focuses on the social dimension: who gets electricity, at what cost, and with what reliability. The fourth cluster, Emissions, Efficiency and Socioeconomic Co-benefits, examines how decarbonization policies interact with health, employment, and broader welfare outcomes.

What makes the review’s findings striking is not the existence of these four clusters but the way they interlock. The authors emphasize that the clusters do not represent isolated scholarly silos. Over the study period, the literature has increasingly converged on a trilemma framing, in which economic development, energy access, and decarbonization are treated as jointly necessary and mutually constraining objectives. A solar mini-grid that lifts a rural community out of energy poverty but remains financially unsustainable fails on one axis. A utility-scale wind farm that attracts foreign investment but displaces local communities fails on another. A coal plant that delivers cheap power and industrial growth fails on the climate axis. The research community, the review suggests, has progressively recognized that no single-axis solution will work for a continent with Africa’s specific emissions profile, development needs, and vulnerability to climate impacts.

The asymmetry at the heart of this debate is worth spelling out. Africa’s cumulative and annual contributions to global greenhouse gas emissions are small by any measure, which means the continent’s decarbonization efforts have limited direct effect on global climate trajectories. Yet the stakes of the transition for Africans themselves are enormous. Energy access deficits remain deep, and the continent’s population is growing rapidly, which means electricity demand is set to expand substantially in the coming decades. The path that demand growth takes—whether it is met with renewable capacity, fossil fuels, or some mixture—will shape both African development prospects and the global emissions picture for generations. This is why the review insists that Africa’s transition cannot be read purely as a decarbonization agenda; questions of affordability, reliability, and industrial development are inseparable from it.

The temporal scope of the analysis, 2010 to 2025, captures a period of dramatic change in both the global energy landscape and African energy policy. Over these fifteen years, the cost of solar photovoltaic technology fell dramatically worldwide, off-grid and mini-grid solutions matured, and international climate finance mechanisms expanded. The publication trends identified in the review reflect this evolution, with scholarly attention intensifying as the practical possibilities of renewable deployment in Africa grew. The mapping of influential works and collaboration patterns also reveals which institutions, regions, and research communities have driven the conversation, and where the networks of co-authorship and citation remain thin—a signal of where research capacity and international collaboration may need strengthening.

Beyond mapping the existing literature, the review devotes significant attention to what the literature has missed. The authors identify several persistent gaps. First, the measurement of energy access and renewable energy themselves remains inconsistent across studies, making it difficult to compare findings or aggregate evidence. Different papers use different indicators, thresholds, and data sources for what counts as adequate access or meaningful renewable penetration. Second, financing and governance constraints—the political economy reasons why capital does not flow to promising projects, or why regulatory frameworks fail—are treated unevenly in the literature, often as background context rather than objects of rigorous analysis. Third, the methodological toolkit of the field leans heavily on approaches that identify correlations rather than causal effects, leaving open questions about what actually drives successful transitions.

The fourth gap is perhaps the most consequential for policy. The review finds that energy justice, gender, and digital inclusion remain poorly integrated into transition research. Energy justice as a framework asks who benefits and who bears the burdens of energy systems, and it has gained traction in European and North American scholarship but has been slower to penetrate African energy studies. Gender dimensions matter because women are disproportionately affected by lack of access to clean cooking and because energy entrepreneurship and employment are not gender-neutral. Digital inclusion connects the energy transition to the broader digital economy, since modern energy services increasingly underpin connectivity, education, and financial technology. A transition literature that ignores these dimensions risks producing policies that expand electricity supply while reproducing or deepening existing inequalities.

For researchers, the review functions as both a map and a research agenda. By consolidating fifteen years of scholarship into identifiable clusters and gaps, it gives newcomers an entry point into a fragmented field and signals to funders and journals where new work is most needed. The call for stronger causal methods is particularly pointed: as African governments and international institutions commit to renewable targets, the evidence base for which interventions actually deliver affordable, reliable, low-carbon energy at scale remains thinner than the urgency of the problem demands. Better measurement, more attention to governance and finance, and explicit incorporation of justice and inclusion concerns would, the authors suggest, make the next fifteen years of scholarship far more useful to decision-makers.

The broader significance of the study lies in its reframing. For much of the past decade, international climate discourse has treated Africa primarily as a victim of climate change or as a future emissions problem to be managed. The trilemma framing that this review documents in the literature offers a more accurate and more demanding picture: Africa’s energy transition is simultaneously a development project, an access project, and a decarbonization project, and the scholarly community has increasingly organized itself around that reality. Whether the continent can navigate all three objectives at once will depend not only on technology and capital but on the quality of the evidence guiding policy—a quality that this review suggests still has considerable room to improve. As the literature continues to grow, the challenge will be ensuring that research keeps pace with the real-world decisions being made today about grids, investments, and the lives of the more than half a billion Africans still waiting for modern energy.

Subject of Research: Bibliometric review of research on Africa's renewable energy transition, energy access, and decarbonization

Article Title: Reconciling economic development, energy access, and decarbonization in Africa’s renewable energy transition: a bibliometric review

Article References: Lamsaf, M., & Liouaeddine, M. (2026). Reconciling economic development, energy access, and decarbonization in Africa’s renewable energy transition: a bibliometric review. Discover Sustainability. https://doi.org/10.1007/s43621-026-04805-2

Image Credits: AI Generated

DOI: 10.1007/s43621-026-04805-2

Keywords: renewable energy transition, Africa, energy access, decarbonization, economic development, bibliometric analysis, green finance, energy security, energy justice, energy poverty, Scopus, VOSviewer

The intellectual engine behind the study is what scholars call the renewables pull effect, a concept first introduced by Samadi and colleagues in 2023. The idea is deceptively simple: because renewable electricity is far cheaper in some regions of the world than in others, and because transporting energy itself is expensive, industries that consume enormous quantities of energy may be economically compelled to move their production to where the sun shines and the wind blows hardest. Previous techno-economic modeling had quantified this pull with striking precision. Egerer and colleagues calculated that relocating entire steel value chains to renewable-rich sites could cut costs by up to 19 percent, while for urea the savings could reach 30 percent. Verpoort and colleagues arrived at similar figures, reporting savings of 18 percent for steel and 32 percent for urea. Yet both teams cautioned that cost models alone could not capture the full picture, and that strategic considerations might ultimately determine which parts of a value chain are worth moving.

Colen and Mohnen set out to fill exactly that gap. Their methodology was deliberately qualitative, reflecting the hypothetical and fast-moving nature of green relocation decisions. The researchers conducted two rounds of interviews between January and April 2025, totaling 2,827 minutes of transcribed material. The first round involved 28 European experts, drawn from both renewable-rich and renewable-scarce countries, while the second round gathered perspectives from 32 experts in nearly all non-European regions identified as potential relocation destinations, including Canada, the Middle East, Australia, and parts of Africa and South America. All participants were required to have at least ten years of professional experience in or closely connected to the relevant industries and to be positioned near strategic decision-making processes. The researchers then applied an abductive thematic analysis, deriving 25 first-order codes that were condensed into nine second-order codes, and supplemented the interview data with trade statistics from the World Steel Association and the World Integrated Trade Solution database.

The interviews revealed three powerful global tendencies reshaping green value chains. The first is a sustainable transition that continues but has visibly decelerated. Experts described green projects being cancelled or postponed, particularly in the United States under a revived fossil fuel agenda, while European climate regulation also shows signs of easing. One expert noted bluntly that many current political leaders care only about cheap electricity, not how it is produced. Economic fundamentals compound the slowdown: renewable-based industrial production typically remains more expensive than fossil-based alternatives, and several interviewees observed a shift toward natural gas-based direct reduced iron and blue hydrogen with carbon capture. The second tendency is rising cost pressure, driven by global overcapacities, especially China’s expansion in low-cost steel, and by recession fears in key downstream sectors such as automotive, which had previously been willing to pay a green premium. The third tendency is a growing political ambition for energy and resource independence, with experts reporting that international dependencies are increasingly viewed as strategic risks in the wake of the Russia-Ukraine war and protectionist trade policies.

Against this backdrop, the strategic assessment of relocation scenarios produced a clear verdict. The experts overwhelmingly rejected two options that cost models had treated as plausible: producing green hydrogen locally in renewable-scarce Europe, and importing green hydrogen at scale. Local production fails because of fundamental physical constraints. As one expert put it, there is simply not enough space for sufficient renewable energy installations to cover all future, even growing, demand, and lower capacity factors keep energy prices uncompetitive. Importing hydrogen fails for a different reason: hydrogen’s physical properties make transport so costly that, in the words of one interviewee, the transportation of green hydrogen is, and very likely will always be, too expensive. Long-term subsidies to bridge that gap were judged politically unsustainable, with one expert concluding that taxpayer money per saved job simply cannot be justified in the long term. The recent decision by ArcelorMittal to halt plans for direct reduced iron production in Germany, despite 1.3 billion euros in pledged government support, illustrates how even substantial subsidies cannot offset structural energy-cost disadvantages.

What remains are two scenarios that involve relocating energy-intensive production steps to renewable-rich regions and shipping the products back to Europe. For green steel, the experts favored the shallower option: relocating only iron production, in the form of direct reduced iron or hot-briquetted iron, while retaining steelmaking in Europe. The reasoning is strategic rather than purely economic. Keeping steelmaking close to customers safeguards quality control for high-performance applications, protects proprietary production expertise, and preserves the ability to incorporate recycled steel scrap, a resource several experts expect to become the object of a looming global fight. Political considerations reinforce this choice, since steel’s importance for infrastructure and defense makes governments more likely to subsidize domestic production, and steelmaking employs substantially more workers than iron production. For green urea, by contrast, the balance tilts toward the deeper option of relocating both ammonia and urea production entirely. Urea is a standardized, transportable fertilizer with little need for customization, quality control and intellectual property concerns are weaker, and the cost savings from full relocation are larger. As one expert observed, for politicians, losing steel simply feels emotionally harder than losing chemicals.

From these findings the authors derive a novel value chain positioning model that classifies regions by their position along the value chain, distinguishing upstream, downstream, and full positions, and marking whether regional demand exceeds or falls short of local production. Applied to the global landscape, the model yields a tripartite strategy for European energy-intensive industries: consolidate high-quality downstream production at home, maintain minimal full value chain capacity in renewable-rich European regions such as the Nordics and Iberia, and globally diversify upstream imports through green relocation. Canada emerges as a prime target, offering vast hydropower resources, high-grade iron ore, small domestic demand, and an active search for new markets. The Middle East combines strong renewable potential with financial capability, and Qatar and Saudi Arabia are already developing gas-based direct reduction plants as a bridge to hydrogen, though experts warn that over-reliance could create new dependencies. Most developed countries in Africa and South America offer high potential but require investment, infrastructure, and stability, with Brazil combining high-grade ore and hydropower alongside high energy costs and slow industrial uptake.

Equally revealing is the list of regions the experts consider unattractive. The United States, China, and India are all consolidating toward full value chain positions driven by domestic industrial ambitions, making them unreliable long-term suppliers for European markets. The United States seeks self-sufficiency in steel and urea supported by abundant gas and large scrap availability, while China is expected to become greener but only for its own supply chains, constrained by entrenched blast furnace capacity and limited scrap. India is expanding toward a full position but will likely redirect capacity toward its own growing markets over time. Australia, though rich in renewables and raw materials, faces high costs and geographic proximity that favors Japan and South Korea as natural customers. The experts’ warning is pointed: although there is no Saudi Arabia of renewables, European policymakers must work to prevent the replacement of old energy dependencies with new ones.

The broader implications stretch well beyond steel and fertilizer. The study documents a fundamental tension between the cost-efficiency imperative that governs globally competitive firms and the autarky-resilience ambitions of nation-states, a tension that is likely to shape industrial location decisions across a wide spectrum of sectors. The authors propose three preliminary propositions for future quantitative research: that strategically favorable relocation depth differs systematically by product type, that rising geopolitical volatility causes market access and resilience to override pure cost efficiency, and that upstream-oriented, export-focused regions make more attractive relocation partners than full value chain consolidators. For practitioners, the guidance is concrete: European steelmakers could phase out domestic direct reduction while upgrading electric arc furnace capacity, secure scrap domestically through circular economy models, and pursue hot-briquetted iron imports, while urea producers face relocation to co-located green hydrogen, ammonia, and urea sites abroad as the most viable path absent stronger political intervention. For policymakers, the prescription includes stable climate frameworks, support for shifting uncompetitive upstream plants toward renewable-rich European regions, expanded partnerships through instruments like the EU’s Global Gateway, and harmonized definitions of what counts as green. In an era when, as one expert put it, you cannot trust even your alliances anymore, strategies that preserve optionality, even at higher short-term cost, may prove to be the most valuable asset of all.

Subject of Research: Strategic green relocation of energy-intensive industrial value chains in response to renewable energy resource distribution

Article Title: Strategic considerations for green relocation in energy-intensive global value chains

Article References: Colen, S., & Mohnen, A. (2026). Strategic considerations for green relocation in energy-intensive global value chains. Journal of Industrial Ecology, 30(4), 1951-1969. https://doi.org/10.1007/s44498-026-00133-w

Image Credits: AI Generated

DOI: 10.1007/s44498-026-00133-w

Keywords: green relocation, renewables pull effect, green hydrogen, green steel, direct reduced iron, hot-briquetted iron, green urea, global value chains, industrial ecology, energy-intensive industries, energy security, decarbonization

The motivation behind the index is grounded in hard geopolitical arithmetic. In 2023, 95 percent of the EU’s imports of rare earth elements came from just three countries: China accounted for 46 percent, Russia 28 percent, and Malaysia 20 percent. Energy tells a similar story of exposure and rapid, painful adjustment. The share of natural gas imported from Russia fell from 48 percent in early 2021 to 17 percent by 2025, with the United States now supplying nearly half of the bloc’s liquefied natural gas. Against this backdrop, the European Green Deal, the Circular Economy Action Plan and the Raw Materials Initiative have all reframed circularity not merely as an environmental strategy but as a pillar of what EU policy calls open strategic autonomy — a deliberate balance between global openness and reduced dependency.

What distinguishes the new research from earlier attempts to rank countries on circularity is its conceptual target. Existing composite indices, the authors argue, essentially ask how circular a country’s economy has become, relying heavily on environmental indicators such as recycling rates, resource efficiency and emissions control. The SRI instead measures resilience-enabling capacity: the structural, productive and innovation-related conditions that determine whether an economy can absorb shocks, adapt and transform. To build it, the researchers standardized seven candidate indicators — circular material use rate, energy import dependency, economic globalization, consumption-based greenhouse gas footprint, environmental patents per capita, the UNCTAD Productive Capacities Index, and an energy diversification measure — and applied principal component analysis, a statistical technique that compresses correlated variables into a smaller set of uncorrelated components.

The statistics delivered a strikingly clean result. A single dominant component explained 56.4 percent of the total variance, with all remaining components showing eigenvalues below one, and a factor analysis confirmed the identical structure. Internal consistency, measured by Cronbach’s alpha, reached 0.80, comfortably above the conventional 0.70 threshold. Energy indicators, despite their obvious theoretical relevance, refused to cohere with the rest: across extensive robustness testing that included renewable energy share and energy intensity, their loadings on the first component ranged only from 0.06 to 0.25, compared with 0.35 to 0.54 for the core five indicators. Energy performance, the authors conclude, constitutes an empirically distinct dimension — a separate energy resilience construct — rather than part of the structural capacity captured by the SRI.

The weighting structure of the final index is where the study delivers its headline finding. The formula reads SRI = 0.209·NCMU + 0.251·NEIG − 0.263·NGHGFP + 0.273·NIC + 0.322·NPCI, with the coefficients derived from the data itself rather than assigned by judgment. Productive capacity carries the heaviest weight at 0.322, followed by innovation capacity at 0.273 and economic globalization at 0.251. The circular material use rate contributes positively but modestly at 0.209, while the greenhouse gas footprint enters negatively at −0.263. Innovation and productive capacity also showed the strongest pairwise correlation in the raw data, at r = 0.741. The message is that the technological and industrial base of an economy — not its recycling bin — is currently the strongest statistical companion of sustainable resilience.

Applied across the EU-26, the index reveals a Union split into three tiers along a pronounced north-west to south-east gradient. The high-resilience group comprises the Netherlands, Denmark, Luxembourg, Germany, Belgium, Finland, Ireland and Sweden, with average scores between 62.0 and 87.9 on a rescaled 0–100 range. A broad middle tier, including Estonia, Austria, France, Czechia, Spain, Italy, Poland and Latvia, clusters around the EU-26 average of 45.7. At the bottom sit Portugal, Lithuania, Greece, Slovakia, Croatia, Bulgaria and Romania, with averages from 5.5 to 28.7 — countries where low circularity coexists with weak productive and innovative capacity, a pattern a circularity-only index would misread as a simple recycling gap.

The longitudinal picture is equally revealing. The cross-country standard deviation of SRI scores fell from 26.34 in 2010 to 18.72 in 2022, a decline of nearly 29 percent, signalling partial convergence driven mainly by catch-up among laggards. Croatia posted the largest gain at +18.83 points, followed by Latvia, Romania, Lithuania and Slovakia. Yet the convergence is partly a story of decline at the top: Finland lost 23.88 points and Luxembourg 22.57, with falling innovation capacity — not environmental deterioration — driving the slide in Finland and Denmark. Slovenia’s drop from mid-table to the lower tier was propelled by a sharp erosion of productive capacity, despite improving circularity and emissions performance. The EU-26 average itself barely moved, fluctuating between 43.8 and 47.2 over twelve years.

Perhaps the most compelling validation of the index comes from its response to crises. Using fixed-effects panel regressions with structural break tests, the researchers found statistically significant downward shifts in the SRI only around the two great global shocks of the period: the COVID-19 pandemic, which produced an immediate drop of 4.44 points followed by a recovery trend of 4.72 points per year, and the Russia–Ukraine war, which coincided with a 5.09-point decline. Neither the European debt crisis nor Brexit registered a significant panel-wide break. The index, in other words, appears to measure exactly what it claims: the capacity of economies to withstand systemic, exogenous disruption rather than localized political turbulence.

For policymakers, the implications cut against one-size-fits-all circularity mandates. In Eastern and South-Eastern Europe, the barriers to a circular transition are structural rather than regulatory, and the authors suggest embedding circular economy conditionalities within existing Cohesion Policy instruments such as the European Regional Development Fund and the Just Transition Fund, rather than pursuing separate funding lines. For mid-tier countries with productive capacity but uneven innovation, cross-border initiatives like the Interregional Innovation Investments mechanism could help. For the leaders losing ground, the priority is sustaining innovation intensity through instruments such as Horizon Europe partnerships. The study also points to accelerating the Critical Raw Materials Act and related regulations as the most direct current bridge between circularity and resilience policy.

So is circular the new resilient? The authors’ own answer, delivered with empirical precision, is: not yet, but increasingly so. The circular economy contributes meaningfully to sustainable resilience, and its weight is expected to grow as the EU pushes toward its target of doubling the circular material use rate by 2030 — an ambition whose full effects fall largely beyond the study’s 2022 cutoff. What the evidence demands, the researchers argue, is not a retreat from circular policy but better sequencing: countries lacking the productive and innovation infrastructure to scale circular strategies cannot be expected to harvest resilience gains from recycling targets alone. The Sustainable Resilience Index offers a benchmarking tool for identifying exactly where those enabling conditions are missing — and, as the EU’s resource dependencies tighten, that diagnostic may prove as valuable as the transition itself.

Subject of Research: Measuring the relationship between circular economy performance and sustainable economic resilience across EU member states

Article Title: Is circular the new resilient? Rethinking EU performance through a new sustainable resilience index

Article References: Chovancová, J., & Petruška, I. (2026). Is circular the new resilient? Rethinking EU performance through a new sustainable resilience index. Environmental and Sustainability Indicators, 32, Article 101509. https://doi.org/10.1016/j.indic.2026.101509

Image Credits: AI Generated

DOI: 10.1016/j.indic.2026.101509

Keywords: circular economy, economic resilience, Sustainable Resilience Index, European Union, principal component analysis, innovation capacity, productive capacity, critical raw materials, energy security, composite indicators, EU policy, convergence

The arithmetic of the fuel cycle explains why demand rises so steeply. A single 1-gigawatt light-water reactor consumes approximately 200 to 250 tonnes of natural uranium per year, depending on burn-up and fuel management strategies. Every new large reactor added to the grid therefore locks in decades of fuel purchases, and the current construction pipeline spans continents. Egypt is building four VVER-1200 units at El Dabaa. Bangladesh is completing the two-unit Rooppur plant. The United Arab Emirates’ four-unit Barakah complex, producing around 5.6 gigawatts, is now fully operational. Poland is advancing a Westinghouse-led AP1000 programme, Hungary is continuing Paks-II, the Czech Republic has begun early small modular reactor work with Rolls-Royce at Temelín, and Vietnam, Indonesia, Saudi Arabia, Argentina and Brazil are all expanding or reviving nuclear programmes. South Africa, operator of the continent’s only commercial reactors at Koeberg, is planning new capacity and life extensions.

Two technological trends will shape how this demand materialises. The first is the small modular reactor, or SMR, which promises factory fabrication, lower capital entry barriers and flexible siting. Most SMR concepts still burn low-enriched uranium, so their roll-out would add to, rather than substitute for, conventional uranium demand, while geographically dispersing fuel offtake contracts into many smaller and more frequent agreements. The review treats SMR uptake as a sensitivity rather than a certainty, noting that deployment depends on licensing timelines, the transition from first-of-a-kind to nth-of-a-kind manufacturing, supply-chain maturity and financing competitiveness. Cost reductions are possible but not guaranteed, and the pace of dispersal remains scenario-dependent.

The second trend is the rise of high-assay low-enriched uranium, or HALEU, enriched to between 5 and 20 percent uranium-235, which many advanced reactors and SMRs require to achieve higher burn-up and more compact cores. The review identifies HALEU production as a pivotal bottleneck: meeting projected demand will require significant investment in conversion and enrichment capacity, and the fuel form brings new logistical, regulatory and non-proliferation challenges. A related analysis cited in the study, published in Science in 2024, highlighted the weapons-relevant concerns surrounding HALEU, underscoring why its supply chain will attract intense safeguards scrutiny. Meanwhile, centrifuge technology has already displaced energy-hungry gaseous diffusion for enrichment, and laser-based concepts under pilot study could reshape future capital, regulatory and safeguard frameworks.

Fast reactors and closed fuel cycles offer a longer-term hedge. Fast-spectrum systems operating in a closed cycle can extract many-fold more energy from the same uranium inventory, converting depleted uranium stocks and recycled actinides into fissile material and reducing long-lived radiotoxic waste. If widely deployed later this century, they could substantially lower fresh-uranium mining needs. But the review is careful to treat fast reactors as a separate long-term sensitivity, since commercial deployment faces formidable technical, economic, proliferation-safeguard and institutional hurdles. Fusion, by contrast, is dismissed as a near-term offset: because it relies on the deuterium-tritium cycle rather than uranium, it sits outside the front-end fuel cycle entirely, and authoritative assessments, including the IAEA’s World Fusion Outlook, indicate it is unlikely to materially affect reactor-related uranium demand within the next two decades given the ITER-to-DEMO timeline and unresolved tritium-breeding challenges.

The market picture that emerges is one of tightening supply. Primary mine production has historically ranged between roughly 55,000 and 65,000 tonnes per year, well below the projected requirements of the 2030s and 2040s. Utilities have historically bridged this gap with secondary supply, including commercial inventories, civil stockpiles and re-enrichment of tails, but those buffers are finite. The joint NEA and IAEA Red Book reports identified recoverable resources exceeding 7.9 million tonnes, yet stresses that timely investment in exploration, permitting and processing is needed to prevent shortfalls. New mines typically require many years to move from exploration through permitting to construction, and under-investment in exploration since the 2010s has limited near-term flexibility. The commercial consequence is already visible: utilities are signing longer-term supply contracts rather than chasing spot-market bargains.

Geopolitics adds a further layer of fragility. Many newcomer nuclear programmes are vendor-financed with bundled fuel-supply contracts that channel demand into the vendor’s national fuel cycle. Russia currently controls around 46 percent of global enrichment capacity and roughly 20 percent of conversion capacity, alongside substantial upstream mining interests through joint ventures. The review suggests that scenarios should assume 30 to 50 percent of incremental uranium demand from vendor-financed builds will be met through the vendor’s home-country fuel cycle unless diversification or counter-contracts are negotiated, a structural dependency that recent analyses of European reliance on Russian nuclear fuel services have made uncomfortably concrete.

On the supply side, the review emphasises that uranium deposits are extraordinarily heterogeneous, and that geology dictates both extraction technology and environmental footprint. Canada’s Athabasca Basin hosts the world’s highest-grade ores, at McArthur River and Cigar Lake, where uranium concentrations can exceed 10 to 15 percent, orders of magnitude above typical global deposits, allowing large recoveries from small volumes of rock using specialised freeze-wall and water-jet underground methods. Kazakhstan, Namibia and Australia, by contrast, mine lower-grade but volumetrically vast deposits. Sandstone-hosted roll-front deposits are amenable to in-situ recovery, in which permeable ore horizons are leached underground, avoiding surface disturbance and tailings but imposing strict hydrogeological restoration requirements. Large low-grade open-pit operations such as Husab and Rössing in Namibia, and polymetallic mines like Olympic Dam in Australia, where uranium is a co-product of copper-gold mineralisation, illustrate the economic diversity of the resource base. Because mining energy intensity, water demand and tailings production scale inversely with ore grade, the choice of deposit and method carries direct sustainability consequences.

Exploration technology is also evolving rapidly. Modern campaigns combine classical geological mapping with airborne gamma-ray spectrometry, magnetics, gravity and electromagnetic surveys, followed by radon sampling, borehole logging and confirmatory drilling under IAEA protocols. Machine learning is increasingly used to assimilate radiometric, geochemical and structural datasets into probabilistic mineral-potential maps, improving target ranking, though the review cautions that robust training data, transparent feature selection and geological validation remain prerequisites for reliability. Non-destructive assay techniques such as neutron resonance transmission analysis, which can identify and quantify uranium and other actinides isotope-specifically, support fuel-cycle inventory verification in line with IAEA safeguards practice. A further unconventional option is recovering uranium as a by-product from phosphate rock used in fertiliser production; under favourable conditions this could supply on the order of 10 to 20 percent of global reactor-related demand, with modular recovery plants capable of delivering 4,000 to 8,000 tonnes per year within a few years of commissioning, though scale-up beyond that remains speculative and hinges on fertiliser economics rather than uranium prices alone.

The review’s bottom line is that the nuclear resurgence is fundamentally underpinned by a uranium renaissance. The resource base is judged adequate through mid-century, but only if exploration, mining, conversion, enrichment and HALEU production receive timely investment under strict regulatory oversight, with occupational doses managed under ALARA principles and transparent community engagement. Advances in in-situ recovery, ore-grade modelling and hydrometallurgical processing will be key to minimising environmental impact, while innovation across conversion, enrichment, fabrication and reprocessing will redefine the efficiency and circularity of the fuel cycle. Whether the world’s newly announced reactors get their fuel, in other words, depends less on geology than on decisions being made now about capital, technology and governance, across a supply chain that has spent a decade running on standby.

Subject of Research: Projected global uranium demand trajectories and front-end nuclear fuel-cycle technologies in a renuclearising world

Article Title: Uranium at the nexus of energy security and sustainable development in a renuclearised world: demand trajectories and technological pathways

Article References: Guembou Shouop, C. J. (2026). Uranium at the nexus of energy security and sustainable development in a renuclearised world: demand trajectories and technological pathways. BMC Environmental Science, 3(1), Article 3. https://doi.org/10.1186/s44329-025-00045-3

Image Credits: AI Generated

DOI: 10.1186/s44329-025-00045-3

Keywords: uranium, nuclear energy, nuclear renaissance, small modular reactors, HALEU, fuel cycle, uranium mining, in-situ recovery, energy security, enrichment, fast reactors, sustainable mining