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

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

Growth driven by electrification and digitalisation

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

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

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

Renewables and supply mix evolution

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

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

Grid investment and flexibility imperative

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

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

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

Affordability and reliability challenges

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

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

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

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By Milosz Karpinski, Energy Analyst
Eléonore Carré, Junior Energy Security Analyst

The post Canada set to play a leading role in supplying the world with responsibly produced critical minerals appeared first on Thoughtful Journalism About Energy's Future.

By Alessio Scanziani, Energy Security Analyst
Shobhan Dhir, Critical Minerals Analyst
Mari Nishiumi, Consultant
Kentaro Miwa, Consultant
Tae-Yoon Kim, Head of Critical Minerals Division

Share of top refining country for energy-related strategic minerals, 2024

Stepping up global action on critical minerals security has never been more urgent. A clear priority is to develop diversified sources of supply for key critical minerals. However, inevitably, it takes time to develop new projects in both mining and refining. Strategic stockpiling of critical minerals can serve as an important protective measure to safeguard countries from supply shocks and disruptions while they develop new, diversified sources of supply. Strategic stockpiles provide a way for countries to strengthen economic and national security, while also helping to deter future export controls and limiting their impact.

Strategic stocks are an insurance policy against short-term disruptions

Strategic stocks – held specifically for emergency purposes with the involvement of the government – have demonstrated effectiveness across various sectors. A notable example is the oil market, where stockpiles have played an important role in mitigating severe economic impacts for decades. After the oil shock of 1973, IEA member governments established a mechanism to build up and pool emergency oil stocks to protect them from being held to ransom via oil supplies in the future. Since then, the IEA has coordinated five collective responses to major oil supply disruptions, helping to limit the economic impacts of shocks caused by natural disasters or geopolitical strife, most recently in 2022 following Russia’s invasion of Ukraine.

Critical mineral markets operate in a very different context from oil markets. The diversity of critical minerals, each with distinct market contexts, means that stockpiling is not a catch-all solution and its suitability can vary by mineral. It is also not a substitute for efforts to develop diversified supply sources that deliver fundamental security benefits. However, stockpiles can still play an important role in providing emergency supply and protecting industries and jobs. Strategic mineral stockpiles also bring several additional benefits. Even when they are not used, they send a signal to markets that sudden supply shocks or export restrictions need not immediately cripple the system. Some IEA Member countries such as Japan, Korea, and the United States hold strategic stockpiles of critical minerals that have protected industries from supply disruptions.

The build-up of critical minerals stockpiles and the need for stock rotation can also support diversification efforts by sourcing materials from projects outside the dominant suppliers, while also enhancing market transparency by providing governments with insights into pricing.

Strategic stockpiles should primarily serve to ensure business continuity and provide a buffer during supply disruptions, rather than to manage price volatility or influence market dynamics. Clear and transparent principles for stockpile releases, focused on addressing acute and short-term supply interruptions, can help prevent market distortion and maintain healthy investment signals that drive market development.

Designing effective stockpiling systems involves addressing a range of strategic questions including material form, governance model, costs, and financing

Amid mounting risks to mineral supply chains, many countries are showing growing interest in establishing stockpiling systems for critical minerals. In doing so, they need to address a range of strategic questions, including the choice of materials to stockpile, governance models, associated costs and financing mechanisms. Critical minerals vary widely in their physical forms, end-use sectors, market sizes, levels of pricing transparency, warehousing needs, and supply chain complexity. Each material therefore needs to be analysed individually, with stockpiling governance models tailored to its specific characteristics.

As part of the Critical Minerals Security Programme, the IEA has examined these issues in detail and developed a comprehensive database and model covering over 30 forms of strategic minerals that are used in the energy sector and have critical applications in AI, advanced technology, aerospace, and defence. This work involved developing an assessment framework to evaluate the supply and strategic risks for each material across multiple dimensions, exploring potential governance models, understanding warehousing requirements posed by the diverse forms that minerals take along their value chains, building cost models to estimate the expenses associated with stockpiling and examining possible financing mechanisms.

The IEA Critical Minerals Stockpiling Assessment Framework evaluates risks and warehousing needs

To determine which materials should be prioritised for stockpiling, the IEA Critical Minerals Stockpiling Assessment Framework was developed to analyse risks and challenges for each material across multiple dimensions: supply risk, the availability of alternative supply routes, strategic importance and the feasibility of stockpiling.

Criteria for determining materials for stockpiling under the IEA Critical Minerals Stockpiling Assessment Framework

When evaluating supply risks, the level of supply concentration in both mining and refining is a key factor, as relying on few dominant suppliers means that any disruption can immediately flip markets into shortfall. For gallium, graphite, manganese and rare earths, the top refiner, China, accounts for over 90% of global supply. High price volatility further complicates the development of new supply: for example, lithium, vanadium, rare earths and cobalt have exhibited much higher volatility than oil and gas. Many high-risk minerals are already affected by some form of export restrictions, such as rare earths, gallium, and tungsten, straining their supply chain. These restrictions highlight the supply risks but also indicate the procurement challenges of building strategic stocks for these materials.

The availability of alternative supply routes is another important consideration. For some materials, there are limited options for substitute materials, such as chromium for stainless steel, titanium for alloys requiring a high strength-to-weight ratio, and germanium for high-performance fibre optics, heightening the risks from supply disruptions. Additionally, many materials are produced as co- or by-products alongside other minerals, making their supply less responsive to demand or price signals. For example, gallium is mainly recovered as a by-product of zinc and aluminium production, tellurium from copper and lead, and germanium from zinc and coal.

The strategic importance of each material depends on the sectors in which it is used. When materials have applications in strategic sectors such as semiconductors or defence, their security of supply becomes a crucial factor for economic and national security. While strategic importance can be assessed at the global level, each country should also consider domestic vulnerabilities and dependencies to assess potential impacts on its overall security and resilience.

The feasibility of stockpiling varies by material as each mineral takes different forms along its supply chain. The form most suitable for stockpiling is generally the imported form – most exposed to disruption risks – that can be directly used domestically in case of a disruption, without the need for further processing abroad. A broad assessment of the properties of strategic materials that are imported by IEA Member countries highlights a number of warehousing challenges for certain critical minerals such as hygroscopicity (sensitivity to humidity), reactivity, hazardousness and fragility. For example, lithium hydroxide is highly sensitive to humidity and degrades quickly in air, reducing its shelf life to around six months, while lithium carbonate can be stored for much longer. Gallium has a melting point of around 30°C. These warehousing challenges can be overcome, for example through controlling temperature and humidity of warehouses, using advanced packaging to minimise contact with air and moisture, and rotating stocks of materials with short shelf life. However, these additional requirements increase the cost and complexity of stockpiling.

Assessment of stockpiling warehousing requirements for selected strategic minerals

Stockpiling governance models balance roles between government and industry

There is a spectrum of stockpiling governance models, with suitability varying by country and material. Governance models can be grouped into two broad categories based on where the minerals are physically stored: ‘government-held’ or ‘industry-held’, each with two main options. For government-held (centralised) stockpiling models, the government owns and manages the stockpile, either directly or through a public agency acting on its behalf. Industry-held (decentralised) models require companies to store strategic stocks in addition to their existing commercial inventories. For industry-held stockpiles, stocks may be industry-owned, where the government sets a mandate for a volume to be reserved for emergency use, or government-owned, where industry manages the stocks which are owned and purchased by the government. Companies that participate in these models may receive public support. Governments could also consider leveraging the expertise and assets of commodity traders to manage stockpiles more efficiently.

Most existing strategic critical mineral stockpiling systems are government-held and managed through public agencies. Japan’s mineral stockpiles are managed by its public agency; Japan Organization for Metals and Energy Security (JOGMEC), Korea’s stockpiles are handled through the Korea Mine Rehabilitation and Mineral Resources Corporation (KOMIR) and the Public Procurement Service (PPS), and the United States’ National Defence Stockpile is managed by the Defence Logistics Agency (DLA). China also has major stockpiles of critical minerals, but unlike the others, utilises a combination of governance models with material stored and managed by both government and industry.

Operating costs underpin total stockpiling costs, with financing, warehousing, and discounting as the largest components

The costs of stockpiling are comprised of two primary components: the material purchase cost and the operating cost. The material purchase cost is the significantly larger upfront expense; however, this is a capital cost that is converted into an asset (the stockpile), and the capital is recuperated when stocks are released or during stock rotation (when selling the stock back to the market before reaching the end of their shelf life). The net costs of stockpiling are therefore determined by the operating costs. Stockpiling costs are sometimes misconstrued with an overemphasis on the material purchase cost, whereas operating costs form the actual costs borne over time. The operating cost components include financing, warehousing, discount, logistics, material loss and administrative costs. Financing costs refer to the cost of using debt or equity to purchase the material, warehousing refers to the cost of storing the material, and discount costs reflect the loss in market value when selling the stockpiled material to the market after a period of storage.

Our analysis indicates that financing, warehousing, and discount account for the largest share of total stockpiling operating costs, but there are major differences in the share of each component by material. Financing costs are the largest cost component for high-value, lower volume materials such as gallium and germanium, while warehousing costs become more significant for larger volume, lower-value materials such as synthetic graphite and nickel sulphate. Stricter warehousing requirements can triple warehousing costs per tonne compared with standard metals; however, financing costs remain dominant for many materials, even those with the strictest storage requirements such as lithium hydroxide and rare earth permanent magnets. Materials with shorter shelf lives incur more significant discount costs under government-held models due to more frequent stock rotation. Industry-held governance models reduce these discounts as companies use the stocks directly rather than needing to sell them back to the market.

Stockpiling critical minerals entails relatively modest costs compared with the potential economic impacts of supply disruptions

Analysis of stockpiling costs at the aggregate IEA level indicates that the total net cost of stockpiling most critical minerals is relatively modest, particularly for many high-priority strategic materials such as gallium and germanium, which often involve low volumes. According to our analysis, for all IEA countries to stockpile six months of their exposed imports of gallium metal from the top supplier, the total operating costs of stockpiling would be around USD 800 000. By comparison, costs of stockpiling the same months of exposed imports of rare earth permanent magnets would be almost USD 90 million. For material used in much larger volumes such as lithium hydroxide, the costs only grow to just under USD 300 million.

Government-owned governance models have lower financing costs while industry-led models have lower discount costs and greater efficiencies

The appropriate stockpiling governance model varies considerably by material and depending on domestic context and supply chain structures. Government-owned operating models with access to lower interest rates are most cost efficient for high-value materials, such as gallium or germanium. Lower-volume materials with fewer specifications such as upstream concentrates or midstream rare earth oxides may be more suitable for centralised government-led models, if there are domestic facilities able to process them. However, materials with a wide variety of company-specific specifications, such as graphite anode material or rare earth permanent magnets, or with short shelf lives, such as lithium hydroxide, are often better suited to industry-held governance models, where companies can store the specific materials, they need and undergo stock rotation more efficiently. Government-owned, industry-held governance models combine some of the advantages of both models: reduced financing costs, greater logistical efficiencies and reduced discount costs.

Beyond material characteristics and cost considerations, stockpiling can also support the development of diversified projects. Government-led stockpiling operating models are better suited to procuring material from specific strategic projects, providing offtakes that enhance project viability. In industry-led models, it is harder to control where material is purchased from, but the government could still have a role in aggregating demand. Ultimately, the most suitable stockpiling governance model depends strongly on national circumstances. A hybrid solution using a mixture of governance models for different materials may be optimal for many countries.

There are multiple ways to finance strategic stockpiling, which depend on the governance model and domestic circumstances

In the case of direct management of government-held stocks, purchase and operational costs are typically financed directly from the general budget or through a special purpose fund. In case the government chooses to use a public agency to manage the stocks, it can provide loan guarantee for the initial stock purchase and cover the agency’s operational costs. In an industry-held model, most of the costs are borne by companies, but governments could contribute through several instruments, such as direct loans or loan guarantees, public subsidies, tax breaks or direct equity investments. In the government-owned, industry-held hybrid model, the government would typically cover purchasing and financing costs, while operating costs could be shared through an agreement between government and industry.

The IEA Critical Minerals Security Programme is a key platform for international cooperation on critical minerals stockpiling

The urgency of today’s challenges facing critical mineral supply chains calls for strong international collaboration to achieve greater economic and national security, and stockpiling is a key tool that countries are considering implementing or expanding. While the objective of stockpiles is to strengthen security of domestic supply, coordination with international partners can be beneficial to achieve greater security more efficiently and faster. Coordination on the timing for stockpile purchases and principles for releases could help ensure markets are not distorted. When procuring stocks, countries could also agree to support strategic projects that would increase global diversification or consider aggregating demand. When compatible with domestic policies, countries could also consider to co-locate stocks for greater efficiencies, especially for low-volume materials, or reserve production in countries with production infrastructure to be dedicated to emergency use. Close dialogue among partners also helps transferring knowledge on efficient stockpile management.

The IEA Critical Minerals Security Programme is a key international platform helping countries to explore strategic questions around developing domestic stockpiling systems and opportunities to strengthen international coordination. The Programme will continue to support IEA Members in their efforts on reviewing strategic stockpiling as a tool to enhance preparedness to supply shocks.

Seven recommendations for developing domestic strategic stockpiles of critical minerals

When developing or expanding domestic strategic stockpiles of critical minerals, governments should consider:

1. Assessing value chains to identify bottlenecks and determine the material portfolio, prioritising those materials with the highest supply risks for a specific country or region.
2. Stockpiling the form of the material imported to a country or region to enable rapid deployment during disruptions.
3. Preparing for potential future disruptions by considering materials exposed to major risks that are not yet subject to export restrictions.
4. Tailoring the stockpiling governance model to the materials of choice, for an overall stockpiling system that optimises cost and benefits.
5. Setting clear transparent principles for stockpile releases to respond to acute short-term supply disruptions, while maintaining robust investment signals for market development.
6. Closely involving industry across upstream and downstream sectors to design feasible and effective stockpiling systems and ensure their operational viability.
7. When compatible with domestic policies, leveraging international collaboration to optimise multiple domestic systems for greater efficiencies.

 

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By Fatih Birol, Executive Director

The post 7 certainties about energy for this age of uncertainty appeared first on Thoughtful Journalism About Energy's Future.

By Rebecca Schulz, Senior Oil Market Analyst
Martina Lyons, Energy Analyst
Deniz Ugur, Consultant
Simon Bennett, Energy Technology Analyst
Courtney Turich, Energy Analyst

Geothermal energy harnesses naturally occurring heat found beneath the Earth’s surface to provide heating and cooling, electricity and energy storage. As global electricity demand rises and power systems place a growing premium on firm supply, geothermal energy’s ability to provide an around-the-clock, low-emissions source of power is attracting renewed attention. However, easy-to-access conventional geothermal resources are relatively rare and mostly confined to a small number of shallow geothermal hotspots globally, accounting for only about 1 per cent of global electricity demand today.

Next-generation geothermal technology developers are seeking to overcome these limits by drilling deeper and harnessing heat from hard-to-reach reservoirs. Operators can either circulate fluid through fractures that have been induced (through what is known as enhanced geothermal systems) or transfer heat to the surface through closed-loop circuits. These technologies are advancing quickly, potentially enabling economically-viable geothermal development nearly anywhere in the world. The IEA’s Future of Geothermal Energy report, published in late 2024, estimated that with continued technology improvements and reductions in project costs, next-generation geothermal could meet up to 15 per cent of global electricity demand growth to 2050.

Next-generation geothermal technology remains at an early stage of development. In general, geothermal projects remain among the most capital-intensive in the energy sector, with drilling and well costs often representing up to 80 per cent of total costs. Yet the past year has seen notable progress. Once considered prohibitively expensive, next-generation projects are now demonstrating measurable efficiency gains and more competitive drilling costs amid ongoing innovation, building investor confidence. These advances – arriving just as global electricity demand surges – have helped boost fundraising. Meanwhile, new supply agreements with data centre operators, along with the prospect of geothermal projects co-producing critical minerals such as lithium, are adding to the momentum.

Investment in next-generation geothermal has risen sharply

According to IEA analysis of new data – including exclusive data shared by Underground Ventures, a firm that invests in next-generation geothermal – financing for the sector reached nearly USD 2.2 billion in 2025, an 80 per cent increase year-over-year and up from just USD 22 million in 2018.

Mature conventional geothermal attracted strong investment as well. Funding for conventional geothermal power projects reached nearly USD 5 billion in 2025 – a four-fold increase from 2018 – while geothermal heating projects, such as those used for district heating, secured over USD 11.5 billion in 2025 alone.

In another sign of growing investor confidence in the sector, the global share of equity financing declined from 70 per cent between 2018 and 2020 to just over half between 2023 and 2025, as companies were increasingly able to secure debt alongside data centre power and critical mineral supply agreements. Debt-based financing now accounts for nearly 30 per cent, with financing terms expected to improve further as risks continue to fall.

While public funding is essential to incubate and reduce the financial risks of next-generation technologies, overall, its relative share in total financing is relatively low. Publicly-sourced grants are currently about 9 per cent of next-generation funding globally, down from 12 per cent between 2018 and 2020. The United States leads in the number of grants awarded, though the European Union provides the largest share of total public funding by value.

The crossover of oil and gas technologies and engineering advances continue to drive progress

The increase in financing has been underpinned by rapid technological progress, with new innovations and knowledge from other parts of the energy sector helping next-generation geothermal projects move closer to commercialisation. Recent advances in subsurface engineering – many of them driven by techniques pioneered in the shale oil industry – have been particularly important, helping to accelerate project development and reduce costs.

The US Department of Energy’s Utah Frontier Observatory for Research in Geothermal Energy (FORGE) has showcased the benefits of knowledge sharing from the oil and gas sector. FORGE drilled its first wells in 2021, and by 2024 had successfully demonstrated enhanced geothermal systems in practice, nearly doubling previous drilling rates from 8 meters per hour (m/h) to almost 15 m/h, with peak rates reaching nearly 26 m/h. FORGE collaborator Fervo, a US enhanced geothermal company that raised over USD 1 billion between 2022 and 2025, has achieved drilling rates of 30 m/h. Several companies have now demonstrated similar performance, including Mazama Energy’s recent high-temperature well construction demonstration at its 15 megawatt (MW) enhanced geothermal pilot in the US state of Oregon.

Resurgent demand for firm power, especially from data centres, is driving interest in geothermal

As technological advancements continue, geothermal’s ability to deliver reliable, around-the-clock baseload power is drawing growing interest. This is proving particularly attractive to the data centre industry, whose global electricity consumption is set to surge by more than 300% by the end of this decade – creating a group of  long-term paying customers that are helping push financing to new levels.

Geothermal projects, whether producing heat or electricity, usually sell their output through long-term contracts. These include heat purchase agreements or power purchase agreements with utilities or industrial customers, which provide stable income to facilitate debt financing. Until 2023, most next-generation geothermal project developers could only secure electricity price guarantees equivalent to solar and wind projects, or about USD 30-60 per megawatt-hour. But as electricity demand grows strongly in major markets – including in the United States, where data centres are helping lift power consumption for the first time in two decades – geothermal developers have begun securing significantly higher contract prices, in some cases reaching about USD 130 per megawatt-hour.

In 2024, Google and NV Energy signed a power purchase agreement for electricity from Fervo’s 115 MW Corsac project, while Meta committed to sourcing 150 MW from Sage Geosystems starting in 2027. This shows that companies are willing to pay a premium for clean, dependable power that can operate continuously, even for the first projects that may have the highest unit costs.

Critical material supply chains offer extra revenue potential

Efforts to build out critical mineral supply are also giving next-generation geothermal a lift. Geothermal energy projects can serve as a source of lithium, demand for which is expected to grow strongly in the next decade under all IEA scenarios.

Lithium that is dissolved in geothermal brine can be obtained via a direct extraction method. This process has the potential to require less water, land and energy use than traditional hard-rock mining, while providing developers with an additional source of revenue.

Geothermal projects currently under development in the European Union and the United States could yield 47 kilotonnes of lithium per year by 2035, which would meet 5 per cent of global demand based on today’s policy settings. Vulcan Energy’s Phase 1 Lionheart project in Germany, which fully secured financing in 2025, not only has offtake agreements with local district heating and industry consumers for power and heat, but also with Glencore, Stellantis, LG Corp and Umicore for lithium. Similar integrated geothermal‑lithium developments are actively underway across Europe and the United States, demonstrating the potential for this model to bolster growth.

Policy support remains crucial for next-generation geothermal to bridge from promising pilots to large-scale deployment

Recent advancements in next-generation geothermal are promising and the potential they open is enormous, particularly as global electricity demand continues to grow. Combining new drilling and materials technologies with real-time downhole sensor data has cut well costs by up to 30 per cent and may extend asset lifetimes beyond 25 years. Further cost reductions are anticipated as developers gain experience through construction and operations and as multiple players continue to compete.

Even so, large-scale geothermal projects face major challenges that could stymie future progress. These include exploration and upfront financial risks, as well as those related to execution. In general, next-generation geothermal projects remain too big for venture capitalists alone and too risky for established corporate energy players. This “missing middle” – also known as the “the technology valley of death” – is where governments traditionally step in. While some energy customers, primarily data centres, are now willing to pay a premium to see if the technology can work at scale, this demand alone appears insufficient to move the technology towards widespread commercialisation.

Given this backdrop, government support remains vital to the sector’s ongoing development. By setting targets and roadmaps that raise awareness, pursuing permitting reform, implementing risk-mitigation schemes, and ensuring power-market designs that make it easier to sell on the electricity produced directly to offtakers, they can help next-generation geothermal move through this “technology valley of death.” Encouraging examples include the US Department of Energy’s geothermal R&D funding, Germany’s new accelerated permitting law combined with drilling risk-insurance, and risk-mitigation facilities in the Philippines, Germany and East Africa. The EU’s forthcoming Geothermal Action Plan is another welcome step towards giving geothermal the dedicated policy attention it has long lacked, and can realise its full potential only by covering both conventional and next-generation geothermal technologies.

Delivering on the promise of next-generation geothermal everywhere will also require economic conditions that make projects both viable and scalable, alongside supportive policies, strong market design and investment incentives. Additionally, growth in the sector – especially growth that supports new demand sectors and sparks fresh innovation – will be amplified if companies can share their learnings through government programs or industry organisations, such as Geothermal Rising, Project InnerSpace, Clean Air Task Force Superhot Rock Initiative and the European Geothermal Energy Council.

The IEA will continue to provide data and analysis to support these efforts, including through a forthcoming publicly accessible global database on geothermal projects. This will provide comprehensive, up-to-date tracking of conventional and next-generation geothermal, alongside the broader assessment of progress via the Races to First data tool.

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In its most recent assessment, the IEA estimates that coal demand in 2025 will hit an all-time high of roughly 8.85 billion tonnes, a modest 0.5 per cent increase from 2024 levels. But looking ahead, worldwide coal consumption is projected to plateau through the remainder of the decade and edge modestly downward by 2030 as cleaner energy sources gain market share and emissions policies take hold.

“Looking ahead, we observe that global coal demand plateaus and will start a very slow and gradual decline through the end of the decade,” IEA Director of Energy Markets and Security Keisuke Sadamori said in a press briefing accompanying the report. Coal remains the largest single fuel for electricity generation, making its evolution critical for climate and energy planning.

The analysis shows a nuanced global landscape. China — the world’s largest coal consumer, accounting for more than a third of global use — saw demand roughly flat in 2025 and is expected to see only a slight decline toward 2030 as renewable capacity expands. Smaller declines in advanced economies such as the European Union and the United States contribute to the broader stabilisation and eventual downturn trend.

In contrast, parts of South and Southeast Asia continue to register robust coal consumption tied to rising electricity demand and industrial growth. Regions including Indonesia and Viet Nam are forecast to experience growing coal use as energy demand surges and renewable deployment lags behind.

Meteorological factors played a notable role in mid-year demand patterns. In China and India, weaker electricity demand growth through early 2025 and stronger hydropower output temporarily reduced coal use, while in the United States and European Union, increased coal generation reflected a rebound tied to higher natural-gas prices and subdued wind and hydro output.

The IEA’s forecast deviates from earlier expectations of continued growth. A mid-year update indicated that global coal demand in some scenarios may decline slightly in 2026, bringing consumption close to 2024 levels before longer-term declines set in.

However, analysts and industry watchers caution that the picture is not uniform. A Bloomberg analysis underscored that whether global coal demand has truly peaked depends heavily on developments in China, where electricity growth and renewable integration rates will remain central to shaping future coal consumption trends.

The IEA’s findings come as coal faces intensifying competition from renewables, natural gas and nuclear power. Technologies such as solar and wind are expanding rapidly, pushing down the share of coal in electricity mix in many advanced economies. Renewables contributed a significant portion of energy supply growth in 2024, further eroding coal’s dominance.

The plateau in coal demand also has implications for global emissions targets. Coal combustion remains a major source of carbon dioxide emissions, and a sustained decline — even gradual — is seen as a critical element of long-range climate strategies outlined under the Paris Agreement.

Still, the IEA emphasises that variations in policy, economic growth rates and energy demand could alter the trajectory. If countries accelerate clean energy deployment beyond current policies, coal’s decline could be faster; conversely, slower renewable adoption might sustain higher coal use longer than forecast.

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The IEA estimates that more than 115 billion tonnes of raw materials linked to fossil fuel production and critical mineral supply were extracted worldwide in 2024. Coal mining accounted for more than half of the total, reflecting the material-intensive nature of coal extraction and its continued role in the global energy mix.

However, the agency’s analysis shows that only a fraction of the material extracted ultimately becomes usable energy products. Of the more than 115 billion tonnes removed from the ground last year, approximately 17 billion tonnes ended up as fuels or refined materials used in the energy system. The remainder consisted largely of rock, water, mud and other residues generated during extraction and processing.

Coal production remains the largest driver of material extraction in the energy system. The IEA estimates that for every tonne of coal produced, around seven tonnes of material—primarily rock and water—are excavated. This high ratio reflects the scale of overburden removal and waste handling required in surface and underground coal mining.

Oil production is also material-intensive. Producing one tonne of oil typically involves extracting nearly six tonnes of water and other byproducts, including drilling fluids and associated waste. These figures underscore the physical demands of conventional oil extraction, as well as the environmental management challenges associated with produced water and waste streams.

By comparison, natural gas extraction generally requires significantly less material movement. According to the IEA, less than one tonne of water and drilling waste is typically extracted for each tonne of natural gas produced. The lower material footprint partly explains why gas has often been viewed as less resource-intensive than other fossil fuels, although it still carries climate and environmental impacts.

While fossil fuels dominate total material extraction, the IEA analysis draws attention to the disproportionate material footprint of critical minerals used in clean energy technologies. Minerals such as lithium, nickel, cobalt and copper are essential for electric vehicles, power grids, wind turbines and solar panels, but their extraction involves large volumes of waste relative to the amount of usable material produced.

On average, producing one tonne of usable critical minerals requires digging up and processing more than 100 tonnes of material, according to the report. This reflects low ore grades, complex geology and the extensive processing required to separate valuable minerals from surrounding rock.

Despite their high waste-to-product ratios, critical minerals currently represent a relatively small share of total material extraction compared with coal and oil. However, their importance is expected to grow as energy systems electrify and expand renewable generation.

The IEA’s World Energy Outlook 2025 explores several scenarios for the future of the global energy system, including pathways that align with existing government policies and more ambitious trajectories aimed at limiting global warming.

Across all scenarios, the agency finds that raw material extraction for energy products declines by mid-century, driven largely by reductions in coal mining. As coal use falls in power generation and industry, the associated material footprint declines substantially, outweighing increases linked to critical minerals.

The reduction in material extraction is most pronounced in the scenario where the world achieves net-zero emissions from the energy sector by 2050. In that pathway, steep declines in coal demand are combined with reduced oil consumption and improvements in efficiency, recycling and material use across the energy system.

Although demand for critical minerals rises significantly in net-zero scenarios, the IEA notes that the overall material footprint still falls because fossil fuel extraction—particularly coal—accounts for such a large share of today’s material flows.

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The report, Electricity Market Design: Building on strengths, addressing gaps, released today, examines the performance of market structures across Europe, the United States, Japan and Australia and identifies reforms needed to maintain secure, affordable and sustainable electricity supply.

According to the IEA, well-functioning electricity markets are a critical tool for balancing supply and demand, coordinating day-to-day operations and signalling when and where new investment is needed. As electricity systems undergo rapid transformation — driven by rising power demand, increased electrification and large growth in variable renewable energy — the agency says effective market design will play an increasingly central role in supporting system reliability and policy objectives.

Short-term markets performing well despite growing system complexity

The report finds that short-term electricity markets, including day-ahead, intraday and real-time markets, have continued to operate effectively even as the systems they manage have become more complex. Across the regions analysed, electricity was supplied securely more than 99.9 per cent of the time over the past five years.

Short-term markets have been successful in maintaining reliable dispatch, enabling efficient scheduling and supporting transparent price formation. They also accommodate a wide range of technologies and participants. In Europe, the IEA notes, the day-ahead market processes more than 400,000 bids every hour, submitted by thousands of registered market actors — one of the most detailed and high-volume power-market operations in the world.

Despite these strengths, the report says short-term markets must evolve to keep pace with the rapid introduction of new technologies and shifting operational patterns. As more distributed energy resources, flexible demand, storage and variable renewables enter the system, market designs will need greater temporal and locational granularity and improved access for smaller or distributed participants. These changes, according to the IEA, will help ensure that price signals better reflect real-time system needs.

Long-term markets lag behind investment needs

While short-term markets remain effective, the report identifies substantial weaknesses in long-term electricity markets. In most regions assessed, liquidity is low and trading volumes are limited. Forward and futures markets see the majority of activity within two years of electricity delivery — far shorter than the time horizons required for financing large capital-intensive energy projects, which often need stable revenue expectations 10 to 30 years into the future.

The lack of long-term market depth reduces the ability of investors and utilities to manage price risk and secure financing for new generation capacity, energy storage, grid infrastructure and electrification projects. The IEA finds that this gap undermines the investment conditions needed to meet future electricity-system demands and achieve long-term policy goals. Market participants, the agency reports, would benefit from reforms aimed at extending contract duration, improving liquidity and widening access to long-term hedging tools.

Complementary mechanisms are important but must be well designed

To compensate for limitations in long-term markets, many jurisdictions have introduced complementary policy mechanisms. These include capacity remuneration schemes, renewable-energy support programmes and other tools designed to advance investment, maintain essential dispatchable capacity and support emissions-reduction goals.

The IEA notes that these mechanisms have become structural components of electricity markets in Europe, parts of the United States, Japan and Australia. They have played an important role in ensuring system adequacy, bringing forward new low-emissions generation and retaining flexible resources that may run less frequently as renewable energy grows but remain necessary for reliability.

However, the report cautions that complementary mechanisms must be carefully designed. In some jurisdictions, design flaws have led to inefficiencies or higher system costs. The IEA stresses that these mechanisms must be coherent with — rather than contradictory to — wholesale market signals to avoid distortions and ensure efficient outcomes.

Holistic market design needed to support the electricity transition

The IEA’s overarching conclusion is that electricity-market design must be treated holistically rather than through piecemeal updates. Because markets now operate alongside major policy instruments, grid constraints, distributed resources, digital technologies and new forms of flexibility, coordinated reforms are needed to maintain investor confidence and support smooth implementation.

The report emphasises three priority areas for reform:

1. Preserving and refining short-term market strengths, particularly by increasing their ability to incorporate variable renewables, distributed resources and flexibility needs.

2. Strengthening long-term market frameworks to provide durable investment signals and accessible risk-management tools.

3. Aligning complementary mechanisms with wholesale-market outcomes to ensure policy goals are met without reducing market efficiency or raising costs unnecessarily.

The IEA also stresses the importance of transparency and predictability in reform processes. Clear and consistent policy frameworks, the agency says, will help build stakeholder confidence and ensure markets can support the rapid transformation now underway in global electricity systems.

Next steps and broader context

The release of this report comes as countries worldwide scale up efforts to decarbonise their electricity systems, electrify transport and heating and expand renewable-energy deployment. The IEA notes that rising power demand, increasing system complexity and high investment needs make strong market design increasingly important.

As electricity becomes the backbone of the energy transition, the report argues, market frameworks must evolve to maintain secure, affordable and sustainable power supplies.

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According to a new report by the International Energy Agency (IEA), global primary energy intensity — the amount of energy required per unit of economic output — is expected to improve by roughly 1.8 per cent in 2025, up from about 1 per cent in 2024. The jump suggests policymakers and industry are beginning to make headway. Still, the IEA warns that this rate remains well below the roughly 4 per cent annual improvement required to double energy-efficiency progress by 2030, a goal set at COP28.

The report notes that although more than 250 new policy measures were introduced in 2025 alone, sluggish progress in sectors such as industry and buildings threatens to drag down the overall outcome. The industrial sector’s energy-intensity improvement rate has reportedly fallen to under 0.5 per cent per year, compared with nearly 2 per cent in the previous decade.

Meanwhile, the International Renewable Energy Agency (IRENA) highlights a parallel challenge: despite setting new records for renewable-energy capacity additions in 2024 — 582 GW globally — the world remains off-track to hit the target of tripling renewable capacity to 11.2 TW by 2030. Equally concerning, efficiency gains remain modest: global energy intensity improved by just 1 per cent in 2024, far behind the 4 per cent-year-on-year improvement required.

Why improvement matters

Energy efficiency is a vital lever: it lowers consumption, reduces emissions, and improves energy affordability. If economies can use less energy to generate the same output, the benefits ripple across security, competitiveness and climate goals. The IEA underscores that “the power to enhance people’s lives and livelihoods through greater energy security, more affordable bills, improved economic competitiveness and lower emissions” lies in boosting efficiency.

In practice, though, rising energy demand is working against efficiency gains. IEA data show that global energy demand grew by 2.2 per cent in 2024 — faster than both the longer-term average (~1.3 per cent) and the rate of efficiency improvement. As a result, the system still becomes more energy-intensive overall.

Where progress is uneven

Some policy progress is visible. The IEA tracked over 250 new policy actions in 2025 aimed at boosting efficiency. Efficiency in emerging economies such as China and India also shows modest upticks as they invest in efficiency standards and technologies.

But headwinds remain:

• In the industrial sector — responsible for roughly two-thirds of global final energy-demand growth since 2019 — energy-intensity improvements have fallen sharply.

• Buildings and cooling represent major gaps. Many new air-conditioning units sold globally are far less efficient than best-available models, undermining broader gains. The IEA notes that many countries — especially in fast-growing regions — still lack binding efficiency standards for new buildings.

• The IRENA report also highlights that investment, grid infrastructure and supply-chain constraints are limiting how quickly renewables and efficiency measures can scale.

The implications for policy and business

For policymakers, the message is clear: the current pace, while improving, remains insufficient. Achieving the doubling of global energy-efficiency improvement by 2030 will require a material increase in ambition, enhanced enforcement, and faster diffusion of best-available technologies. The IEA’s “Energy Efficiency Policy Toolkit 2025” provides a menu of measures for industry, buildings and transport that countries can adopt.

For industry and business, especially in energy-intensive sectors, the opportunity is still large. With many systems still operating at less than half of today’s best-available efficiencies, retrofits, new high-efficiency equipment and smarter operations remain low-hanging fruit. But success will depend on regulation, capital deployment and the ability to implement change at scale.

The broader energy-transition backdrop

Efficiency gains must be made alongside the rapid deployment of renewables and rising electricity demand. The IRENA report emphasises that even as renewables grew by a record 582 GW in 2024, the world must now add more than 1,122 GW per year through the remainder of the decade to meet the tripling target. That puts enormous pressure on investment and supply chains.

At the same time, the IEA’s recent “Global Energy Review 2025” shows that growth in electricity demand — driven by cooling, digitalisation and electrification — outpaced overall energy demand growth. Unless efficiency improvements accelerate, energy use will continue to rise even with increased renewables entering the system.

What comes next

The next five years will likely determine whether the world stays on track for its dual targets: doubling energy-efficiency improvement rates and tripling renewable-energy capacity by 2030. Achieving those will require:

• Sharper regulation and standards: mandating minimum performance levels for equipment, buildings, and industrial processes.

• Scaling investment: The IRENA-led report states that to stay on track, annual investment in renewables must reach at least USD 1.4 trillion per year through 2025-30 — more than double the USD 624 billion invested in 2024.

• Faster technology deployment: Speeding up adoption of high-efficiency equipment, industrial optimisation, grid flexibility and smart controls.

• Targeting hard-to-abate sectors and regions: Industry, buildings in emerging economies, and regions with very low efficiency baselines will demand particular attention.

• Bridging infrastructure and supply-chain gaps: Many of the bottlenecks highlighted by IRENA relate to grids, storage and component manufacturing.

Bottom line

The global trajectory of energy efficiency is improving — but not fast enough. At roughly 1.8 per cent improvement in 2025, the world remains well short of the pace required to hit the 4 per cent-plus annual gains needed to meet 2030 targets. In tandem with renewable-capacity scaling and rising demand, efficiency will remain one of the most important yet most challenging pieces of the energy-transition puzzle.

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