A year or two ago, some of this might have sounded theoretical. Sovereign AI was a phrase people used in strategy documents and conference panels. Important, yes, but still slightly abstract. That has changed.

We are now moving very quickly into a world where the computing power, the models, the data, the cloud infrastructure and the operating systems behind AI are becoming part of the critical infrastructure of modern economies. And the question that follows is a simple one: who actually controls them?

Making this about any one country, one company or one technology provider would miss the point. The point is that whoever controls the computing, the models and the data has leverage over everyone who relies on them. The country or organisation holding that leverage today may not be the one holding it in five years’ time.

That is a strategic issue for the economy, and an operational issue for energy, because energy is not a normal sector. Energy is the system that every other system depends on. If energy fails, everything else fails with it.

And at the same time, we are asking the energy system to do something extraordinarily difficult. We are asking it to decarbonise at pace, remain reliable and affordable, integrate much higher levels of variable renewable generation, and support the electrification of transport, heat and industry. And now we are asking it to power a sharp rise in digital infrastructure and AI.

AI sovereignty matters because whoever controls the computing, the models and the data has leverage over everyone who relies on them. The country or organisation holding that leverage today may not be the one holding it in five years’ time.
 

The numbers are striking. The latest Energy Institute Statistical Review of World Energy shows that electricity is becoming more central to the energy system. Electricity generation now represents around 19% of global total energy supply. In China that share has almost doubled since the turn of the century, reaching 24%. Transport is one of the clearest signs of that shift. Internal combustion engine vehicle sales have been falling since 2017, and in 2025 more than a quarter of new cars sold globally were electric. China remains the largest electric vehicle (EV) market, accounting for 60% of EVs sold worldwide.

And then there are data centres. For the first time this year, the Energy Institute Statistical Review of World Energy included data centre power demand as a dedicated table. Global electricity consumption for data centres in 2025 was 788TWh. Some 40% of that was in the US alone.

So, when we talk about AI we are not talking about something floating in the cloud, disconnected from the physical world; AI has a physical footprint. It has an energy footprint. It has a grid footprint. And, increasingly, it has a sovereignty footprint.

The energy sector is therefore on both sides of the AI equation. On one side, energy will be essential to enabling AI: powering the data centres, the networks, the computers and the cooling that advanced AI requires. On the other side, AI will become essential to running energy: forecasting demand, balancing grids, integrating renewables, improving maintenance, optimising assets, supporting safety decisions, identifying cyber threats and helping people make sense of systems that are becoming too complex to manage by traditional means alone.

Using AI in industry
AI can help us operate more safely, more efficiently and more intelligently. It can help limit downtime through predictive maintenance. It can support load balancing and fuel optimisation. It can help specialists carry out hazard assessments. It can help engineers, operators and decision-makers see patterns they might otherwise miss.

But, and this is the important point for today, applying AI well is not just about whether the algorithm works. It is about whether the whole system works. It covers technology, organisation, people, governance, skills, interfaces, accountability and culture. The human factor is not a soft issue here. It is central.

In high-risk industries, people do not disappear when automation increases. Often, their role becomes more difficult. They move from doing the task to monitoring the system. They are expected to know when to trust the machine, when to challenge it, when to intervene and when to take back control. That is not easy. Highly automated systems can put human operators in the position of watching rather than acting. If the system makes a poor decision, the person may have only seconds to understand what has happened and intervene effectively.

That raises difficult questions. How should functions be allocated between people and AI? How much authority should an AI system have?

Who is accountable when something goes wrong? And how do we design interfaces that allow people to understand, challenge and query AI outputs rather than simply accept them? These are not abstract design questions. In energy, they go to the heart of safety, resilience and public trust.

The question for energy is not ‘Should we use AI?’ We will use AI. In many areas we already are. The question is whether we use it deliberately, safely and in a way that respects sovereignty, or whether we drift into dependency before we have agreed what good looks like.

What does sovereign AI mean for us?
Sovereign AI is still more of a phrase than a standard. It can mean domestic supply. It can mean data residency. It can mean model assurance. It can mean regulatory control. It can mean supply chain resilience. It can mean operational independence. It can mean all of those things at once.

But if we cannot define it in a way that operators can apply, boards can govern, regulators can test and government can support, then it will remain a slogan. And slogans do not run infrastructure.

National strategy increasingly assumes some degree of sovereign capability, but many operational systems still sit on foundations controlled elsewhere. That may be manageable in some contexts. But when we are talking about the infrastructure that powers the country, we need to be much clearer about the risks we are accepting, the dependencies we are creating and the safeguards we expect.

The energy sector still has a window to shape this agenda on its own terms. But that window will not stay open indefinitely.

The Sovereign AI for UK Energy Security Forum was organised with Applied Computing and supported by Wipro and AWS.

• Further reading: ‘Why the energy transition increasingly depends on AI’. Artificial intelligence is driving up electricity demand through data centres and advanced computing. Yet speakers at All-Energy argued that it may also be essential for managing the increasingly complex, decentralised energy systems needed to achieve net zero.
• ‘How much energy does AI actually consume?’ There are serious concerns about the energy consumption of AI systems – in particular large language models (LLMs) such as ChatGPT. Find out how much energy they use to answer your queries.

These measures are part of the Action Plan for Carbon Peaking during the 15th Five-Year Plan (2026–2030), which targets a 17% reduction in carbon emissions per unit of GDP from 2025 levels by 2030. At that time, non-fossil fuels must account for 25% of total energy consumption, and clean energy sources must meet all new electricity demand nationwide.

‘The plan will strengthen China’s energy security during global energy market instability while helping the country move into a time when non-fossil energy becomes the dominant source of supply,’ said Tian Zhiyu, Director of the Centre for Energy Sustainable Development under the Energy Research Institute of the NDRC.

An NDRC official stated that the commission will work with relevant departments to implement the plan and support national goals to peak CO2 emissions before 2030 and achieve carbon neutrality before 2060.

The new implementation frameworks target nine high-emission industries: steel, electrolytic aluminium, cement, flat glass, oil refining, ethylene, synthetic ammonia, methanol and coal-fired power generation. Official data shows these industries remain the main sources of national energy consumption and carbon emissions due to their large industrial base. The steel industry alone accounts for about 15% of China’s total carbon emissions.

This high percentage is due to the long-process production model in China’s steel sector, which results in higher carbon intensity than steel manufacturing in the European Union, Japan and South Korea. Government reports indicate that much of the domestic capacity in crude steel, electrolytic aluminium and cement clinker does not meet advanced energy efficiency benchmarks. In addition, industrial operators face increasing bottlenecks as conventional energy-saving technologies reach operational limits, raising the marginal cost of further carbon reductions. In the cement sector, which accounts for about 9% of national carbon emissions, over half of emissions come from the limestone calcination process rather than fuel combustion.

To address this, the government’s action plan calls for coordinated efforts across industries, as carbon emissions in key sectors depend on both upstream energy sources and downstream applications. For example, the carbon intensity of the electrolytic aluminium industry is influenced by the carbon footprint of its power supply as well as the grid’s ability to absorb wind and solar power.

To monitor carbon data across interconnected supply chains in automotive manufacturing and construction, authorities are implementing national product-specific carbon accounting. These systems embed carbon costs into corporate operational expenses, increasing financial pressure on substandard facilities. Regulators will apply differentiated electricity pricing and restrict carbon quota access for enterprises that do not meet energy efficiency standards. High-efficiency enterprises will receive policy incentives and financial benefits through the national carbon quota trading market.

The national guidelines direct industries to adopt digital management tools, intelligent sensors and big data analytics for real-time energy monitoring and efficiency optimisation. Pilot programmes in Zhejiang Province have applied these tools to over 3,400 high-energy-consuming enterprises, raising local steel and ethylene operations to national standards. To support these efforts, the state is developing new infrastructure, including about 100 national-level zero-carbon industrial parks and 500 zero-carbon factories.

The plan also includes developing multiple zero-carbon transport corridors to reshape regional logistics networks between industrial centres. In Baotou, a green power transmission project delivers clean electricity from 200 km away, enabling local aluminium producers to manufacture low-carbon metals using renewable energy.

To support clean energy integration across the grid, the Chinese government has established a capacity-based electricity pricing system that compensates flexible power sources, including coal-fired power and energy storage facilities. Reforms linking the national carbon market and the power market aim to incorporate carbon-related costs directly into electricity pricing.

On the consumption side, the guidelines prioritise replacing fossil fuels with non-fossil energy in transportation and construction. The three-year roadmap calls for expanding new energy vehicles so they make up about 30% of all vehicles on the road by 2030. For transportation infrastructure, operators must first upgrade high-power charging facilities at stations where utilisation rates exceed 40% during major holidays.

Finally, the directive requires coordinated development between green electricity supply and emerging data industries, with a focus on computing power facilities. This approach aims to improve regional energy distribution by aligning the high electricity demands of data centres with local renewable energy generation. 
 

The completed maritime grid will generate up to 47.8TWh of renewable electricity per year, supplying around 10.6% of the annual electricity consumption of France. The Clean Industrial Deal State Aid Framework uses a two-way contract for difference (CfD) that provides operators with a variable premium. For three specific wind farms, this new framework replaces a temporary support scheme that the Commission previously approved in August 2025.

‘Today’s decision clears the way for France's offshore wind support scheme,’ stated Teresa Ribera, Executive Vice-President for Clean, Just and Competitive Transition, adding that France will continue working towards a fully decarbonised energy system.

The agreement, signed with Dar Al Balad Contracting and Operations (DAB), covers the conversion of existing heavy oil-fired boilers into dual-fuel systems capable of operating on natural gas and heavy oil, including co-firing.

The project involves the Jeddah South and Shuqaiq power plants on Saudi Arabia’s west coast. Each plant has an installed capacity of about 2.9GW and consists of four generating units that began operating in 2017.

Mitsubishi Power previously supplied boiler components for both facilities and will use existing infrastructure as part of the conversion work.

The project is part of Saudi Arabia’s efforts to increase the share of natural gas in power generation and reduce reliance on heavy oil. The country has set a target for natural gas to account for more than 50% of its power mix.

Electricity demand remains high on the west coast, where heavy oil has historically been a primary fuel source. Converting existing plants is intended to support supply while aligning with emissions reduction goals.

Mitsubishi Power will provide equipment and technical services under its agreement with DAB. The end customer is Saudi Energy, which is overseeing fuel transition initiatives in the power sector.

Air Liquide to invest $200mn in US POX unit
Air Liquide has announced plans to invest more than $200mn to expand production at Oxea’s site in Bay City, Texas, US.

The project includes construction of a partial oxidation (POX) unit, expected to start operations in early 2029. The facility will produce syngas and hydrogen for use in Oxea’s chemical manufacturing processes.

According to Air Liquide, the unit will include a CO2 recycling system designed to reuse emissions within the production process. The project will partially replace existing units and is expected to reduce net CO2 emissions by approximately 64,000 t/y.

The investment expands Air Liquide’s industrial gas infrastructure on the US Gulf Coast, where it operates a pipeline network supplying regional customers.

Most disbursements have supported the distribution and installation of end-use equipment such as cookstoves and LPG cylinders, while smaller shares have been allocated to technical assistance, market development, investment vehicles and infrastructure. Nearly half of the funding has gone to LPG, with the remainder spread across improved biomass, electric cooking, biogas and other solutions.

Around 12 million people gained access to clean cooking solutions in 2024, roughly three times the annual rate seen in 2010, with early indications pointing to further gains in 2025. Sixteen countries recorded faster progress than in the previous year, although rapid population growth meant the overall number of people without access continued to increase.

The report also highlights rising investment in the sector. Annual spending reached approximately $770mn in 2024, up from $590mn in 2020, with around 70% coming from private capital and consumer spending. LPG remains the dominant cooking fuel, accounting for more than 70% of access, while electric cooking is the second most widely used option and biomass cookstoves continue to play a role in many households.

External pressures are also affecting the sector. Disruptions to global LPG markets following the closure of the Strait of Hormuz have contributed to higher prices, reducing affordability for households and increasing fiscal pressure on governments. These developments highlight the importance of strengthening fuel supply security and diversifying cooking technologies.

Alongside financial trends, policy activity has increased significantly. Since 2024, more than 120 new clean cooking policies have been introduced across more than 30 countries, representing most of the population without access. These measures, combined with a growing pipeline of infrastructure – including an estimated 250,000 t of additional LPG storage capacity under construction – are expected to support further progress.

Ahead of the second Clean Cooking Summit (which was planned for 9–10 July but postponed because of travel restrictions), the IEA reported a further $900mn in new financial commitments, adding to the $2.2bn pledged at the inaugural 2024 Paris meeting. The next summit in Nairobi is expected to focus on mobilising additional funding and accelerating delivery.

A new institutional arrangement for the Clean Cooking Alliance has also been agreed, transitioning it into an intergovernmental initiative hosted by the IEA. The shift is intended to strengthen coordination between governments, industry and financiers, with 12 countries participating in the inaugural meeting under the new structure. It is expected to provide a more formal framework to track progress, align policy efforts and sustain momentum between summits.

The bill sets up a two-stage process for permitting. Stage one is a feasibility permit. If a developer decides to proceed, it will need to apply for a commercial permit and obtain environmental consents. There will need to be safety zones around any assets, and developers will have to decommission them at the end of their lives.

Energy Minister Simeon Brown said: ‘The winds off the South Taranaki coast are on a par with those of the North Sea, the most productive offshore wind region in the world, and because they blow so steadily, offshore turbines are expected to run at higher capacity than turbines on land.’

He continued: ‘The South Taranaki Bight alone could one day supply a significant amount of new generating capacity, with a single large project there potentially powering more than 650,000 homes.’

An amendment allows ministers to designate areas as exclusively for offshore renewable energy, which prevents seabed minerals permits from being issued, according to analysis from law firm Russell McVeagh. It adds that what the new law does not do is set up any kind of contract-for-difference (CfD) price support mechanism.

The French-speaking eastern Canadian province of Québec has published its 2026–2050 Integrated Energy Resource Management Plan, which says that an additional 15TWh to 2030, 60TWh to 2040 and 150TWh of renewable energy supplies will be needed by 2050. Including planned energy efficiency measures raises the 2050 total to nearly 295TWh.

In 2022, the province consumed 496TWh of energy, of which 41% was electricity (primarily from hydro, plus wind), 37% petroleum, 14% natural gas and LNG, and 7% bioenergy.

Although the report does not specify exact ratios, wind power is the main target for the growth. The plan says: ‘Wind power remains the preferred form of electricity generation for quickly adding low-cost energy to complement existing infrastructure.’ It anticipates wind installed capacity to be 12–16GW by 2040, and 21–25GW by 2050.

It also anticipates hydro representing 7–11GW in 2040 and 8–12GW in 2050. Solar could be 1–3GW in 2040 and up to 5GW in 2050.

The report also says that the province intends to ‘fully’ exercise its powers to strengthen energy autonomy and reduce reliance on hydrocarbon imports.

Onshore wind turbine manufacturer Nordex was pleased with the outcome. It said: ‘As the birthplace of Canada’s wind energy industry, Québec brings together recognised know-how, world-class expertise and a strong industrial ecosystem that make it a natural partner in accelerating the energy transition. It is no coincidence that Nordex chose Québec as the cornerstone of its Canadian growth strategy. Today, the company accounts for nearly 60% of its Canadian portfolio in Québec, representing more than 1.2GW of projects, while also maintaining its Canadian headquarters in Montreal.’
 

In July, solar power trade association SolarPower Europe complained that the plans have generated ‘deep uncertainty’ in the sector and called on authorities to publish guidance and impact assessments, harmonise codes and support European manufacturers to scale up production in compensation.

It said: ‘The absence of written information on the justification and scope of the decision is already delaying solar projects across Europe – putting the EU’s 2030 renewable energy goals at risk – while at the same time hindering the sector’s ability to adapt to the [European] Commission’s decision. The absence of prior consultation or an impact assessment is also a concern for the sector and is not consistent with the Commission’s own good governance principles. Without understanding the Commission’s reasoning, investors cannot make informed decisions about projects, investments, procurement or financing structures.’

But the trade body went on to say its complaints do not mean it was against the plans. ‘Industrial policy and cybersecurity are priorities for SolarPower Europe which require distinct and tailored approaches. We have a track-record of concrete proposals on strengthening cybersecurity and are supporting strong and strict made-in-Europe provisions for reshoring manufacturing.’

In the absence of official impact assessments, analyst Wood Mackenzie has conducted its own analysis, which estimates that more than 28GW (DC) of capacity will be affected, amounting to 14% of forecast European solar photovoltaic (PV) demand, and 12% of energy storage demand, between 2026–2030. However, 80% of funding of these projects comes from either private or national government funding, it said.

Both Wood Mackenzie and SolarPower Europe said that central and eastern European projects would be most affected, as they are the ones that receive the most public support.

The Wood Mackenzie analysis goes on to say that the impact will spread more widely, as EU funding is also used for international projects. And it could be greater within the EU if member states adopt the rule for solar and battery storage projects supported with national funds, as the EU is requesting.

Wood Mackenzie suggests that replacing the inverters with domestic alternatives will raise prices by about 10%. That’s not all, as the rules will also require unbundling of integrated battery and inverter technologies.

Juan Monge, Principal Analyst at Wood Mackenzie, said: ‘The real questions now are how the Commission will update the EU Cybersecurity Act to treat solar inverters as critical infrastructure and whether EU member states will follow the Commission’s lead and extend these restrictions to their own national funding programmes. If they do, the scale of disruption changes considerably.’

Still, both companies continued to invest in renewables at huge scale. Amazon matched 100% of electricity with renewables in 2025. It achieved 131TWh of carbon-free production. The company counts 375 utility-scale projects globally (264 solar, 109 wind and two nuclear) and 712 renewable energy projects accounting for 41,670MW capacity in total. That sum includes 50 projects amounting to 1,009MW in UK.

Separate Frontier Economics research found Amazon invested more than €14bn in Europe and UK between 2021–2025, amounting to 8.7GW of renewable energy capacity.

In 2025, Google’s clean energy production amounted to 48TWh, or roughly enough energy to power Greece for a year. It also matched 100% of electricity consumption with renewable energy purchases. In 2025 it signed agreements for more than 12GW of 'net-new clean' energy, which includes power purchase agreements, energy storage agreements and agreements for carbon certificates. That figure is about a third of the total amount contracted from 2010–2025, and eight times greater than in 2019.  

Supply chain (Scope 3) emissions grew by 25% at Google and 20% at Amazon in 2025 compared with 2024.

Speaking of the increase in supply chain emissions, Brandt adds: 'This increase reflects not only the scale of new AI infrastructure, but also an Asia-Pacific supply chain operating on grids that remain undersupplied with carbon-free energy. This is in part due to land constraints, high construction costs, and policy and regulatory hurdles.' Google did reduce operational emissions (Scope 1 and 2) by 2%.  

At Amazon, supply chain emissions account for 76% of its carbon footprint, which reached 80.85mn t CO2e, up from 69.55mn t CO2e in 2024, and 65.28mn t CO2e in 2023. Emissions from direct operations accounted for 19% of carbon footprint and indirect emissions from purchasing electricity represented 5%.

Amazon highlighted a number of sustainability programmes among its supply chain as well as elsewhere, such as the Climate Pledge Fund and Amazon Sustainability Accelerator.

Google calculated that it avoided emissions exceeded 58mn t CO2e in 2025, through machine hardware efficiencies, software and compute efficiencies and clean energy procurement.

Also, it estimates use of nine of its products combined helped reduce emissions by 41mn t CO2e (Google Earth, Nest thermostats, Solar API, Ignite Energy Access, fuel-efficient routing, Green Light, alternative route suggestions, Contrails, and Waymo).

His Excellency Dr Sultan Al Jaber, ADNOC Managing Director and Group CEO, and XRG Executive Chairman, said: ‘With LNG demand set to grow substantially, the world will need reliable, responsible and trusted suppliers at scale. This world-class, integrated commercial LNG platform brings together the full strength of ADNOC’s marketing, trading and shipping capabilities to create a single global hub in Abu Dhabi. It marks a step-change in scale, flexibility and optionality of our LNG marketing and trading platform and will further position ADNOC to meet the world’s growing demand for energy.’

The combined organisation is targeting 47 million tonnes per year (mn t/y) of combined LNG by 2035, including the 9.6mn t/y Ruwais LNG project in Abu Dhabi expected to start up in 2028. That project will increase ADNOC Gas's production to 15mn t/y.

At that point, ADNOC Gas is expecting to be transferred ADNOC's 60% share of Ruwais LNG 'at cost' – estimated to be $5bn. According to a 2024 press release, other shareholders in the project are Mitsui & Co, Shell, BP and TotalEnergies, each with 10%.

In July, ADNOC signed a 15-year sales and purchase agreement with Inpex of Japan for 1mn t/y of LNG, primarily from Ruwais LNG.

In other news also in July, ADNOC and XRG signed a strategic collaboration agreement with Mitsui & Co of Japan, the Ruwais LNG investor of Japan, a country which is one of ADNOC's most important markets. The SCA establishes a framework for collaboration across multiple strategic areas, including crude oil market development and long-term supply, LNG sales and optimisation, sulfur procurement and logistics, and shipping solutions for LNG, ammonia, sulfur and other commodities.  

Through XRG, ADNOC and Mitsui will also evaluate international investment opportunities across the energy value chain, alongside potential collaboration on lower-carbon fuels and chemicals, including methanol and other projects at TA'ZIZ.  

In May, the TA’ZIZ Methanol Company, a joint venture between TA’ZIZ and Proman, announced financial close on $2bn of financing for the UAE’s first world scale methanol plant in Al Ruwais Industrial City, targeted for completion in 2028. Once operational, the plant will support the development of a domestic chemicals value chain.

Pacific exporter's first shipment

On Mexico's Pacific coast, TotalEnergies has shipped to Asia the first cargo from ECA LNG Phase 1, an LNG export terminal currently under commissioning, in Ensenada, Baja California. TotalEnergies, which holds a 16.6% stake in the project alongside operator Sempra Infrastructure, will offtake 1.7mn t/y of LNG for 20 years from the start of commercial operations.

The site, formerly an LNG receipt, storage and regasification terminal, is being augmented with natural gas liquefaction capabilities. The single-train phase 1 facility has a nameplate capacity of 3.25mn t/y, 2.5mn t/y of which has been covered by 20-year agreements with TotalEnergies and Mitsui. It is claimed to be the first such facility on Mexico's Pacific coast, and promises to reach Asian markets more quickly than existing facilities in the US Gulf of Mexico, which would have to transit through the Panama Canal.

The LNG is sourced from the Permian basin in Texas and New Mexico. A second liquefaction train is also planned at the site.

Justin Bird, CEO of Sempra Infrastructure, said: ‘At a time of increased uncertainty in the global LNG trade, we are excited to begin shipping a new and reliable source of natural gas from North America’s Pacific Coast to customers around the globe.’

Shell 2026 LNG Outlook

Shell reports that total LNG trade in 2026 could amount to the same as in 2025, 422mn t. That is despite the closure of the Strait of Hormuz which has locked in about a fifth of the world's monthly supply of LNG, assuming that shipping returns to normal in summer 2026. The ramp up of new liquefaction facilities in North America, improved performance at existing plants and slower Asian imports of LNG have partially offset the impact of reduced supply from the Middle East, it said.  

Long-term supply accounted for two-thirds of LNG trade. It said that the conflict had bumped up the average price of LNG by a few dollars per million British thermal units (mn Btu). The average price that buyers paid for LNG in May was around $11–12/mn Btu, compared to $7–11 in January before the conflict began.

Shell's 2026 LNG Outlook forecasts 180mn t of new supply to enter the market by 2030.

South and Southeast Asia are forecast to account for 40% of LNG import by 2050. In Japan, datacentres are causing demand growth.

It estimates 200mn t/y of new LNG liquefaction capacity will be needed in addition to projects already under construction.

This year is the tenth LNG Outlook. Since 2017, global LNG trade has increased by around 60%, from 264mn to 422mn t.

‘Sunny Italy and agri-PV are a perfect match,’ stated Sopna Sury, CEO of RWE Renewables Europe & Australia. ‘Advanced agri-PV enables us to use scarce land resources responsibly and efficiently by generating two different yields from the same land: agriculture and renewable energy.’

The company has begun construction on four additional agri-PV projects in Italy, adding 50,000 solar modules and 38.2MWac of capacity. These include Acquafredda 2 (11.7MW) in Campania, Cave (9MW) in Calabria and Enna (9.5MW) and Carcitella (8MW) in Sicily, all scheduled for completion in 2026.

‘We are now looking forward to installing a further 50,000 solar modules, which will supply electricity to an additional 20,000 homes, while sheep graze below,’ Sury said. Local farmers oversee agricultural activities at the sites, cultivating crops such as alfalfa, oats, broad beans, rosemary, chamomile and medicinal herbs.

Agri-solar news roundup  

Swedish renewable energy company, Orrön Energy AB, recently sold a 91MW Agri-PV solar project in eastern Germany to Gülermak Renewables Ltd for up to €5.6mn. Orrön Energy received an initial €2.4mn, with the remaining balance contingent on achieving development milestones. The company expects to be construction-ready by 2027. The 91MW German project is ready for permitting and includes an option for battery storage.  

Chinese digital manufacturing company, Antaisolar, introduced its Agri-PV Tracking System Solution at Intersolar Europe in Munich. Global Technical Director, Emmanuele Chiappori, presented tracking hardware with adjustable ground clearance from 1.3m–5m to accommodate agricultural machinery. The Antaisolar system uses a two-section pile foundation to increase pull-out resistance and a ‘SmartTrail’ control system with a dedicated harvest mode for lateral movement of machinery.  

Staying in Europe, institutional research programmes are integrating energy storage into agricultural solar designs. In Romania, researchers launched a three-year, €10mn demonstration project titled ‘Increasing the resilience of the food supply chain to the complex challenges of the modern world’ to develop an agri-solar system integrated with batteries. The National Institute for Research and Development of Isotopic and Molecular Technologies leads the Romanian initiative, in partnership with the Agro-Food-IND Napoca Cluster and industry partners. Prodfer Construct, a subsidiary of the engineering, procurement and construction company Parapet, deploys the photovoltaic panels and energy storage units for the Romanian pilot. The infrastructure supplies electricity directly to irrigation systems serving cereal crops, vegetables and medicinal plants.  

Across the Atlantic, a US research team led by the National Laboratory of the Rockies developed an economic framework and simulation demonstrating that widening the spacing between solar panel rows makes large-scale, mechanised agrivoltaics financially viable. The researchers simulated a 160-acre project in Colorado over 25 years with tracked solar arrays and four distinct crops (potatoes, onions, sugar beets and wheat). They found that spacing the solar rows between roughly 9.6m and 18.8m allows heavy farming equipment to navigate freely, maintaining standard crop production without sacrificing efficiency. The analysis showed that when agricultural profits reach roughly $200 per acre, the combined revenue from power purchase agreements and sustained crop sales often outpaces traditional utility-scale solar-only installations, making the system highly adaptable to variations in capital costs and demonstrating that farm-scale food production and clean energy can thrive on the same footprint. 
 

The system works by absorbing heat directly from the synthetic turf surface, which naturally collects solar radiation and warms the upper layer during daylight hours. Underground pipes beneath the pitch distribute the captured heat to target destinations and the grid layout directly under the turf maximises heat absorption. Operators can then use the heat immediately in local buildings or store it to ensure a consistent supply year-round. Storage enables the system to provide warmth during the winter months while the heat extraction process also cools the turf surface, ensuring a safe and comfortable environment for athletes.

The heat collector field technology is reportedly already in use in Eindhoven, Zaanstad, Gouda and The Hague. The energy captured by these fields supplies various nearby buildings, including sports facilities, homes, swimming pools, primary schools and daycare centres. Stefan Diderich, Director General and CEO of the EMEA Synthetic Turf Council (ESTC), stated that these fields provide clean, renewable energy to communities.

‘We not only hope for this technology to be scaled up across the Netherlands, but for other countries to look and learn from this, as this has the potential to deliver an extraordinary amount of good on a global scale,’ Diderich stated.

Each field is capable of heating up to 300 homes annually. Widespread adoption of this technology could reduce national CO2 emissions by up to 0.45mn t/y. This requires applying the technology to the country's 1,250 existing pitches across the Netherlands. There are additional opportunities to implement this infrastructure on multi-use synthetic turf pitches nationwide. Leander Lignac, Specialist in Sustainable Sports Facilities at the Knowledge Centre for Sport & Physical Activity, stated that converting synthetic turf pitches into energy sources maximises impact.

‘Turning synthetic turf sports pitches into a source of green energy is all about impact – using a single space in multiple ways to solve many challenges at once. Space in the Netherlands is sparse, especially in the cities, so when it’s possible to use conveniently located pitches not just for sports, but for sustainability goals too, these facilities become more future-proof. While this technology is not yet widespread, it has the potential to deliver a significant reduction in carbon emissions when scaled up. Ultimately, the sports sector needs to be future-proof, and as part of that journey, it is our job to make municipalities and local sports clubs aware of these solutions to help them be realised across the Netherlands.’

The Dutch sports department recently published a Roadmap for Improving Sustainability in Sport, which outlines steps for athletic facilities to transition from traditional energy sources. 

The facility converts industrial off-gas into electricity for onsite use and export to the grid. Built, owned and operated by E.ON Power Plants Belgium, the facility captures energy from syngas generated during carbon black production and converts it into electricity via a high-efficiency steam turbine.

The plant will supply the entire Imerys site while exporting surplus power equivalent to the annual consumption of around 40,000 households to the Belgian grid.

Carbon black is a key conductive material used in lithium-ion batteries for electric vehicles and energy storage systems. The installation enables full recovery of syngas that was previously flared, improving overall energy efficiency at the site.

The project also incorporates flue gas treatment systems, including DeNOx and DeSOx technologies, aimed at reducing nitrogen oxide and sulphur oxide emissions in line with EU environmental standards.

E.ON Power Plants Belgium operates similar industrial energy installations across the region, including sites in Ertvelde, Tisselt and Terneuzen.

UK sets out plans to tighten energy standards for larger non-domestic buildings

Meanwhile, the UK government has set out plans to strengthen Minimum Energy Efficiency Standards (MEES) for non-domestic buildings, including a proposed requirement for larger rented properties to reach an Energy Performance Certificate (EPC) rating of B by 2031.

EPC ratings measure a building’s energy efficiency on a scale from A (most efficient) to G (least efficient).

The update is an interim response to consultations held in 2019 and 2021 on improving the energy performance of non-domestic rented buildings in England and Wales and signals a more targeted approach focused on larger premises.

Under the proposals, all private rented buildings over 1,000m² would be required to meet an EPC B rating by 2031, where cost-effective. Smaller buildings would remain subject to the current minimum standard of EPC E.

The government confirmed that it has dropped the previously proposed interim milestone of EPC C by 2027, giving landlords and tenants more flexibility to plan upgrades around lease cycles and building requirements.

Existing mechanisms, including the seven-year payback test and exemptions, will remain in place to ensure that only practical and cost-effective measures are required.

The changes are expected to reduce energy use and costs significantly, with estimated bill savings for tenants in larger non-domestic buildings of up to £360mn/y by 2031.  

Publication of further details as well as launch of enabling secondary legislation is planned.

The government said continued operation of the plant would reduce overall energy system costs compared with building alternative generation capacity, while also strengthening the UK’s energy security.

The government and EDF have agreed terms for a 20-year Contract for Difference (CfD) price guarantee at £70.50/MWh in 2025 prices, starting in 2035 – the plant’s original closure date – with support and investment from Centrica.

The announcement is part of wider government support for nuclear energy, including plans for small modular reactors in Anglesey and the construction of a new twin-reactor nuclear plant next door, Sizewell C, set to generate 3,260MW. Sizewell A houses two Magnox reactors, now shut down.

NEA report highlights barriers to scaling nuclear capacity worldwide  

New analysis from the OECD Nuclear Energy Agency (NEA) reinforces the importance of extending the operating lives of existing reactors as countries seek to scale up nuclear capacity.

The report finds that meeting global ambitions to significantly increase nuclear energy will require accelerated growth in workforce capacity, supply chains and financing, alongside maximising output from the current fleet.

It outlines four scenarios for global nuclear capacity to 2050, ranging from 347GW in a low case to around 1.3TW in a transformative scenario, more than tripling current levels.

According to the NEA, achieving this level of expansion would require significant changes in policy, industrial capability, project delivery and financing, particularly in OECD countries.

The report also highlights a shift in nuclear development towards non-OECD countries. While OECD countries account for around 78% of existing capacity, approximately 80% of the 70GW currently under construction is in non-OECD countries, with China accounting for more than 33GW.

Long-term operation of existing reactors is identified as a key factor in maintaining capacity. Many OECD reactors are due to reach the end of their initial licences before 2040 and extending their lifetimes to 60 or 80 years could help preserve low-carbon generation. However, more than 50GW of OECD capacity has not yet secured licences to operate to 2040.

The report also identifies supply chain, workforce and financing constraints as major challenges to higher deployment scenarios. Global investment in nuclear new build has averaged around $30bn/y and would need to increase significantly to meet higher growth pathways.

The NEA concludes that closing the gap between ambition and delivery will require coordinated action from governments, industry and financial institutions, alongside measures to attract private capital and manage project risks. 

A. Growing up on the West Coast of Scotland, I was fortunate to be immersed in nature from a young age. The rugged beauty of the coastline and the abundance of wildlife fostered a profound connection to my surroundings, particularly the water. This environment instilled in me an appreciation for the natural environment that has shaped my outlook throughout life.

My interest in energy emerged as part of a broader curiosity about how cities function and thrive. I began to see energy as both a challenge and an opportunity: it is fundamental to economic productivity, and quality of life, and an area where some of the most transformative changes can be made. Rather than viewing energy in isolation, I recognised its central role in the functioning of cities and societies.

With the progression of my career, especially through my involvement in large-scale infrastructure and the aviation sector, my focus on energy sharpened. I started to see energy not just as an operational issue, but as a strategic lever and essential aspect that could drive meaningful change across projects and industries.

Q. How did you first hear about the Energy Institute and what motivated you to join?  

A. I first heard about the Energy Institute through the Society of the Environment, where I was looking to become registered as a Chartered Environmentalist. I was keen to find an organisation that could support the development of my career as a sustainability professional with a technical slant, and the Energy Institute offered that mix. The diverse community fosters knowledge sharing and collaboration, supporting personal and professional development within the field.

Q. The Energy Institute isn't the only organisation that offers registration for Chartered Environmentalists. How has the Energy Institute gone beyond merely offering access to professional registration services to support you and your career?  

A. While Chartered Environmentalist registration was my initial reason for joining in 2019, the Energy Institute has become much more than a professional registration body. I was looking for an organisation that combined sustainability with technical and engineering credibility, and the EI has delivered on that.

The Energy Institute has provided access to a strong professional network, high-quality technical insight and opportunities to engage with emerging issues across the energy transition. I particularly value its balanced, evidence-based approach.

More recently, I have applied for Energy Institute Fellowship and become a mentor, reflecting how my relationship with the organisation has evolved from seeking professional recognition to actively contributing to the profession. I now see the EI as an important part of my ongoing professional development and a community where I can both learn from others and share my own experience.  

Q. How has being a Chartered Environmentalist (CEnv) benefitted you in your career?

A. Becoming a Chartered Environmentalist has been a defining milestone in my career. At a practical level, it provides immediate credibility, particularly in complex, multidisciplinary environments like giga-projects, where you’re engaging with engineers, financiers, policymakers and developers simultaneously.

More importantly the Chartered Environmentalist professional qualification signals that your approach is grounded in systems thinking, ethics and evidence-based decision-making. In my current role leading ESG for a large-scale development, that credibility is essential when influencing high-value decisions, whether that’s embedding decarbonisation strategies, shaping sustainable design standards, or challenging business-as-usual approaches.

It has also helped position me not just as a sustainability advocate, but as a strategic advisor who understands risk, value creation, and long-term resilience.

Q. Tell us about your current job and industry, and how your work is contributing toward a just transition to net zero?  

A. I have more than 20 years in the built environment and aviation sectors, including roles as Senior Director of ESG (Environmental, Social and Governance) at Qiddiya and Head of Sustainability at Abu Dhabi Airports. I have led multiple programmes to cut GHG emissions through global supply chains, delivered ISSB-aligned reporting and IFRS disclosures, and secured executive and board-level buy-in for significant ESG investments.

My work integrates carbon reduction strategies, science-based targets, and climate risk management to advance Saudi Vision 2030 and drive innovative green-finance solutions.  

Q. You have jumped around between roles based in Scotland and the Middle East. In doing so, you have managed to straddle climactic extremes. What links have you identified between the two countries/regions, in sustainability terms specifically?

A. Working in both Scotland and the Middle East has shown me that sustainability is far more universal than many people assume. The climate, geography and culture are very different, but the underlying challenges are remarkably similar: how do you create economic prosperity while protecting natural resources and improving quality of life?

Scotland has a long history of industrialisation and is now focused on decarbonising an existing economy and infrastructure. Saudi Arabia, by contrast, has the opportunity to build new cities and industries from the ground up. One is largely about transformation; the other is about shaping the future. From a sustainability perspective, both require long-term thinking, strong governance and the ability to balance environmental, social and economic priorities.

The biggest lesson I’ve taken from working across both regions is that sustainability is ultimately about people rather than geography. Whether you’re engaging communities in Scotland or stakeholders in Saudi Arabia, success depends on understanding local priorities rather than imposing a universal model. The principles are global, but the solutions must always be locally relevant. 

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

Ofgem said the portfolio had been structured to provide an appropriate mix of technologies, storage durations and geographic locations. The energy regulator opted for capacity at the upper end of its original target range, recognising that some schemes may not ultimately go ahead while aiming to ensure sufficient storage capacity is delivered.

The full list of LDES projects provisionally selected for Ofgem support, listed in consultation documentation

Source: Ofgem  
 

Unlike shorter-duration batteries that typically respond over minutes or a few hours, LDES functions over a timescale of eight hours or more, allowing larger volumes of renewable electricity to be shifted across extended periods. According to Ofgem, wider deployment could ease pressure on transmission and distribution networks while reducing the need for costly network investment and constraint management.

Akshay Kaul, Director General for Infrastructure at Ofgem, said: ‘It’s fantastic to see such a wide range of technologies coming forward. This takes us a step closer towards the long-duration energy storage we need in a clean power system to maintain secure supply during periods of cold, hot, still or cloudy weather when solar or wind power output may be low.’

The investment support scheme uses a cap-and-floor mechanism designed to give developers greater revenue certainty while protecting consumers. Projects are guaranteed a minimum level of revenue if returns fall below an agreed threshold, while revenues above the cap are shared with consumers.

Sam Hollister, Head of UK Market Strategy at LCP Delta, said technologies capable of shifting electricity across hours and days would become increasingly important as renewable generation expands.  

‘Today’s announcement marks an important milestone for long-duration energy storage in Great Britain. As renewable generation continues to grow, technologies that can shift large volumes of electricity across hours and days will become increasingly important in maintaining security of supply and minimising system costs,’ he said.

Consultation on Ofgem’s provisional decisions will remain open until 7 August 2026, with a final decision expected later this year. Applications that are not selected in the first round may still compete for support in future or go ahead without support on a merchant basis.

Reflecting on these outcomes, Kristian Ruby, Secretary General of Eurelectric, stated that local power production lessens dependence on imports. ‘Data trends from the first half of 2026 reveal what we’ve long been advocating for: replacing imported fossil fuels with homegrown clean and renewable electricity means an energy-independent Europe less exposed to crises.’

Driving this trend in May 2026, solar generation led the electricity mix across the 27 member states, accounting for almost 23% of total output. Solar output reached a record monthly high of 48TWh, equivalent to Hungary’s annual electricity demand. This record output helped moderate costs during peak hours and reduced reliance on thermal gas-fired plants when weather conditions were favourable.

However, electricity prices rose sharply during periods without sunlight. Below-average wind speeds and low water reservoir levels, along with nuclear reactor maintenance schedules in multiple countries, limited the availability of alternative clean power sources.

Consequently, in May and June 2026, electricity prices before 09.00 and after 18.00 averaged €122/MWh, up from €90/MWh during the same period in 2025. Daytime prices remained much lower, averaging around €56/MWh due to intense solar availability. As a result, gas generation rose by a mere 1% during sunny periods but increased by 15% outside of those hours when solar output was unavailable.

This growing divergence, Eurelectric reports, highlights a clear gap in system flexibility. Specifically, the grid lacks sufficient storage, demand response and cross-border interconnectors at the scale necessary to balance daily supply fluctuations. As solar output declines in the evening, power systems continue to rely on gas, tying consumer power costs to volatile fuel markets during morning and evening peaks. Parallel difficulties emerged in the Nordic region, where lower hydro volumes, weaker wind generation and infrastructure maintenance raised electricity prices well above levels recorded in 1H2025.

‘The challenge now lies in flexibility,’ Ruby said. He noted that infrastructure must be flexible enough to respond to changing weather conditions. ‘Even as Europe becomes less exposed to fossil fuel shocks, its power system remains vulnerable when weather conditions are unfavourable and flexible low-carbon capacity is insufficient.’

On a national level, Belgium provides a clear example of how cross-border infrastructure can strengthen security of supply when domestic assets face constraints, reports Eurelectric. With its entire nuclear fleet remaining unavailable from April-end-June due to maintenance, Belgian electricity generation fell by 23% year on year over the April-June period. Yet consumer demand increased by 7%, while net imports into the country increased by 150%. Cross-border interconnections, therefore, acted as an important source of flexibility. For example, Eurelectric data shows that this structural grid network allowed Belgium to draw on neighbouring regional generation sources to balance the system, maintaining security of supply despite a major loss of domestic generation capacity.

Looking ahead, Ruby stated that ongoing infrastructure investment is needed to stabilise prices throughout the entire year.

‘Investment in grids, storage, demand response and other low-carbon flexible capacity will be essential to manage periods of low wind, hydro or solar availability, strengthen security of supply and keep electricity prices under control’, he concluded.

Too often, people’s energy bills are driven by global price volatility and international instability. That has real consequences for communities managing the cost of living, businesses facing rising costs and consumers paying some of the highest electricity prices in Europe.

These pressures bring the energy trilemma into sharper focus: how we balance security of supply, affordability and sustainability for consumers. Right now, security and affordability are understandably front of mind.

But this is not a zero-sum trade-off. The path to a cleaner energy system in Great Britain is also the most credible path to a more secure and more affordable one.

Scaling up cleaner, homegrown power reduces our exposure to volatile fossil fuel markets. That strengthens security and improves affordability over time. Investing in networks and flexibility improves resilience while enabling more sustainable generation. Well-designed markets can also help ensure those benefits are passed on to consumers.

NESO was established as an independent body to help balance the trilemma in the interests of consumers. We operate today’s electricity system and help plan tomorrow’s, working with government, the regulator, industry and communities across Great Britain. Three priorities stand out.

The path to a cleaner energy system in Great Britain is also the most credible path to a more secure and more affordable one. 
 

Delivering at pace

The immediate priority is clear: deliver the transformation of our energy system at pace.

There is real progress to build on. Record offshore wind auction results. More grid infrastructure being built. New highs in renewable generation. A new zero carbon operation record earlier this year.

These are not just milestones. They are practical steps towards a system that is less exposed to shocks, more stable in price, and better for consumers.

Recent events confirm we are on the right path. Now we need to go further, faster, together. Every project delivered, and every reform completed, can be a step in the right direction for consumers.

Connections reform is central to this. The previous system was not fit for purpose. The new pipeline could unlock around £40 billion of investment each year, support large-scale electrification and help build the industries of the future — while reducing long-term exposure to global price shocks. 

Over half of the offers needed for 2030 have now been issued, and NESO continues to work at pace with customers. At the same time industry is progressing with building out the network we need to connect more clean power to the grid.

Reforming the energy market will also play a key role. Markets that better reflect how the system operates can respond more efficiently to changes in supply and demand. That improves resilience and reduces avoidable costs for consumers. We are working with government and Ofgem to shape Reformed National Pricing as part of this.

Faster, visible delivery — in step with industry — is the most direct way to demonstrate progress and help make tangible the benefits of the transition for consumers.

Data and AI: improving outcomes for consumers

A better energy system will depend not just on what we build, but how we operate it. 

Consumers are no longer passive users of energy, their choices now shape demand in real time. Responding effectively requires a system that is connected, adaptive and responsive by design. That means moving beyond siloed infrastructure to interoperable systems, where data can flow securely and consistently across organisations, to enable faster, smarter decisions.

Data is the foundation for this. Used well, and combined with AI and advanced analytics, it improves decisions across the system — from long-term planning through to real-time operation. It helps reduce inefficiencies, strengthen reliability and lower costs for consumers. 

It also supports a more flexible system. Digital twins, predictive maintenance and smarter network management help manage growing complexity while maintaining security of supply at the lowest possible cost. 

But the value of data and AI depends on coordination. Without common standards, we risk fragmentation, duplication and higher costs. Interoperability — technical, semantic and organisational — is essential to unlock the full benefits. 

At NESO, we recognise that leadership in this space is essential. We are exploring the role of a digital co-ordinator for Great Britain to provide clear accountability for how digital infrastructure supports the physical system. This includes setting standards for interoperability, enabling secure data sharing, and ensuring that AI can be deployed safely, ethically and at scale. Alongside this, we will publish an initial shared digital vision and architecture for the sector, developed with industry. 

Together, these steps will help ensure digital capability delivers a system that is more resilient, more efficient and more affordable.
 

Planning the whole system

Energy can be complex. But the reasons for improving it are simple. Better places to live. Lower costs. More local jobs. And cleaner air for kids and grandkids to breathe.
 

Delivering the energy transition requires a broader approach to planning. It means looking across the whole system at how generation, networks, storage and demand interact, and recognising how decisions in one area affect another.

This is what we mean by a whole-system approach. As an independent body, NESO is well placed to take that view, bringing together evidence from across the energy system to support better-informed decisions.

Our strategic energy plans are central to that work. They will set out what we need, where we need it and by when, looking ahead to 2050 and beyond. They will align national, regional and network priorities, provide a clearer framework for investment, and give communities a stronger voice in shaping new infrastructure.

Done well, they will help keep the trilemma in balance over the long term. They will strengthen resilience while coordinating the growth of clean power with the infrastructure needed to support it.

These plans are being developed with stakeholders across the sector and we will consult on them over the next two years. Options for future energy generation and storage will be presented to the UK government in 2026, ahead of the first public consultation next year.

Staying the course

When I was younger, I trained with the Royal National Lifeboat Institution. It taught me that when conditions are uncertain, stay calm, trust the plan and keep moving forward. That is where we are today.

The energy trilemma continues to define Great Britain’s energy transition. By focusing on delivery, making better use of data and planning the system as a whole, we can keep security, affordability and sustainability in balance for consumers.

At NESO we recognise that the energy system serves people, businesses, society and the economy and we are committed to working with with all stakeholders across all regions and nations to ensure we have the right priorities and ultimately the best energy system for Great Britain.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘UK government rules out move to zonal pricing for electricity market’. Discover more about the debate around zonal pricing.
• ‘Can the UK rewire its energy future?’. At the recent All-Energy conference in Glasgow, Scotland, industry leaders warned that UK electricity network upgrades, supply chains and investment must keep pace with the transition if the country is to capture the benefits of growing renewable generation while shielding consumers from future energy shocks.  

The programme, based on GE Vernova Hitachi’s 300MWe-capacity BWRX-300 reactor design, would have a combined capacity of 4.2GW. According to SGE, it could generate enough electricity to meet around 11% of UK power demand, equivalent to powering almost eight million homes for at least 60 years.

Under the plans, one site would host six SMRs, with two further locations accommodating four reactors each. SGE has established SGE SMR UK Limited as its dedicated UK project company.  

The announcement follows recent progress by Rolls-Royce SMR, which earlier this year signed an agreement with Great British Energy – Nuclear to develop three reactors at Wylfa in North Wales. The two projects illustrate how Britain’s emerging SMR market is beginning to encompass different reactor technologies and commercial models.

The plans also build on regulatory progress already achieved by the BWRX-300. In December 2025, the reactor design completed Step 2 of the UK’s Generic Design Assessment, with the Office for Nuclear Regulation, the Environment Agency and Natural Resources Wales concluding that there were no fundamental safety, security, safeguards or environmental protection shortfalls that would prevent its deployment in Great Britain.

The proposal also differs from the government’s first SMR deployment programme, with SGE describing its approach as privately financed and commercially led, with no costs falling on consumers before the reactors begin operating.

In addition, it would be the UK’s first nuclear fission reactors featuring a boiling water reactor (BWR) design, which was created in the US, where it found greatest popularity. Unlike pressurised water reactors, these do not separate the reactor vessel from the steam turbine, so water boils in the reactor and is sent directly to the turbine.

Programme partners include GE Vernova Hitachi Nuclear Energy, Samsung C&T, Laing O’Rourke, Aecon, Fermi Development and Etara.

Construction of the first BWRX-300 reactor is already under way in Canada, where the design is expected to become the first SMR to enter commercial operation in an OECD country.

Rafał Kasprów, SGE Chief Executive, said: ‘Standardisation, repetition, modularisation and a fleet deployment strategy are the most effective ways to deliver new nuclear projects successfully, reducing costs, construction risk, and delivery times.’

SGE expects the project to enter the Advanced Nuclear Pipeline later this year, with site selection and government support discussions planned for the first half of 2027. Subject to approvals, the company is targeting first commercial operation in 2034. 

Power-to-X technologies use renewable electricity, including surplus generation that might otherwise be curtailed, to produce hydrogen, synthetic fuels and other low-carbon energy products for sectors that are difficult to electrify.

In Denmark, European Energy has begun hydrogen production at its Måde Power-to-X facility following the commissioning of a 5MW Plug Power electrolyser, which complements an existing 3.1MW electrolyser at the site. The installation is expected to produce around 550 tonnes of renewable hydrogen each year.

Rather than operating as a conventional renewable energy project, Måde combines wind generation, battery storage, hydrogen production and district heating through a single integrated energy system. Surplus renewable electricity can either be stored in batteries or converted into hydrogen, while waste heat from electrolysis is supplied to the local district heating network.

Meanwhile, in Germany, Ineratec’s Era One facility has become the first Power-to-Liquid plant in the world to receive ISCC (International Sustainability and Carbon Certification) EU certification under the Renewable Energy Directive. The certification means synthetic fuels produced at the site are recognised as Renewable Fuels of Non-Biological Origin (RFNBOs), allowing them to count towards European Union targets in transport, aviation and industry.

ERA ONE, located at Industriepark Frankfurt-Höchst, produces up to 2,500 tonnes of synthetic fuels each year. According to INERATEC, the certification confirms the fuels are derived entirely from renewable, non-biological sources and achieve lifecycle greenhouse gas emissions at least 70% lower than conventional fossil fuels. The plant uses electricity from renewable sources to run an electrolyser to produce hydrogen and oxygen. The site process uses hydrogen and carbon dioxide to create synthetic fuels and other materials.

The certification comes as the European Union begins introducing RFNBO targets under the Renewable Energy Directive, reinforcing demand for renewable hydrogen and synthetic fuels in sectors including aviation, transport and industry.

René Alcaraz Frederiksen, Executive Vice President and Head of Power-to-X at European Energy, described the Måde facility as an important advance in bringing Power-to-X projects into operation. He said: ‘Projects like this demonstrate how PtX can be implemented in practice and support the continued development of Europe’s hydrogen market.’

Tim Böltken, Chief Executive and Co-Founder of Ineratec, said: ‘This milestone shows that regulation, certification and industrial production are finally starting to come together.’

At the most basic level, batteries are composed of an anode, a cathode and an electrolyte. As a lithium-ion battery goes through each charge and discharge cycle, lithium ions shuttle from the anode to cathode and back again. This causes the battery to expand and contract.  

To address this, the research team built a device that squeezes a type of battery known as a pouch cell using pneumatic ‘bellows’ – air-filled cushions that function as a self-adjusting clamp. The bellows maintain a continuous pressure, while a sensor monitors tiny volume changes as the battery charges and discharges.  

The findings show that the pressure must remain within a narrow ‘Goldilocks’ range, with the team identifying an optimal level of around 12.5 bar. Deviations from this range were found to accelerate degradation: excessive pressure led to lithium plating on the anode, while insufficient pressure caused cracking in the cathode.

‘We found that when you keep the pressure on them relatively constant throughout each charge and discharge cycle, it’s much better for the overall lifetime of the battery,’ said Professor Michael De Volder, from Cambridge’s Department of Engineering, who co-led the research. ‘If you press too hard, the anode is unhappy. If you don’t press hard enough, the cathode starts degrading.’

It is hoped that longer-lasting electric vehicle (EV) batteries could reduce the volume of raw materials that need to be mined to produce new batteries. ‘We’ve produced a solution for cleaner electric cars, but we have to make sure that on the back of it, we are not creating new ecological disasters in other parts of the world,’ said De Volder. ‘If we can reduce the pressure on these mining operations a bit, that would be another important benefit.’

The technology has been tested at laboratory scale but will need to be scaled up to represent commercial battery applications.  

The research was supported in part by the European Research Council, the Faraday Institution and the Engineering and Physical Sciences Research Council, part of UK Research and Innovation.

The report estimates that 167bn m3 of gas was flared during the year, a 6% increase on 2024. The gas burned was worth an estimated $54bn and was equivalent to Africa’s total annual gas consumption.

Gas flaring contributes significantly to greenhouse gas emissions. The report estimates that flaring in 2025 generated around 389mn tCO2e, including methane released through incomplete combustion. It says gas that could otherwise support energy security or economic development is instead being burned at the wellhead rather than captured for productive use.

The report asserts that technologies to capture and use associated gas are already widely available. Progress remains constrained in many producing regions, however, by limited pipeline and processing infrastructure, insufficient investment, underdeveloped gas markets and inconsistent regulatory frameworks.

It also found that flaring increased faster than oil production during 2025, indicating that recent progress in reducing flaring intensity has stalled. However, the report points to some positive examples, including Kazakhstan, which has reduced flaring by 87% since 2012. The US has also curtailed flaring, with new pipeline infrastructure contributing to the largest absolute reduction in flaring during 2025. The report says such examples prove sustained policy and infrastructure investment can deliver significant improvements.

The report was published as international attention turned to methane emissions. Speaking during London Climate Action Week, UN Secretary General António Guterres launched a global call for faster action, saying methane is responsible for around one-third of global warming and that 70% of methane emissions from the oil and gas sector could be eliminated using existing technologies, much of it at low or no net cost. He also called for governments to adopt a new global standard of near-zero methane emissions across the oil and gas value chain.

Industry groups also welcomed the renewed focus. The Oil and Gas Climate Initiative (OGCI) said its member companies had collectively reduced methane emissions by 63% since 2017 and routine flaring by 72% since 2018. The organisation said these reductions demonstrate that large-scale progress is achievable through improved monitoring, operational practices and collaboration.

Despite mature standards and well-understood hazards, process safety is too often treated as a documentation exercise rather than a design discipline. The industry does not lack the tools to address this problem. What it lacks is ownership. Unless project developers take explicit responsibility for defining process safety requirements, critical risks can remain unaddressed.

Piloting and industry collaboration have done much to improve the efficiency and financing of clean hydrogen. In my experience, the discipline of process safety has not kept pace.

This is not to say that the industry is operating in the dark. Hydrogen is one of the best-understood industrial materials, having been used for well over a century in town gas, chemical and process applications. The standards, methodologies and regulatory frameworks needed to manage it safely are mature and readily available.

What I often see is uncertainty across the supply chain about what process safety actions should be taken and, crucially, who is responsible for taking them. The result is an accountability gap that can leave important risks unaddressed.

Understanding the role of electrolyser process safety
Process safety, which aims to prevent and control major industrial accidents, remains one of the most widely misunderstood engineering disciplines, even among experienced engineers. That challenge will only grow as the hydrogen sector expands. DNV predicts that clean hydrogen production will increase 100-fold by 2060, helping to mitigate more than 2Gt of annual emissions from sectors that are difficult to electrify.

A 2023 study by the Institute of Sustainable Process Technology identified the need to maintain process safety across design, construction and operational phases as one of the industry’s key challenges.

Every process safety assessment starts with identifying hazards. Once hazards have been recognised and understood, the safeguards needed to manage them can be defined. Documentation, standards and assessment methods come afterwards, providing evidence that those safeguards have been specified and implemented.

Process safety is often reduced to a compliance exercise. An organisation may produce a Hazard and Operability (HAZOP) study and a full suite of process safety documentation but still be unable to explain which hazards those documents are intended to address. Producing documentation is not the same as understanding and managing risk.

Identifying the ownership gap
Responsibility for process safety often becomes blurred as projects move from design into procurement and delivery. Developers typically assume process safety is embedded within the systems delivered by manufacturers and engineering, procurement and construction (EPC) contractors. Manufacturers and EPC contractors, in turn, rely on developers to define the process safety requirements they are expected to meet.

This is not a question of intent. Every party is working to deliver a safe, successful project. But procurement specifications define what suppliers are expected to deliver. If process safety requirements are not clearly specified at that stage, they are unlikely to form part of the final delivery.

What I see is a systemic accountability gap, and one that poses real risks to project performance, asset integrity and ultimately human safety.

Many organisations still approach safety primarily as an engineering problem to be solved, producing the documentation needed to satisfy customer requirements or achieve certification, rather than as a discipline that should shape the design of a project from the outset.

Procurement is where responsibility can be exercised most effectively. Project developers ultimately carry the operational, commercial and legal consequences of a safety failure. They therefore have both the greatest exposure and the greatest influence. Procurement specifications should clearly define the process safety evidence expected from manufacturers and EPC contractors rather than relying on whatever information suppliers choose to provide.

There is a systemic accountability gap, and one that poses real risks to project performance, asset integrity and ultimately human safety.

Understanding electrolyser-specific risks
Documentation can address many common hazards, but electrolyser-specific risks are still often overlooked. Effective process safety follows a clear sequence:

• Identify hazards – pinpoint what can go wrong.
• Define safeguards – determine how escalation will be prevented.
• Demonstrate performance – provide evidence that those safeguards are effective.

Hydrogen understandably attracts most attention, but substantial volumes of high-concentration oxygen, for example, are often treated as a secondary hazard. Many organisations still assume oxygen presents little risk because it is unlikely to ignite under their operating conditions and any release will simply disperse into the atmosphere.

This assumption overlooks an important hazard. High-concentration oxygen requires strict material selection because contaminant particles within an oxygen stream can become self-combustible. Materials that perform safely under normal atmospheric conditions can also degrade rapidly when exposed to oxygen concentrations beyond those for which they are certified.

Safeguards illustrate the wider problem. One common example is cell stack monitoring, where sensors monitor the operating condition of the electrolyser stack, triggering alarms or shutdowns if abnormal conditions are detected. These systems are often cited in documentation as safeguards against a range of failure modes. A monitoring system, however, can only be regarded as effective if rigorous testing has demonstrated that it can detect the relevant failure modes early enough to prevent harm. Unless developers require that evidence during procurement, suppliers are unlikely to provide it, leaving the effectiveness of the safeguard unverified.

Factory acceptance testing raises similar concerns. In many industrial sectors, a factory acceptance test means a system has been fully tested before leaving the manufacturer’s facility. Within the electrolyser industry, factory acceptance testing often consists of pressure testing to confirm there are no leaks together with electrical checks. This system is not operated under live production conditions, however, meaning an electrolyser can arrive on site without producing a single cubic metre of hydrogen. The first production run may therefore become the first meaningful demonstration that the system performs as intended.

Bridging the gap
Effective process safety should not begin with a list of standards or regulatory requirements. It should begin with a structured assessment by the project developer of what the system produces, what can go wrong and what the consequences would be.

Hazards must be identified before safeguards can be defined. Only then can the appropriate standards and verification methods be selected to demonstrate that those safeguards are effective.

Independent hazard assessment and verification help ensure that hazards are identified consistently, risk reduction measures are proportionate to the risks involved, and responsibilities are clearly allocated across developers, manufacturers and contractors.

Industry standards set out requirements for electrolyser design, construction and operation, together with methods for verifying that systems perform as intended. They also establish common approaches to defining system boundaries and assessing performance, allowing technologies to be evaluated on a consistent basis. DNV’s electrolyser safety and performance standards are one example of this approach.

Standards, however, cannot compensate for requirements that were never defined. Responsibility rests with the project developer to issue technically grounded procurement specifications that identify the hazards to be addressed, the safeguards required and the evidence needed to demonstrate that those safeguards will perform as intended. In a commercial environment where suppliers deliver against defined specifications, those requirements establish accountability across the supply chain.

Standards are already available. The challenge is ensuring developers define the hazards, specify the safeguards and require evidence that those safeguards will perform as intended. Until ownership of process safety is clearly defined, accountability gaps will remain, regardless of how much documentation accompanies a project.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Going beyond understanding ‘what went wrong’. Find out how the Energy Institute’s updated and expanded version of EI 3295: Reporting, investigating and learning from incidents, accidents and events, can make operations safer.
• ‘Is electrolyser technology good enough to build a large-scale hydrogen economy?’. Development of electrolysers which split water into hydrogen and oxygen will be critical to achieve net zero emissions by 2050. In particular for decarbonising hard-to-abate industries, with electrolysis powered by renewable energy. Although electrolysis capacity is growing from a relatively low base today, discover why there is need for significant acceleration to reach the net zero target.
   

Europe’s energy problem is not a supply problem
Europe’s vulnerability to energy crises stems largely from a long-standing reliance on imported fossil fuels, exposed during the post-pandemic recovery and intensified by geopolitical instability. When gas storage was depleted and wholesale spot markets were manipulated, prices surged, threatening both household budgets and industrial competitiveness. More recently, disruption affecting key global energy trade routes has highlighted how closely Europe remains tied to events beyond its borders.

The consequences extend beyond energy security alone. Volatile energy prices continue to affect the cost of living, industrial investment and Europe’s ability to compete internationally. While the continent may not rely directly on every region affected by geopolitical tensions, global oil and LNG markets remain interconnected. A shock in one part of the world can quickly translate into higher costs across Europe.

The common assumption is that these challenges can be addressed primarily through the deployment of additional renewable generation. Expanding renewable capacity is essential, but it is not sufficient on its own. Our main finding is that Europe’s energy security, affordability and climate objectives share a common solution: energy system integration.

For too long, electricity, heating, transport and industry have been planned and operated largely as separate systems. That approach is becoming increasingly difficult to justify. As renewable generation expands, the challenge is no longer simply producing clean electricity. It is ensuring that energy can move efficiently between sectors, locations and users at the times it is needed most.

Recent modelling also shows that integrated systems are more cost-effective than approaches that consider sectors in isolation. Analyses that focus solely on electricity while overlooking heating, transport and industrial flexibility can produce misleading conclusions about both costs and security of supply. A more integrated perspective reveals opportunities that are otherwise missed.

Europe’s challenge is therefore broader than replacing one source of energy with another. It requires a more coordinated approach to how energy is produced, transported and used across the economy.

Europe’s energy security, affordability and climate objectives share a common solution: energy system integration.

The cost of planning in silos
The consequences of fragmented planning are becoming increasingly visible across Europe’s energy system. Grid congestion is growing, infrastructure development is struggling to keep pace with demand and significant price differences persist between markets. These are often treated as separate challenges, but they stem from the same underlying issue: a system that still plans electricity, heating, transport and industry largely in isolation.

The clearest example is the grid itself. As renewable generation expands, electricity must be transported across greater distances and used more flexibly than in traditional energy systems. Yet bottlenecks continue to restrict the movement of power between regions and markets. Without a doubling of grid capacity and interconnections, Europe risks limiting the value of the renewable energy it is already deploying.

Planning in silos can also distort how policymakers assess energy security. Models that focus solely on electricity generation often overlook sources of flexibility elsewhere in the system. As a result, they can overstate constraints and underestimate opportunities to balance supply and demand more efficiently.

Transport illustrates this shift. Electrification is commonly discussed as a decarbonisation strategy, but it also strengthens energy security by reducing dependence on imported oil. At the same time, smart and bidirectional charging technologies create new opportunities for flexibility. Millions of electric vehicles (EVs) could help balance the grid by storing electricity when renewable generation is abundant and returning it when demand increases.

Buildings offer similar opportunities. Through thermal storage, smart controls and heat pumps, homes and commercial properties can become active participants in the energy system rather than passive consumers. Demand can be shifted to periods of high renewable generation, reducing pressure on the grid and lowering overall system costs.

Viewed individually, these developments may appear incremental. Taken together, they point towards a different way of organising the energy system. Electricity networks, buildings, transport and industry become increasingly interconnected, creating new sources of flexibility and reducing reliance on imported fuels.

The technologies needed to support this transformation already exist. Progress now depends on whether market structures, regulatory frameworks and infrastructure planning can evolve quickly enough to unlock their full value.

Seven priorities for an integrated energy system
If Europe is to move beyond fragmented energy planning, policymakers will need to focus on a series of practical priorities. These are not separate objectives. Together, they form the foundations of a more integrated, secure and efficient energy system.

• Put energy efficiency at the centre of system design – Energy efficiency is often treated as an afterthought. It should instead be recognised as a ‘no-regrets’ option that underpins energy security, affordability and sustainability. Lowering overall demand reduces pressure on grid infrastructure and decreases the scale of investment required in new cables, substations and generation assets. Energy efficiency is about more than using less energy. It makes the entire system smaller, smarter and easier to manage.
• Protect the digital infrastructure underpinning integration – Digitalisation is the nervous system of an integrated energy model. It enables load matching, storage optimisation and the coordination needed to manage variable renewable generation. As reliance on digital tools increases, so too does exposure to cyber threats. Protecting information and communication technology infrastructure must therefore be viewed as a core element of energy security.
• Accelerate the adoption of time-of-use pricing – Managing variable wind and solar generation requires greater flexibility on the demand side. Time-of-use tariffs can help align consumption with periods of abundant renewable generation, encouraging households and businesses to use electricity when renewable output is high and wholesale prices can fall to very low levels. In many member states, these pricing mechanisms remain underdeveloped. Expanding them would help unlock the demand response needed for a more integrated system.
• Strengthen cross-border interconnections – Europe’s existing interconnections remain insufficient to support the movement of growing volumes of renewable electricity. Stronger cross-border links would help ease congestion, improve market efficiency and allow surplus generation in one region to be used more effectively elsewhere. A truly integrated energy system requires infrastructure capable of connecting renewable resources, industrial demand and consumers across national boundaries. Progress will also need to be measured more consistently. Independent monitoring and transparent, data-driven assessments can help identify where member states are falling behind on priorities such as grid expansion, interconnection capacity and tariff reform, providing greater accountability for implementation.
• Remove incentives that favour fossil fuels – Many European markets still contain subsidies and incentives that favour fossil fuel consumption. These measures can slow investment in energy efficiency and renewable technologies while prolonging dependence on imported fuels. Policymakers cannot expect to accelerate the transition while continuing to support elements of the system they are seeking to replace.
• Embed energy justice into the transition – A just transition is not a secondary consideration. It is a prerequisite for success. The growth of rooftop solar, batteries, EVs and heat pumps is enabling citizens to become active energy consumers who can generate, store and manage their own energy. This can strengthen resilience and reduce exposure to price shocks. However, market complexity must not become a barrier to participation. Public acceptance depends on ensuring that the benefits of integration are widely understood and widely shared.
• Support vulnerable households through electrification – The transition cannot become a luxury available only to those who can afford the upfront cost of technologies such as heat pumps and EVs. Targeted support for lower-income households will be essential if electrification is to occur at the pace required. Broad participation strengthens both the social legitimacy and long-term durability of the transition.

These priorities provide a practical framework for translating the principles of energy system integration into policy action. They would help create a system that is better able to withstand future shocks while improving affordability, security and long-term competitiveness.

Integration is now a competitiveness issue
Energy system integration is about more than security and decarbonisation. It is increasingly becoming a question of economic competitiveness.

Our findings show that integration provides the most credible pathway towards achieving the objectives of the EU’s Clean Industrial Deal. We are moving towards a future in which electricity becomes cheaper than gas, and industries that electrify early are likely to gain a significant competitive advantage. This is about more than climate policy. It is about industrial survival in an increasingly competitive global economy.

The transition also creates an opportunity to develop new industrial clusters built around clean technologies and circular economy principles. By integrating energy efficiency and renewable energy into industrial planning, Europe can create high-tech hubs that strengthen innovation, attract investment and support long-term economic growth. Advances in sustainability are increasingly becoming drivers of industrial leadership.

Achieving this transformation will require long-term confidence from investors. Major infrastructure projects require stability over decades, not years. Policymakers therefore need to establish credible frameworks that provide certainty for grid expansion, electrification and industrial decarbonisation. Long-term investment becomes far more difficult when policy direction changes or implementation stalls.

Local energy planning also has an important role to play. By integrating multiple energy supplies, carriers, infrastructures and consumption sectors, communities can make better use of energy that might otherwise be wasted. Greater coordination at the local level helps unlock efficiencies that are often overlooked when systems are planned separately. This is the essence of integration: creating value through stronger connections between sectors.

As energy systems become smarter and more interconnected, the role of the consumer will continue to evolve. In the traditional model, consumers were largely passive recipients of energy. In a more integrated system, households and businesses become active participants through flexible demand, distributed generation and storage. Energy markets will need to adapt accordingly, placing greater value on flexibility and reliability services alongside energy supply itself.

Europe already possesses the technical expertise and much of the economic evidence needed to support this transition. The question is whether implementation can proceed at the pace required. Continued fragmentation will leave consumers and businesses exposed to many of the same vulnerabilities that have characterised recent energy crises. A more integrated approach offers a pathway towards a cleaner, more secure and more competitive future.

*The European Academies' Science Advisory Council (EASAC) is a network of national science academies in Europe.

The views and opinions expressed in this article are strictly those of the authors only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Modern grids will be the foundation for future growth in Europe’. As Europe seeks to strengthen energy security, stimulate sustainable growth and affordability, and reduce emissions, accelerating electrification and investing in modern grid infrastructure must become urgent priorities, writes Maxine Ghavi, Executive Vice President and Head of Europe at Hitachi Energy.
• ‘Local plans and energy infrastructure: an integrated delivery model’. The Local Plan process, and the wider planning system in the UK, could do more to give greater, enduring certainty as to where energy development is suitable in a Local Plan area, writes Anthony Greally, Head of Advanced Energy at planning consultancy Lichfields.
   

Wood Mackenzie’s analysis concludes that the EU is unlikely to achieve this target even if every storage project currently in advanced development proceeds as planned.  

No single part of the system can scale independently, says the market analyst. Storage developers require committed capture projects before investing, capture operators need transport infrastructure and storage agreements before making final investment decisions, while transport networks depend on sufficient CO2 volumes to justify investment. Without progress across the whole system, individual projects risk stalling, it warns.

Wood Mackenzie notes that the NZIA aims to overcome the long-standing ‘chicken-and-egg’ challenge facing carbon capture and storage (CCS) by encouraging storage capacity ahead of demand. However, it says the policy has created a new challenge, with storage developers expected to commit investment before enough capture projects, transport infrastructure and commercial agreements are in place to support long-term deployment.

The scale of the challenge is reflected in the numbers. Less than 6% of the EU’s targeted storage capacity is currently operational or under construction, while only 4mn t/y of capture capacity has reached final investment decision and is contractually linked to storage. Meeting the 2030 target would require a fivefold increase in storage investment decisions between 2026 and 2028, suggests the market analyst.

Commercial conditions also remain challenging. Wood Mackenzie says that while the EU Emissions Trading System provides an incentive to reduce emissions, carbon prices remain below the cost of deploying CCS for many projects approaching final investment decision. Combined with split ownership, uncertain project economics and delays averaging around 1.5 years across EU storage projects, these factors leave an estimated 11mn t/y of planned capture capacity at risk of becoming stranded, it warns.

Despite these wider challenges, companies continue to invest in technologies designed to strengthen individual parts of the carbon capture system. One example is Air Liquide’s new industrial-scale carbon capture pilot at Holcim’s CaptureLab in France.

The pilot uses Air Liquide’s Cryocap FG technology, developed specifically for the cement industry. Cement production is among the hardest industrial sectors to decarbonise because many of its CO2 emissions result from the production process itself rather than fuel combustion. Technologies capable of capturing these process emissions are expected to play an increasingly important role in reducing industrial emissions in the future.

Built using a modular design, the pilot plant pre-treats flue gas before CO2 purification. It can be relocated to other industrial sites following its initial deployment, supporting wider deployment of the technology, according to Air Liquide.

Projects such as Air Liquide’s demonstrate continued progress in carbon capture technology. However, Wood Mackenzie concludes that meeting the EU’s carbon storage ambitions will depend on coordinated development across capture, transport and storage infrastructure rather than advances in any single part of the value chain. It suggests the EU’s ability to scale CCS will depend as much on linking capture, transport and storage through shared infrastructure and commercial agreements as on continued progress in capture technology itself. 

E.On’s flexible connection standard was developed with battery storage company Eco Stor and tested at its Bollingstedt project in Schleswig-Holstein before being adopted more widely.

The change comes as demand for battery storage connections continues to grow. E.On has already committed to connecting around 25GW of BESS capacity and has received requests for a further 500GW, equivalent to around six times Germany’s current peak electricity demand.  

Other companies are also preparing for larger deployment. Energy infrastructure developer NatPower and Tesla have signed a strategic agreement covering more than 25GWh of battery energy storage systems across Europe. The agreement forms part of NatPower’s wider battery storage programme, which aims to deploy up to 100GWh of capacity across several European markets over the coming years.

Battery storage is becoming more important as Europe’s electricity system changes. As more renewable generation comes online, electricity networks need greater flexibility to balance supply and demand throughout the day. Batteries are well-suited to that role because they can store surplus electricity when generation is high before supplying it back to the grid as demand rises.

Batteries can also relieve pressure on electricity networks, reduce the need for some grid reinforcement and provide services traditionally supplied by gas-fired power stations. As deployment grows, the speed at which new capacity can be connected and integrated into the electricity system is becoming a more important consideration.

Energy think tank Ember forecasts the EU’s battery fleet will grow from 43GW in 2025 to 178GW by 2030, with utility-scale projects accounting for most of the expansion. In a recently published report it argues that battery storage will play a growing role in balancing electricity supply and demand as larger volumes of renewable electricity come onto the grid.

Ember also estimates that by 2030 Europe’s battery fleet could provide more than 80% of the hourly power output currently available from EU gas-fired power stations. The report concludes that batteries are among the lowest-cost options for providing short-term system flexibility.

Battery storage is no longer defined simply by individual projects. Connecting enough new capacity to support Europe’s changing electricity system is becoming just as important as developing the technology itself, suggests the report.

'This project is a milestone not only for CRC but for Europe's wider energy transition,' said Henk de Graaf, Director at CRC Evans. It forms part of the North Adriatic Hydrogen Valley (NAHV) programme, which spans Slovenia, Croatia and Italy’s Friuli Venezia Giulia region.  

The NAHV is the first transnational hydrogen valley initiative to secure European Union backing, with EU funding covering around 7.3% of the €345mn project cost. The balance has been raised through the Northern Adriatic Clean Hydrogen Investment Platform and contributions from industrial partners. Launched in September 2023, the initiative is due to complete in August 2029.  

The programme aims to demonstrate cross-border integration of hydrogen production, distribution and consumption, facilitating the transport of more than 20% of the three participating countries' targeted 5,000 t/y of hydrogen output.

NAHV will launch 18 testbed applications across the hard-to-abate, energy and transport sectors, replacing fossil fuels with pipeline-delivered hydrogen. These applications will progress from Technology Readiness Level 6 to Level 8 by project completion, transitioning from localised pilots to fully qualified commercial operations. Four fuel-cell applications will also be demonstrated in the energy and transport sectors to test hydrogen-to-electricity conversion efficiency and reliability under real-world conditions.

The findings are expected to inform infrastructure design and regulatory frameworks for subsequent regional networks, with at least five additional hydrogen valleys planned across central and southeastern Europe.

The initiative sets out a target to increase the share of electricity in global energy demand from around 21% today to 35% by 2035 – requiring progress at roughly four times the current pace. The goal is based on IEA and IRENA analysis.

Electrify Now will prioritise key sectors including transport, industry and buildings, alongside enabling measures such as grid modernisation, energy storage expansion and supply chain development. It also aims to strengthen cooperation between governments and businesses, support project sharing and mobilise investment, particularly in emerging and developing economies.

The summit brought together representatives from Australia, Brazil, Colombia, Ethiopia, the Netherlands, Türkiye (Turkey) and the EU, alongside UN Secretary-General António Guterres.

Industry groups welcomed the initiative. The Global Wind Energy Council said electrification would significantly expand opportunities for wind and other renewable technologies. Its CEO, Ben Backwell, called electrification ‘the number one priority for every decision-maker today’.

Alongside the launch, more than 100 companies – including Iberdrola, Ikea, Levi Strauss, Nestlé, Nikon, Uber and Volvo Cars – called on governments to place electrification at the centre of economic and industrial strategy. Coordinated by the We Mean Business Coalition and the Global Renewables Alliance, the group, which represents a combined annual revenue of more than $1.5tn, is advocating for faster policy action to accelerate electrification globally.

Separately, UK Energy Secretary Ed Miliband confirmed that more than £100bn in clean energy investment has been announced in the UK since the current government took office. This year’s renewable energy auctions alone have mobilised £27bn, with offshore wind, solar power and grid infrastructure accounting for the bulk of planned investment, he said. The funding is expected to be distributed across all UK regions and includes both domestic and international capital.

Developed by Pattern Energy, the project comprises 916 turbines across three counties in central New Mexico. At 3.65GW, it is the largest wind project in the US, significantly exceeding the scale of other major developments, including Alta Wind in California (1.1GW) and Great Prairie in Texas (1.03GW).

The project also includes a ±525kV voltage source converter (VSC)-based high-voltage direct current (HVDC) link supplied by Hitachi Energy. Electricity is converted to direct current for efficient transmission over long distances, before being converted back to alternating current for grid integration.

Power is transmitted into Arizona and then routed into Southern California via the Palo Verde hub, with around 2.13GW expected to reach the California grid.

At full capacity, SunZia is expected to supply approximately one million homes annually, supporting growing demand driven by electrification, data centres and industrial expansion. The transmission system also enhances grid flexibility, allowing operators to respond quickly to demand peaks, particularly when solar generation declines in the evening.

The development significantly expands New Mexico’s wind capacity, increasing it from 4GW to 7.65GW and raising wind’s share to around 45% of the state’s energy mix.

SunZia is expected to avoid around 9mn t of CO₂ emissions annually.

LDES refers to technologies capable of storing electricity for eight hours or more. These include pumped hydro storage, flow batteries, compressed air energy storage and liquid air energy storage. The analysis focuses on emerging storage technologies rather than pumped hydro, which is already widely deployed across Europe.

According to the report, LDES market overview – what is the outlook for innovative LDES in Europe?, higher levels of wind and solar generation are creating more periods of surplus electricity production alongside periods when renewable output falls short of demand. LDES can help address both challenges by storing electricity when supply is abundant and releasing it when it is needed.

Researchers found that storage can reduce renewables curtailment, ease network congestion and lower balancing costs. It can also reduce reliance on flexible fossil fuel generation during periods of lower renewable output.

Kristian Ruby, Secretary General of Eurelectric, said the emergence of a stronger commercial case for long-duration storage reflected the growing need for flexibility across Europe’s electricity system. ‘Europe’s energy transition needs technologies that can cover the increasing need for flexibility in the power system. It is encouraging that a business case is beginning to emerge for innovative long-duration energy storage with substantial system benefits: less curtailment, lower operating costs, reduced congestion and greater security of supply,’ he commented.

The analysis found that LDES addressed different challenges in different markets. In some countries, revenue opportunities are driven primarily by energy trading, allowing operators to store electricity when prices are low and release it when prices rise. Elsewhere, the main value comes from helping system operators manage congestion and maintain grid stability.

The findings come as policymakers seek ways to integrate growing volumes of renewable generation while maintaining reliability and controlling system costs.

In the UK, the energy regulator Ofgem is assessing projects under its cap-and-floor support scheme for LDES, which aims to balance the power system. Last year, Ofgem confirmed that 77 projects had progressed to the final assessment stage of the scheme, covering technologies including flow batteries, lithium-ion batteries, compressed air energy storage and pumped hydro.

Investment in large-scale storage projects is also gathering pace. In September 2025, Fidra Energy reached financial close on the 1.4GW Thorpe Marsh battery energy storage project in South Yorkshire, which is expected to begin operating in mid-2027. More recently, in May this year Invinity Energy Systems completed the delivery of 20.7MWh of vanadium flow batteries (VFB) to the Copwood VFB Energy Hub at a site in Uckfield in East Sussex, which is set to become Europe’s largest VFB installation when it enters service later this year. The project pairs 90 VFBs, made in Scotland, with a 3MW solar array.

Danielle Portsmouth, Future Skills Manager at ORE Catapult, said the industry faced an urgent challenge to build the workforce needed to support future growth. ‘The UK is a global leader in offshore wind experience and installed capacity, attracting significant investment and playing a crucial role in the nation’s clean energy transition. However, without a clear focus on increasing the pipeline of skills and talent into the sector, we will not be able to maintain this position,’ she warned. ‘Without immediate action, the capabilities and capacity of our current workforce will be insufficient to achieve the UK’s 2030 targets in offshore wind.’

The ORE report identifies a range of specialist roles expected to be in growing demand, including wind turbine technicians, high-voltage cable specialists, installation engineers, fabrication specialists and electrical managers.

Researchers argue that education and training providers need to anticipate future technology requirements rather than focus solely on current vacancies. The report proposes a more forward-looking approach to skills planning, allowing training programmes to adapt more quickly as technologies evolve. Among its recommendations are the creation of working groups spanning industry and education, the appointment of sector champions for emerging technologies and greater collaboration on specialist training initiatives.

The report was sponsored by RenewableUK, which represents more than 500 companies operating across the renewable energy sector.

James Lord, Skills and Social Value Manager at RenewableUK, said the industry needed to act quickly to ensure workers entering the sector have the expertise required for future roles. ‘To maintain the UK’s world-leading position in offshore wind, we must ensure that our workforce has the right skills and capabilities as technology evolves,’ he said.

The report was published as major offshore wind projects continue to be built in UK waters. For example, RWE has just completed installation of all 100 turbines at its 1.4GW Sofia offshore wind farm, located more than 200km off the north-east coast of England. The final turbine was installed on 10 June with testing and commissioning work continuing before the wind farm becomes fully operational. Once completed, Sofia is expected to generate enough renewable electricity to power around 1.2 million UK homes. 

The trial reflects growing interest in technologies that can provide flexible generation alongside increasing volumes of wind and solar power. While renewable generation continues to expand, grid operators still need sources of dispatchable power when renewable output falls or electricity demand increases. Hydrogen is attracting growing interest because it can store surplus renewable electricity and be used later to generate power when needed.

Wärtsilä said the trial was designed to demonstrate that large-scale engine-based power generation can operate entirely using hydrogen rather than conventional fuels.  

Rasmus Teir, Director of Technology Strategy and Decarbonisation at Wärtsilä, said the test addressed one of the key challenges facing electricity systems with growing shares of renewable generation.  

‘As countries rapidly scale wind and solar energy, one of the biggest challenges facing the energy transition is how to maintain reliable electricity supplies sustainably during periods of low renewable generation or spikes in demand,’ he said. ‘Today, our Wärtsilä 31H2 hydrogen engine is operating on 100% hydrogen and supplying power to Spain’s national grid, demonstrating that large-scale low-carbon hydrogen engines can provide the flexible, dispatchable sustainable power needed to support future renewable energy systems.’

The Wärtsilä 31H2 is based on the company’s Wärtsilä 31 engine platform, which is used in both power generation and marine applications and offers a power generation capacity of between 4.6–10.4MW, depending on configuration. The company describes the 31H2 as the world’s largest pure hydrogen engine, with performance testing continuing at the Bermeo site.

The company contends that hydrogen-fuelled engines could eventually support a range of applications including power systems with high levels of renewable generation, industrial facilities and energy-intensive operations requiring flexible low-carbon power.

The trial does not mean hydrogen-based power generation is ready for widespread deployment, as the availability of low-carbon hydrogen, supporting infrastructure and project economics remain significant challenges. However, the demonstration provides evidence that large-scale hydrogen engines could become one option for balancing electricity systems as renewable generation continues to expand, notes Wärtsilä.

While pipelines are expected to play an increasingly important role as carbon capture networks expand, the report says shipping will remain a significant part of the market.

Shipping’s share of transported volumes is forecast to fall from 48% to 24% between 2030 and 2050, but the volume of CO2 carried by ship is still expected to more than double to 79mn t/y.

Ships are more flexible than pipelines, allowing captured emissions from multiple industrial sites to be gathered and transported to storage locations across Europe.

The Xodus analysis identifies the North Sea as the likely centre of Europe’s carbon storage industry, with the UK, Norway and the Netherlands expected to receive growing volumes of captured carbon from elsewhere on the continent.

A separate Xodus report forecasts that the Asia-Pacific region will become the world’s largest market for transporting captured carbon by sea. By 2055, the region could require more than 90 storage sites, almost 8,000km of pipelines and around 80 specialist carbon transport ships to support planned carbon storage activity.

Unlike Europe, where many industrial centres are relatively close to potential storage locations, parts of the Asia-Pacific face much greater distances between emitters and suitable geological storage sites. In some cases, those distances exceed 5,000km.

Japan and South Korea are expected to be among the largest sources of demand for carbon storage services despite having limited domestic storage options. The Xodus report forecasts growing demand for cross-border carbon transport and offshore storage infrastructure.

Simon Allison, Vice President APAC at Xodus, said the region was well placed for large-scale CCUS deployment: ‘While APAC [Asia-Pacific] currently trails areas like the North Sea in terms of deploying commercial-scale CCUS [carbon capture, use and storage] to serve industrial emitters, its large emissions footprint and operational experience in CO2 re-injection positions it to become a global hub for CCUS development in the decades ahead.’

The studies indicate that transporting captured carbon may become a major new shipping market, requiring fleets of dedicated vessels alongside new ports, pipelines and storage sites. 

While support for electrification was strong in both advanced and emerging economies, the survey suggests business ambition may be moving faster than the infrastructure development needed to support it.

Nearly seven in 10 respondents (69%) said businesses are electrifying their operations faster than governments are preparing power systems, while 63% said national power systems are not keeping up with demand. More than half (54%) named insufficient grid capacity as a barrier to electrification.

The findings are published in the report Powering up: business perspectives on electrification, which examines how businesses view the transition from fossil fuel-powered systems to electric alternatives.

María Mendiluce, Chief Executive of the We Mean Business Coalition, said repeated energy shocks had exposed the risks associated with fossil fuels and reinforced the business case for electrification. ‘Businesses are ready to throw the switch on a cleaner, better world that is more secure, prosperous and resilient,’ she said. ‘Governments need to catch up.’

Respondents linked electrification to energy security and competitiveness. Globally, 88% said electrification would make their business more competitive, while the same proportion said it would help their business grow. A further 84% expected electrification to reduce long-term operating costs and 80% said it would cut energy bills.

Those expectations are translating into ambitious electrification plans with 90% of business leaders surveyed expecting their operations to be largely electrified by 2035, including 73% who expect to reach that point by 2030.

Support was particularly strong in emerging markets such as Indonesia and Nigeria where 99% are expecting to electrify by 2035, while 96% of respondents in India and 97% in the Philippines said the same.

The results indicate a greater focus on commercial drivers than is often assumed. Respondents consistently linked electrification to lower costs, greater resilience to price shocks and stronger competitive positioning.

Businesses expressed little doubt about the benefits of electrification. The greater concern was whether grids and power systems would be ready to support it. Expanding and future-proofing electricity grids was identified as the single most important policy measure governments could take to accelerate the transition, with 43% selecting it among their top priorities. Overall, 89% supported investment in grid upgrades.

The report found that half (50%) of businesses had already delayed or cancelled projects because of market or policy barriers, including grid constraints and permitting delays, as well as the high upfront cost of replacing existing equipment.

More than eight in 10 respondents said investment in grid infrastructure would help make energy more affordable in the long term. Many respondents pointed to infrastructure and policy bottlenecks despite strong plans to electrify.

‘A gap is emerging between business ambition and the speed of infrastructure and policy delivery,’ the report states.

The concern appeared in different forms across major markets. In the US, 75% of business leaders said power systems were not keeping pace with electrification demand, while the figure was 80% in South Africa. In Indonesia, 83% said their companies were electrifying faster than the government was preparing the system.

The survey also points to growing concern about the economic consequences of slow progress on infrastructure and policy. Globally, 62% of respondents said they would consider moving operations to another country if their government did not provide sufficient support for electrification. Among businesses already operating internationally, the figure rose to 72%.

Access to reliable, affordable electricity appears to be playing a larger role in investment decisions. Countries that expand grid infrastructure and provide greater policy certainty may be better positioned to attract investment.

Conversely, delays to power system development could become a drag on competitiveness even where business demand for electrification remains strong.

Across the markets surveyed, support for electrification was closely tied to concerns about energy security and business costs. Many businesses now view access to reliable electricity infrastructure as an important factor in future investment decisions. For policymakers, attention may be shifting from encouraging electrification to ensuring electricity infrastructure can keep pace with demand.

For real estate investors, these geopolitical shocks translate directly to the balance sheet. Rising energy costs erode occupier affordability, increase operating expenses and affect property values.

In this environment, passive assets can become liabilities. Building resilience requires a shift from defensive risk management towards a broader focus on performance. Sustainability is no longer simply a compliance exercise. It has become an important driver of physical, financial and competitive performance.

Moving past data
Many property owners become trapped in the data collection phase, treating reporting as the finish line. While audit-ready data is essential for accurate risk modelling and compliance, data alone does not lower an energy bill or protect asset value. It is the starting point for action.

Leading organisations are increasingly moving beyond manual tracking and using digital tools to turn sustainability data into operational improvements. Rather than becoming absorbed in utility bills and reporting requirements, asset managers are using more accurate and timely data to identify opportunities for action.

By benchmarking performance across portfolios, investors can identify underperforming assets more quickly and prioritise interventions where they are likely to have the greatest impact. The aim is not simply to collect more information, but to use it to guide decisions that improve performance before the next period of market disruption.

Investing for resilience
A common misconception is that sustainability initiatives are a drain on short-term liquidity. In reality, targeted investments in asset efficiency can strengthen long-term financial resilience.

Deploying capital into building upgrades such as smart building technologies, modern heating, ventilation and air conditioning (HVAC) systems, high-performance insulation and on-site renewable energy generation can deliver multiple benefits.

Energy-efficient buildings often attract stronger occupier demand and help reduce vacancy risk. They can also lower exposure to energy market volatility by reducing baseline operating costs. Advances in investment planning tools also allow managers to assess retrofit options across portfolios and direct capital towards projects that offer the strongest financial and operational returns.

A common misconception is that sustainability initiatives are a drain on short-term liquidity. In reality, targeted investments in asset efficiency can strengthen long-term financial resilience.

Performance is not static
Given the volatile nature of global politics and energy markets, a set-and-forget approach is increasingly difficult to justify. Maintaining performance requires continuous monitoring and ongoing improvement.

By establishing robust baselines and tracking asset performance before and after sustainability interventions, owners gain a clearer understanding of outcomes and returns. Sustainability becomes less of an abstract corporate objective and more of a measurable component of asset performance.

At portfolio level, these insights can support capital allocation decisions based on evidence rather than assumptions. They can also help demonstrate to stakeholders, lenders and regulators that physical and transition risks are being actively managed.

A strategic imperative
The past two decades have shown that resilience cannot be built in the middle of a crisis. It must be embedded into portfolio strategy long before disruption occurs.

Attitudes towards sustainability are changing. Some organisations still view it primarily as a cost, while others increasingly treat it as a contributor to long-term asset performance. Asset owners that understand how their buildings are performing and act quickly to address inefficiencies are likely to be better placed to navigate future periods of uncertainty.

Energy volatility shows little sign of disappearing. For investors, the challenge is no longer simply understanding energy risk, but determining how quickly portfolios can respond to it. Sustainability is becoming an increasingly important part of that response.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘What is EnCO, and why does it matter? Building an energy conscious future together’. Why is so much energy efficiency work not optimised after its launch, and what, if anything, can we do about it, asks Peter Allan, Executive Director of EnCO.
• ‘Vulnerabilities and opportunities: rebuilding the UK’s energy resilience’. The resilience of the UK’s electricity system, which is recognised as critical to national security, is being tested as never before, writes Stephen Horrax, Director of Energy, UK & Ireland, at global engineering and consultancy firm Ramboll.
   

China continues to account for the largest share of the global EV market, with electric vehicles now making up nearly two-thirds (64%) of domestic car sales.

Focus is also turning to emerging EV markets where the demand for EVs is surging and where adoption now often exceeds that of the US, according to the report. Nearly half of all cars sold in Singapore in 2025 were electric, followed by Vietnam at 39% and Thailand at 27%. In Turkey, passenger EV sales more than doubled in just one year, with electric cars accounting for 22% of total sales. A drive towards oil import independence, relative openness to Chinese automakers and EV-focused industrial policies are thought to be behind this growth.

In Singapore and Thailand, EV models from Chinese brands have driven adoption, with Chinese brands making up 88% of all EVs sold in Thailand in 2025. The analysis finds that similar – or higher – EV penetration rates without Chinese automakers are possible. Vietnam, for instance, saw EV sales almost double to 179,000 in 2025, with domestic automaker VinFast accounting for 98% of the total. Similarly, in Turkey, domestic manufacturer Togg was the market’s second-largest EV brand in 2025, after BYD.

The growing proliferation of EVs in road transport has a deep impact on the trajectory for global oil consumption, with total road fuel demand expected to peak in 2029. Under BNEF’s economic transition scenario, the combined impact of fleet electrification and fuel efficiency improvements avoids 25.8mn b/d of road fuel demand by 2040, four times larger than the oil displacement across aviation, marine and petrochemicals sectors combined.

Despite strong global momentum, BNEF has revised down its EV adoption outlook for the second consecutive year, citing slower growth in China and the US.

In China, tighter eligibility requirements for incentives and increasing market maturity are weighing on growth. In the US, EV sales are projected to fall 19% this year following the rollback of federal support, including fuel economy targets and elements of the Inflation Reduction Act. As a result, EVs are expected to make up just 24% of the US vehicle fleet by 2040.

Affordability remains a key barrier globally. In major European markets such as Germany, Italy and the UK, battery electric vehicles are still around 17% more expensive than comparable internal combustion engine (ICE) cars, although this gap has narrowed significantly from 34% in 2024.

Battery costs remain the largest component of EV pricing. While efforts to localise battery supply chains are accelerating, matching China’s cost base remains challenging. The country continues to benefit from a mature supply chain, lower input costs, favourable financing conditions and intense competition, resulting in the lowest battery prices globally. By contrast, smaller manufacturing scale and less integrated supply chains in North America and Europe are likely to keep costs higher.

BNEF also highlights the slower pace of fleet turnover. Despite rapid sales growth, electric passenger vehicles are not expected to outnumber ICE vehicles on the road until 2047. By 2040, more than one billion combustion-engine passenger cars will still be in use globally, alongside the majority of trucks, vans, two-wheelers and buses.

Laying the foundations: Emily – the student perspective  
Early-career support is essential for those entering the energy sector. Emily Fan, a Student Member pursuing an MSc in Sustainable Energy Futures at Imperial College, defines the next generation’s passion and expertise. Her path to energy was inspired by an early fascination for sustainability and problem solving, and her first interaction allowed her to visualise this in a real-world context during London’s Energy Idea Challenge: ‘I worked on a project connecting offshore wind to green hydrogen production and for the first time I saw how energy, technology and real-world constraints could play together.’ However, like many others, Emily has struggled throughout the years to find her niche.

She found community as an Ambassador for the Energy Institute’s London Young Professionals Network (YPN), connecting with peers who share her enthusiasm for energy. This involvement gives her exposure to a broader range of industry perspectives than classroom learning alone. Through the Energy Institute, she engages with professionals from various backgrounds and companies, gaining hands-on insights and building a strong network before entering the workforce. As she puts it: ‘It has helped me navigate through energy, finding out what I enjoy and how to translate into a real career pathway.’ She is now focused on renewables and decarbonisation technologies, especially alternative fuels in hard-to-abate industries, such as aviation.

Beyond discovering her niche, what drives Emily is an appreciation for the impact energy has on us all. ‘We all depend on it, we all benefit from it, bear the consequences,’ she insists. ‘We need more people to offer their perspectives, skills and passions to make the energy sector even better than where it is now.’

Emily’s student story showcases how early support, exposure and community help shape your direction when starting out. By gaining hands-on experiences and connections beyond the classroom, opening doors to exploring potential interests, building confidence, and finding your niche in a broad and evolving sector.

Building the practical skills: Guilherme on the associate journey  
Throughout one’s working life, ongoing skill development is a must. The Associate Member (AMEI) grade reflects a commitment to building practical energy skills. The sector now values both traditional and non-traditional expertise for professionals to create new roles and challenge established practices.

Guilherme Castro AMEI, Offshore Wind Innovation Manager at the UK’s Crown Estate, demonstrates the value of diverse backgrounds: without a formal engineering or computer science degree. Born in Brazil and witnessing the limitations of energy, he felt compelled to make a difference. ‘The main change I want to contribute is that energy is not a differentiator of opportunities to anyone across the globe. That is my mission, for people to have access to studying during the night, for hospitals to have no outages.’ He attains the global south has its own energy transition journey, and believes combining diverse perspectives is essential ‘so we’re not insulated in our ideas’.

Guilherme has worked in the UK energy sector for eight years. He has found cultural adaption and how to work in his non-native language to be his main challenges. Part of his evolution he puts down to community through the Energy Institute’s YPN: ‘When you want to impact, I think you need to connect to leverage your power.’ Guilherme reflects on pursuing an interview at Octopus and how his fellow YPNs would hold pocket interviews together: ‘It’s a really diverse group, we’re not working in the same sector, so you get diversity of views and suggestions to shape your preparation.’ He attributes this to helping land him the role.

As a generalist Guilherme reflects on feeling afraid when pivoting to new parts of the sector. But these risks are the memorable milestones that he’s most proud of. They have given him a unique perspective; solutions which are system wide.

During Guilherme’s eight years in energy, four have included specialising in artificial intelligence (AI). Before generative AI became widely discussed, he developed AI solutions for energy applications. His experience shows how varied educational paths drive digital transformation in the sector.

Guilherme used his expertise to benefit the global community by proposing an AI training course for energy professionals. The Energy Institute developed and launched an ‘AI in the Energy Sector’ programme last year to help the market grasp the basics of how the technology works, its impact and the potential for them.

Guilherme’s associate journey goes beyond building practical skills. It’s about having confidence to grow, adapt and contribute. His experiences show how combining diverse perspectives, continuous learning and expanding community can bolster your career and leverage your impact in energy.

Duncan, the experienced and chartered professional  
The Energy Institute’s Member (MEI) grade provides formal recognition for those with at least four years of experience who demonstrate independent judgment and leadership. Duncan Cockburn MEI, Head of Energy Operations and Environmental Compliance at BT, demonstrates this commitment. His journey began with a desire to surf more, leading him to his passion and a 30-year energy management career.

Duncan was an Associate Member for many years before he progressed to MEI to obtain his chartership. He sought out the Energy Institute as a learning opportunity, to fill in the gaps of his expertise. ‘I’m an aircraft engineer, I like the logic of things, the organisation and the engineering of things. But when it comes to how it operates within refrigeration or air conditioning or those kinds of controls, it was that extra breadth that I needed.’

As a Chartered Energy Manager, he adapted his focus to meet stricter legal compliance standards, moving beyond basic energy-saving metrics. He now manages the ISO 50001 standard for his organisation, driven by a strong belief in responsible resource use.

Staying current with changing legal requirements requires ongoing learning. Duncan valued the Energy Institute’s structured support and learning opportunities. Completing the ‘Advanced Energy Manager’ course through the EI Academy expanded his expertise and enabled him to approach complex projects with new perspectives. He also highlights the value of volunteering alongside fellow MEI and chartership interviews, forming powerful connections, alongside their breadth of professional experience strengthening his knowledge.

He strongly believes that the sector has a place for everybody, ‘because it needs all sorts of people to be successful’. He adds: ‘You can be analytical, you can be observational, you can write good business cases.’ It is individual strengths which can be pulled together to achieve more.

Duncan’s journey demonstrates how MEI formalises experience while supporting continual growth. By upskilling through training, gaining professional recognition, and expanding your peer networks, experienced professionals can deepen their expertise, stay current and make significant change.

Jaz, the fellowship and leadership standard  
The Fellow (FEI) grade represents the highest level of professional achievement, awarded to those with significant and sustainable contributions to the energy sector or society. Fellows are innovators and leaders who drive change and support the community through mentorship, policy advocacy and public service.

Jaz Rabadia MBE FEI Chartered Energy Manager, has spent two decades helping global organisations manage energy use and utilise sustainable environmental, social and governance (ESG) practices. In particular, she noticed that young women weren't joining the sector and made it her mission to help more young women understand the exciting world of energy and energy management.

Jaz says that the Energy Institute has been instrumental in her personal and professional growth since joining as a graduate. She has built lasting relationships, spoken on international panels, contributed to industry reports and shared best practices at major events. The recognition and opportunities she received evidently show the value of aligning passion with a respected global institution.

After all her years in energy, she gained the recognition she deserved when obtaining the unique title of Chartered Energy Manager, as well as receiving an MBE for services to sustainability in energy management and promoting diversity in science, technology, engineering and mathematics (STEM).

Jaz believes that ‘the beauty of the energy industry is there’s a role for everyone’.

‘So whether you’re from a financial, legal, engineering or even communications background, there is a role for somebody… we need people who are willing to challenge the status quo.’ Just as Jaz did when starting out. Although she was the only woman in the room, she realised this was her strength and went on to inspire many others to follow suit. 

Jaz’s journey highlights how becoming an EI Fellow recognises not only expertise, but long-term impact and leadership. Throughout her roles, and alongside her commitment to diversity in the sector, she demonstrates how experienced professionals can influence the sector while empowering others to follow.

The power of a shared purpose: a collaborative ecosystem of support  
The experiences of these distinguished members demonstrate how the Energy Institute brings together individual journeys to support global progress. The Energy Institute offers resources for continuous professional growth, including access to training, mentoring, events and a regional peer network.

The task ahead is therefore twofold: expanding capacity while ensuring the system remains stable, secure and capable of withstanding both external shocks and internal variability. This shifts the focus from capacity alone to resilience by design.

From energy security to sustainable resilience
The UK energy sector is moving beyond short-term crisis response towards a longer-term model of sustainable resilience. Rather than reverting to fossil fuels, the emphasis is now on electrification and maximising domestic renewable resources.

Security and sovereignty have become increasingly prominent themes in discussions about the future energy system.

Policy developments reflect this shift. Measures to stabilise electricity pricing and increased investment in clean power signal that resilience and decarbonisation are increasingly viewed as mutually reinforcing. However, generation alone will not deliver a secure system.

In practice, resilience requires systems that can respond dynamically to variability in both supply and demand. Advanced modelling, scenario planning and digital tools are becoming essential in enabling operators and developers to manage this growing complexity and uncertainty.

Without sufficient flexibility and stability, increased renewable penetration can introduce volatility. The challenge is no longer simply to build more infrastructure, but to design systems that are more intelligent, responsive and capable of real-time adaptation.

A window of opportunity, but not guaranteed
The UK has a clear opportunity to position itself as a leader in low-carbon energy systems designed to withstand future shocks. Significant public investment, including funding for Great British Energy, sits alongside strong policy commitment to the government’s Clean Energy Mission 2030.

Yet delivery remains the critical risk. The pace and scale of change required mean that ambition alone is insufficient. Without coordinated planning, timely investment and a focus on execution, the UK risks losing ground in an increasingly competitive global transition.

The challenge is not a lack of solutions, but the ability to bring them together efficiently at system level. Bridging the gap between strategy and delivery will require closer collaboration between policymakers, network operators, investors and technical advisers, alongside a sustained focus on implementation.

Without coordinated planning, timely investment and a focus on execution, the UK risks losing ground in an increasingly competitive global transition.
 

Learning from international systems thinking
The UK is not alone in facing these challenges. Nordic energy systems, in particular, demonstrate the value of integration and flexibility in delivering resilient outcomes.

The combination of renewable generation with large-scale storage, including battery systems and pumped hydropower, enables these systems to manage variability effectively. At the same time, the widespread use of district heating highlights the benefits of localised, system-based solutions.

In Denmark, district heating supplies around two-thirds of households, drawing on a diverse mix of energy sources including waste heat, solar and geothermal energy. These systems are developed as part of coordinated urban and energy planning, offering a model that is increasingly relevant for cities in the UK.

There are clear opportunities to adopt similar principles. Integrating heat, power and digital infrastructure offers a route to more efficient and resilient systems. For example, capturing excess heat from data centres for use in local heat networks can provide both system benefits and savings for consumers.

Advanced design tools and multidisciplinary engineering are making it easier to evaluate these approaches and make decisions under uncertain conditions.

Delivering the transition: infrastructure, technology and flexibility
At its core, the transition remains an engineering and delivery challenge. The UK’s electricity grid is ageing and was not designed for the complexity of a highly electrified, renewables-dominated system. Reinforcement and modernisation are therefore essential.

Advanced technologies will play a critical role. Flexible alternating current transmission systems and power electronics can improve system stability and enable greater renewable integration. Innovations such as Ramboll’s Universal Damping static synchronous compensator (STATCOM) act as a shock absorber for the grid, reducing oscillations and unlocking additional capacity within existing infrastructure.

Alongside grid innovation, demand-side transformation will be equally important. The electrification of heat and industry, including large-scale heat pump deployment, offers a pathway to reduce emissions while improving system efficiency. Delivering these solutions at scale requires early planning, robust business cases and coordinated programme delivery.

At the same time, there is a significant opportunity to unlock flexibility at the domestic level. Innovation programmes such as National Grid’s Equinox project demonstrate how consumer behaviour can support system resilience. By incentivising households to shift or reduce heat pump use during peak periods, trials have shown that demand can be managed without compromising comfort, helping to relieve pressure on local networks and reduce the need for costly reinforcement.

This marks an important shift. Households are no longer passive consumers, but active participants in a more flexible and responsive system. Realising this at scale will depend on new market mechanisms, compelling customer propositions, and the integration of digital platforms and smart controls to coordinate flexibility across networks.

Digitalisation will underpin this transformation. The ability to model future scenarios, optimise performance and accelerate delivery is becoming a defining factor in successful energy programmes. Equally important is the workforce: combining engineering expertise with digital capability and systems thinking will be essential.

From vulnerability to opportunity
The UK’s energy system faces undeniable challenges, but these should not be viewed solely as risks. The same pressures that expose vulnerability also create an opportunity to redesign the system for a more resilient and sustainable future.

Delivering this will require coordinated action across policy, infrastructure and industry, together with a shift from isolated interventions to integrated, system-level thinking. It will also require the confidence to move decisively from ambition to delivery.

The UK has the capability, resources and expertise to succeed. If these can be brought together at pace and scale, this country has the potential not only to secure its own energy future, but also to lead globally in the design and delivery of resilient, low-carbon energy systems.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Why the grid will decide the UK’s energy future’. While much of the national conversation focuses on generation targets, it is the UK’s electricity grid itself that will determine how quickly, equitably and productively the country can reach net zero, explains Mark Neller, Arup’s Energy Leader for the UK, India, Middle East and Africa.
• ‘Modern grids will be the foundation for future growth in Europe’. As Europe seeks to strengthen energy security, stimulate sustainable growth and affordability, and reduce emissions, accelerating electrification and investing in modern grid infrastructure must become urgent priorities, writes Maxine Ghavi, Executive Vice President and Head of Europe at Hitachi Energy.

The supply reduction has pushed regional gas prices to near three-year highs, reducing demand and creating a 35mn t/y supply gap in 2026, which Asia-Pacific markets cannot easily replace. As a result, about 90TWh of generation is shifting from gas to coal-fired facilities. The market analyst projects that Asia’s coal consumption could rise by nearly 70mn t in 2026 if gas markets remain tight. This increase is driven by higher usage of existing coal plants, not new capacity.

Coal-fired generation is also increasing in northeast and southeast Asia, while gas-based generation declines. Seaborne coal shipments to the region are also rising. Japan’s coal-fired generation reportedly rose by 11% as gas-fired output fell by 13%. In May, South Korean coal imports were 50% higher and Japanese imports 20% higher than the previous year.

‘What we are seeing is not a coal comeback but a reality check for the Asia-Pacific’s energy transition,’ said Tonmit Talukdar, Analyst of Coal Research at Rystad Energy. ‘LNG price volatility has shifted costs without reversing the move towards cleaner energy and thermal coal prices have responded to that tightness with cautious buying, stockpiling and a geopolitical risk premium rather than any structural change.’

‘Coal is stepping in when gas prices spike, supply tightens or mothballed plants are briefly restarted,’ Talukdar added.

Talukdar stated that the current market response is more contained than the response during the 2022 Russia–Ukraine crisis. Disruptions to Russian gas supplies in 2022 caused a sharp increase in global coal demand. At that time, renewable energy capacity additions were limited. Thermal coal inventories across major Asian markets were also lower in 2022.

In 2026, high coal inventories and the availability of alternative energy in China, India and other Asian nations currently prevent a similar market pressure. ‘Until storage, grid flexibility and firm low-carbon capacity scale sufficiently to cover peak demand and periods of low wind or hydro output, coal will continue to serve as the system’s fallback,’ Talukdar said.

Rystad Energy’s base case scenario projects that Newcastle coal will average $125/t in 2026, referring to the 6,000 kcal/kg coal basis – the global benchmark for seaborne thermal coal and the reference price for Australian exports into northeast Asia. The price is projected to decrease to $115/t in 2027, with nuclear restarts in northeast Asia and improvements in LNG supply easing the fuel deficit.

The report shows that Japan leads demand growth among gas power systems in the Asia-Pacific region due to policy adjustments and nuclear restarts. South Korea and Taiwan are also burning more coal because of disruptions to LNG supplies and lower nuclear output. The Philippines, Thailand and Vietnam are increasing coal usage to offset tight gas balances. China remains insulated from these disruptions because gas has low penetration in its power sector, meaning China contributes only marginally to seaborne coal demand.

A downside scenario involving renewed hostilities could increase coal demand by 90mn t in 2026 alone. Under this scenario, cumulative near-term demand would reach approximately 190mn t. However, Rystad reports that no major coal producer has approved new large-scale mining projects or extended mine lifetimes, despite increased demand. This capital allocation decision contrasts with the industry actions that followed the 2022 invasion of Ukraine. Governments describe the current demand increases as emergency responses to system constraints and supply shocks. Future investment decisions by producers like Adaro, BHP, Bumi or Glencore regarding new mines or life extensions will indicate whether these industry expectations are permanent or temporary, concludes the report.
 

In addition, Energy UK’s report, Clean heat: jobs and skills for the future, states that high electricity costs limit demand for low-carbon heat technologies, which in turn will restrict investment in training before the Warm Homes Plan is fully implemented. The report notes that most heating employers are sole traders or micro-businesses that lack the capital to invest in training without market certainty.

Experts within the industry emphasise that framing this challenge as an employment opportunity is the key to solving it. Energy UK Head of Industrial Strategy Rachel Cary said: ‘The Warm Homes Plan is a chance to bring down bills, strengthen our energy security and create thousands of jobs across the UK, but it all rests on a skilled workforce to deliver it. Unless we act now, a skills shortage risks being a bottleneck to delivery. More than a million young people are not in employment, education or training, but with the right support, the transition to low-carbon energy can bring a diverse range of good, well-paid jobs while lowering bills and boosting growth.’

To bridge this gap and tap into that potential workforce, the report suggests changes to policies. The trade body recommends that the government provide low-cost loans or bursaries for retraining and expand the Heat Training Grant to include advanced courses. The report also calls for reforms to the Growth and Skills Levy to increase apprenticeships, tax incentives for near-retirement engineers to mentor new entrants and low-carbon heat awareness programmes in schools.

If these workforce interventions are implemented and the government’s rollout is successful, the Heat Pump Association UK says that the gross value added from manufacturing, installing and operating residential space heating appliances could increase from £12.2bn today to £22.5bn by 2035. This growth could support 143,000 full-time jobs by 2035, with about 140,000 roles focused on heat pumps, according to the association.

While long-term growth hangs in the balance, concrete financial steps are already being taken on the ground. As part of the Warm Homes Plan, the Department for Energy Security and Net Zero announced a £40.6mn investment on 20 May 2026 to upgrade heat networks and install low-carbon systems in England and Wales. The allocation includes £15.6mn to upgrade 94 old heat networks across England and Wales, replacing leaking pipes, insulating pipework and replacing home interface units to improve energy efficiency for more than 10,000 residents, hospitals and charities.

A portion of this cash injection has already been earmarked for regional infrastructure projects: the government distributed a £25mn share to four specific projects, including £13.5mn to expand the Bristol City Leap heat network using heat pumps, which the government states will create more than 1,000 jobs, apprenticeships and work placements. Rochdale received £1mn to build a heat network extracting heat from a sewer to supply public buildings, schools and social housing, while the Green Heat Network Fund allocated £8.6mn to the King’s Cross Heating and Cooling Network and £2.2mn to a waste-heat project in Atherstone.

Officials view these early local investments as steps towards broader geopolitical and financial resilience. Minister for Energy Consumers Martin McCluskey said: ‘The conflict in the Middle East has shown once again why we must get off the fossil fuel rollercoaster and onto low-carbon, homegrown power we control. Heat networks will play a role in that shift, lowering bills for whole communities while strengthening our energy security.’

Only the top 10 ranking, which actually includes 12 manufacturers because two manufacturers are named in two places, was released to the public. Of these, nine of the top 12 manufacturers are headquartered in China. However, suppliers targeting protected, high-barrier markets gained momentum, with India’s Adani Solar ranking sixth, Singapore-based Elite Solar eighth and South Korea’s Qcells 10th.

Chinese companies continue to dominate Wood Mackenzie's global solar PV manufacturer ranking
Source: Wood Mackenzie
¹If the difference in the score is 0.4 or lower, the companies have been given the same rank.

‘Chinese manufacturers continue to lead globally on manufacturing scale, technology advancement and operational efficiency. However, severe financial pressure from ongoing oversupply is accelerating structural change across the sector,’ said Yana Hryshko, Head of Solar Supply Chain Research, Wood Mackenzie.

Tunnel oxide passivated contact modules (TOPCon) – cell technology designed to enhance the efficiency and reliability of photovoltaics (PV) – accounted for more than 80% of shipments among the top 10 manufacturers in 2025, confirming that the transition to this technology is now effectively complete among leading suppliers. Mainstream TOPCon module efficiency reached 24.8% during the year.

Despite strong shipment volumes, persistent global oversupply continued to pressure profitability across the sector. Leading Chinese solar manufacturers recorded a combined loss of $5.5bn in 2025, while most non-Chinese manufacturers remained profitable due to stronger pricing conditions in protected markets.

Average manufacturing capacity utilisation among the top 10 manufacturers rose to 70% in 2025, up from 67% in 2024, signalling improving demand. Meanwhile, manufacturers continued diversifying production footprints outside of China in response to rising trade tensions and localisation requirements, with nine of the top 10 manufacturers now operating facilities in at least two countries.

The UK remains the largest offshore wind nation in the North Sea by turbine count under this model. By 2030, the UK is projected to operate 4,200 turbines, followed by Germany with 2,700 and the Netherlands with 1,700. By 2050, the UK turbine count rises to 6,300, while Germany reaches 4,300 and the Netherlands exceeds 4,200. The Netherlands faces the highest spatial density relative to its national territory and offshore wind farms would occupy 19% of Dutch North Sea waters by 2050.

Heriot-Watt University reports that the model projects wind farms occupying 18% of Belgian waters, 15% of Danish waters, 14% of German waters, 9% of UK waters, 8% of Norwegian waters and 7% of French waters.

The study implies that the expansion could create physical interactions both above and below the water. Large wind farms generate atmospheric wakes extending 40km or more, potentially reducing energy yields at neighbouring projects across borders. Below the surface, turbines alter marine environments and limit the movement of commercial fisheries who depend on the seabed for certain harvesting methods. The research institutions are mapping alternative marine activities that can coexist within operational wind farm boundaries.

In other news, the Global Wind Energy Council (GWEC) reports that the international offshore wind market expanded in 2025: workers connected 9.3GW of new offshore wind capacity globally last year. These additions increased total global offshore wind capacity to 92.5GW by the end of 2025.

China maintained the largest share of new installations for the eighth consecutive year, adding 6.6GW and bringing its capacity to 48.4GW. There, the country has shifted from state feed-in tariffs to grid parity and now uses market-based renewable energy pricing.

In 2025, European developers commissioned 2GW across five wind farms in three countries, accounting for about 20% of the global annual increase.

GWEC estimates that over 50GW of offshore wind capacity are under construction worldwide. Annual installations are expected to double in 2026, triple by 2031 and surpass 50GW/y by 2035. The organisation forecasts a compound annual growth rate of 24% for the sector from 2026 to 2030. Market forecasts indicate that global offshore wind capacity could increase to 420GW by 2035, with 327GW of new capacity forecast over the next decade.

The group identifies 25GW of planned projects worldwide (excluding China) that are ready to build but remain awaiting final investment decisions. However, grid connection bottlenecks, delayed state auctions, permitting backlogs and supply chain constraints are delaying these developments.

GWEC presents an eight-point action plan for policymakers which instructs governments to classify offshore wind farms, transmission grids, ports and storage facilities as nationally important infrastructure. The plan advises states to establish long-term grid investment schedules aligned with offshore wind auction pipelines. It also recommends increasing public financing for support infrastructure to lower private financing costs for developers.

The report recommends that industrial nations develop local manufacturing pipelines and train the necessary workforce. It also urges governments and industry groups to address public opposition and share local economic information with coastal communities. The policy roadmap calls for direct public investment to decarbonise heavy industry through electrification, aiming to make offshore wind the primary electricity source for national energy grids. The data shows that markets such as China, the European Union, Japan, the Philippines, South Korea, Türkiye (Turkey), the UK and Vietnam are adjusting planning frameworks to accelerate deployment, attributed to efforts to reduce national exposure to international fossil fuel price volatility.
 

The trend was highlighted this month after Spanish renewable energy company Grenergy commissioned the largest battery storage facility in the Americas and Spanish renewable energy company Acciona Energía announced plans for a major new storage project in northern Chile.

Grenergy’s Elena facility, located in the Antofagasta region, has entered operation with 3.5GWh of storage capacity. The company plans to expand the project to 7GWh by 2028.

Elena forms part of Grenergy’s Oasis de Atacama development, a large-scale solar and storage platform in northern Chile. The project is expected to combine 2.5GW of solar generation with 14.1GWh of storage capacity once fully completed.

The scale of the project reflects the increasingly prominent role storage is playing in renewable energy development. Battery systems allow electricity generated during periods of strong solar output to be stored and used later, helping developers make greater use of renewable generation and deliver power beyond daylight hours.

Grenergy said Oasis de Atacama is designed to provide greater flexibility to the electricity system while supporting the integration of additional renewable capacity. According to the company, Elena includes 624 battery containers and 6,240 battery units.

The company has also linked the development to wider industrial and economic activity in northern Chile, stating that large-scale storage could support industrial electrification, mining decarbonisation, electric mobility and future data centre investment.

The project is backed by substantial investment. In September 2025, Grenergy secured $270mn in senior non-recourse financing for Phase 6 of Oasis de Atacama, known as Elena. The batteries are being supplied by Chinese battery manufacturer BYD Energy Storage.

Acciona Energía is pursuing a similar strategy. The company said it will build a 196MW/980MWh battery storage facility linked to its El Romero solar plant in the Atacama Desert, with commercial operations expected by the end of 2027.

The project will double Acciona Energía’s planned storage capacity in Chile to around 2GWh. It follows a separate 1GWh storage project currently under development at the company’s Malgarida solar complex.

Acciona Energía said the additional storage capacity would help optimise renewable energy management, improve grid stability and strengthen security of supply.

Renewable generation projects continue to advance alongside storage deployment. Renewable energy developer Mainstream Renewable Power recently announced that its 109.2MW Ckhúri wind farm in the Antofagasta region had reached commercial operation. The project comprises 26 turbines and is expected to generate enough electricity to supply around 166,000 homes.

Mainstream said the wind farm would provide electricity particularly during evening and night-time periods when solar generation falls. The project forms part of the company’s wider Huemul Energía platform, which contributes to more than 1.2GW of renewable energy capacity developed by Mainstream in Chile.

The announcements suggest Chile’s renewable energy market is evolving beyond a focus on generation capacity alone. Developers are increasingly combining solar and wind projects with storage infrastructure designed to shift electricity to periods of higher demand and make more efficient use of renewable output.

The scale of the latest projects also demonstrates how quickly battery storage is moving beyond smaller grid-support applications. Elena is already operating at 3.5GWh and is expected to double in size by 2028, while Acciona Energía’s Chilean storage portfolio is set to reach around 2GWh once its announced projects are completed. Storage is becoming a core part of how developers plan, finance and operate renewable energy projects in Chile.

In May, the Chilean government reportedly published a plan to move to a 100% renewable-powered electricity grid by 2030. While two-thirds of the grid is already powered by renewables, grid constraints have reportedly held back further increases. The government plans market reforms and transmission upgrades.
 

The proposal aims to increase the role of electricity across the global economy and forms part of a broader package of measures ahead of the November 2026 summit in Antalya, Türkiye (Turkey).

COP31 organisers said greater electrification would strengthen energy security and support economic development. They also argued that wider use of electricity, alongside continued growth in clean power generation, would help reduce dependence on fossil fuels and support climate goals.

The initiative comes as electricity demand continues to rise, driven by growing use of electric vehicles and expanding digital infrastructure.

Electrification is one of several priorities included in the Action Agenda. Other goals include improving energy efficiency in buildings, cutting food loss and waste, and strengthening the resilience of cities.

However, achieving higher levels of electrification will require substantial investment across power systems. Networks will need to expand, while growing demand will require additional generation and storage capacity.

To support the initiative, COP31 organisers have commissioned the International Energy Agency (IEA) to develop ways of achieving the target and identify measures that could accelerate electrification.

The IEA is expected to publish a special report examining how countries could achieve higher levels of electrification while strengthening energy security.

Jessica Isaacs, Global Impact Director at the World Resources Institute (WRI) Polsky Center for the Global Energy Transition, said the proposal sent a strong signal that clean power must become ‘the bedrock of the global energy transition’.

She said no country would achieve electrification at the scale and speed required without supportive policies and investment in electricity infrastructure. Isaacs also highlighted the need to extend access to modern energy services, noting that hundreds of millions of people worldwide still lack access to electricity and clean cooking.

Environmental organisations broadly welcomed the announcement but argued that electrification alone would not be sufficient to meet climate goals. Greenpeace said the proposal should be accompanied by stronger commitments to phase out fossil fuels and accelerate the deployment of renewable energy.

COP31 organisers have said they intend to build an international coalition to support the target ahead of the Antalya summit. The electrification goal is expected to become one of the presidency’s central energy priorities in the run-up to the conference.

Developed in partnership with Transmission Developers, the line runs underground and underwater through Lake Champlain and the Hudson River. It is the longest HVDC cable system in North America and uses HVDC Light technology supplied by Hitachi Energy, a voltage-source converter-based system designed for underground and subsea applications.

Electricity is sourced from Hydro-Québec’s provincial hydroelectric system, including large-scale generating facilities in the province’s northern regions.

Power sales to New York State are expected to generate approximately US$34bn over the life of the contract. The agreement allows flexibility in delivery volumes depending on system conditions, while maintaining priority for Québec’s domestic electricity needs.

The interconnection is designed to operate in both directions over time, enabling electricity imports into Québec and supporting wider renewable energy integration across the region.

For New York, the project is expected to displace a share of thermal generation and reduce greenhouse gas emissions by around 4 million tonnes annually. It also contributes to the state’s target of 70% renewable electricity by 2030 under the Climate Leadership and Community Protection Act.

Black & Veatch is unique in its set-up, out of our 12,000+ employee-owners we have a central pool of talented engineers, about 9,000 in total, who can be called on to work on projects around the globe. In that way we are borderless and focused on deploying skilled engineers where they are needed. Around the world we need more engineers, so the best way to use your global resources is to have them all in one pool: civil engineers, mechanical engineers, electrical engineers, geothermal engineers, chemical engineers. They provide support to all the areas and the solutions that we bring to our clients.

To take a step back and look at some of our current work, we're providing engineering design support for a major 300MW open-cycle gas project running on biofuels in Ireland. The plant, due to come online in 2027, replaces an oil-fired plant decommissioned in 2023. Elsewhere, for the past 14 years we've been helping the UK gas and electricity market regulator Ofgem understand consumer sentiment, through our detailed energy customer audits.

Our vision is to become the leader in sustainable infrastructure. What we mean by that is really building human-critical infrastructure that is going to power economies. We made a decision to discontinue working on new coal-powered power plants, we've moved away from that as part of demonstrating our commitment to be leaders in sustainable infrastructure.  

Our vision is to become the leader in sustainable infrastructure. What we mean by that is really building human-critical infrastructure that is going to power economies.

How can we achieve the goal of net zero?
Thinking about sustainability more broadly, if you look at the UK and the goal of achieving net zero, I am now asking myself, how can we help with that? The first thing that I noticed since moving here is that the time for BESS is now. If I look at the grid, I think of it as a patient. Can this patient take the stress that we're putting in? It's also 100 years old, like much of the infrastructure across Europe, the Middle East and Africa (EMEA). Our ageing grid needs urgent attention and upgrades so that it can take the extra loads we are generating from a world-leading renewable energy sector. The net zero goal here in the UK is a noble one, but I believe it can only be achieved through a rapid transformation of our grid and that’s what we at Black & Veatch are focused on.  

We're involved in over 3GWh of battery energy storage systems in this region. A key project is the Eccles BESS for Matrix Renewables in Scotland. This is a 500MW/1GWh project currently being built. Black & Veatch is the ‘owner's engineer’ – we like to build the things we design. When clients want to build complex energy infrastructure and they need a partner to provide additional advice and anticipate challenges on their behalf, we provide those owner’s engineer services to them because we know how the EPC world works.

We’re involved in the entire life cycle of our client’s infrastructure. Since we are the ones who most likely did the conceptual evaluation of their plans, identified the equipment that was needed and may have ended up building it, we can then provide excellent advisory work to ensure that management of the energy asset is being optimised.

We've also been supporting energy company SSE with the preliminary front-end engineering design (pre-FEED) and the FEED for the Aldbrough Hydrogen Pathfinder project, a 35MW electrolytic hydrogen project in east Yorkshire. Hydrogen is a new sustainable technology, so we need to foster it, and we need to actually show how it will be a vital part of the UK’s energy portfolio. We’re also working on one of the largest hydrogen projects in the world, an advanced clean energy storage green hydrogen project in Utah, US. This 220MW capacity renewable energy project (Black & Veatch served as EPC) is nearing start-up and commissioning.

I like to view bringing new technologies to the energy mix as a puzzle we’re trying to solve. How do we introduce innovation to the market that will increase the supply, resilience and reliability of energy? That’s the puzzle we are trying to solve.

I’m excited to be here in Glasgow to help solve the UK’s energy puzzle.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Problem solving: how wind power uses a UK agency to resolve demanding engineering challenges’. Find out how an Innovate UK agency is helping connect big company problems with solutions that often come from small firms in other industrial sectors, to avoid reinventing the wheel.
• ‘From force majeure to restart: the engineering and project delivery priorities after disruption to LNG infrastructure’. What does it actually take to bring LNG infrastructure back safely, credibly and sustainably into service? 

State Senator Peter Harckham added that the public funding will expand local rooftop and community solar to create annual utility savings for consumers. ‘At a time when other forms of new electric generation face years of delay, our investment in solar means new energy that can quickly scale, meet demand and provide long-term savings,’ Harckham said.

In tandem with community solar additions, the New York State Senate and Assembly passed the Solar Up Now NY (SUNNY) Act to Governor Hochul for signature. The SUNNY Act permits the use of portable plug-in solar devices, such as balcony solar panels, up to 1.2kW capacity (AC). These systems connect directly to standard 120V electrical outlets.  

The legislation requires devices to be certified by a testing laboratory and installed in accordance with state fire codes. Under the act, utilities cannot require users of plug-in solar devices to sign grid connection agreements or participate in net metering. Utilities are also prohibited from charging fees for using the equipment. Device owners must notify their utility provider within 30 days of installation.

‘Under the SUNNY Act, even people living in apartments will be able to make the choice to replace some of their fossil fuel use with solar energy they capture themselves,’ said Katherine Nadeau, Deputy Executive Director of Policy and Programs at Environmental Advocates NY.

New York is the eighth state to pass plug-in solar legislation through its legislature. Governors in Colorado, Maine, Maryland, Utah and Virginia have signed similar bills into law, while approved legislation in Connecticut and New Hampshire awaits the governor's signature.

These state measures come as utility regulators in 27 US states are raising fixed monthly fees and lowering per-kilowatt-hour rates for residential customers. According to the North Carolina Clean Energy Technology Center, these changes create baseline costs that consumers pay regardless of whether they self-generate. This can reduce the price difference between daytime and nighttime electricity, limiting time-of-use savings and impacting solar-plus-battery investments.

The budget also follows the passage of the Accelerate Solar for Affordable Power (ASAP) Act, which aims to deploy 20GW of distributed solar energy by 2035. Patrick McClellan, Policy Director for the New York League of Conservation Voters, said that federal support faces changes, making state-level funding additions for the NY-Sun programme and interconnection updates necessary to boost community solar.

Analysis from the Rocky Mountain Institute indicates that centralised infrastructure expansion drives up retail electricity rates across the US due to transmission line and substation construction costs: distributed energy resources generate and store electricity at the point of consumption, reducing peak loads on the distribution grid. Clean energy advocacy groups, including Vote Solar, say that distributed generation moves infrastructure development costs away from public utility ratepayers and onto private investors.  

The New York state budget calls for the Public Service Commission to revise the utility interconnection process, stating that these utilities will create flexible interconnection programmes using smart-grid controls to manage solar and energy storage exports and charging to avoid delays caused by traditional infrastructure upgrades. NYSEIA estimates that flexible interconnection programmes could increase community solar hosting capacity by up to 97% in upstate New York, adding 3.3GW of capacity. The state aims to reach 10GW of distributed solar by 2030, having already surpassed its previous 6GW goal ahead of schedule.

On a local level, the funding expansion coincides with the completion of Sunset Park Solar, a 725kW rooftop installation at the Brooklyn Army Terminal. As New York City's first community-owned solar collection, the project partners with the New York City Economic Development Corporation to supply electricity to local low- and moderate-income residents and small businesses.

Nonprofit organisations United Puerto Rican Organisation of Sunset Park (UPROSE) and Solar One drove the joint development of the Sunset Park project alongside energy cooperative Co-op Power, Resonant Energy and installer 770 Electric Corporation. UPROSE and Solar One provided solar installation training courses to local residents and 770 Electric Corporation hired six of those trainees for the construction work. The cooperative ownership structure gives each subscriber-member a vote to determine how to allocate resources and profits from the installation.

The Sunset Park Solar array is expected to generate more than $1mn in revenue for the Community Resiliency Fund over its 25-year lease period. The project is also expected to lower energy costs by 20% for participating residents, according to UPROSE. The installation is estimated to generate 19.6mn kWh of solar electricity over 25 years, reducing greenhouse gas emissions by an estimated 13,056 tonnes of CO2 equivalent. 
 

By enabling door-to-door emissions calculations, the framework is intended to support more accurate benchmarking of transport performance and inform procurement and operational decisions. It also aims to provide clearer data for consumers and public authorities.  

The rules apply to companies that voluntarily disclose transport emissions, ensuring that reported figures are consistent and verifiable. Further work will refine the methodology, while the European Commission (EC) is set to roll out guidance and digital tools, particularly for small and mid-sized enterprises. Full application of the framework is expected by 2030.

The push for standardised reporting comes amid growing evidence that official emissions data does not reflect real-world performance, particularly for plug-in hybrid vehicles.

A study by the International Council on Clean Transportation (ICCT) finds that plug-in hybrid vehicles in Europe emit, on average, five times more CO2 in real-world conditions than official figures suggest. The gap between real-world and official values widened between 2021 and 2023, driven in part by overestimation of how often these vehicles operate in electric mode.

Plug-in hybrids accounted for around 9% of new car sales in Europe in 2025 and are often marketed as a lower-emissions alternative due to their ability to accept both mains power and road fuels, as well as their ability to switch between electric and combustion power. The findings add to evidence of their real-world emissions performance.

The EC revised the methodology used to calculate plug-in hybrid emissions in 2025, with further adjustments planned for 2027. At the same time, the EU’s CO2 emission reduction targets for cars are under review in the European Parliament, where an early draft proposes freezing future corrections to plug-in hybrid CO2 values.

‘Even with the 2025 correction, emissions on the road are not accurately estimated. And the worrying trend is that new models are not emitting less but more. Even if carmakers claim that consumers drive more kilometres in electric mode, the reality is something else,’ commented Peter Mock, Europe Director, ICCT.

The report finds that the gap between real-world and official emissions values grew from 265% in 2021 to 400% in 2023, on average across all manufacturers. Mercedes, the largest seller of plug-in hybrids between 2021 and 2023, recorded the widest gap, rising from 329% in 2021 to 614% in 2023, with a three-year average of 452%.

Plug-in hybrids show a larger divergence between real-world and official CO2 values than other powertrains. Based on ICCT estimates, the gap corresponds to approximately 100mn tonnes of CO2 from new registrations between 2021 and 2025, emissions that are not reflected in the EU’s CO2 reduction targets for carmakers.

The study covers around eight million vehicles, including petrol and diesel cars and their hybrid variants. Differences between real-world and official emissions are observed across all vehicle types, averaging around 20% for internal combustion vehicles, including full and mild hybrids, compared with around 400% for plug-in hybrids registered in 2023.

‘The gap of plug-in hybrids is shockingly high, but this should not distract from the fact that the gap of conventional vehicles, which still make up the majority of vehicle sales in the EU, is also considerably high at 20%. As a consequence, we didn’t see any notable reductions in the real-world CO2 emissions of vehicles with a combustion engine over the past years,’ said Jan Dornoff, ICCT Research Lead and co-author of the study.

Between 2018 and 2023, official average CO2 values for new cars fell by 28%, while real-world emissions declined by 15%. Battery electric hybrid vehicles accounted for most of the reduction. Real-world emissions from combustion engine cars decreased by around 1% over the same period.

That observation framed Turnbull’s discussion with Energy Institute members last month. In the edited extracts that follow, organised around key themes from the conversation, the former Australian Prime Minister reflects on Australia’s experience with renewable energy, storage, electrification and energy security, and explains why the next phase of the transition will depend increasingly on supporting infrastructure.

Storage has changed the renewables debate 
‘I had a real epiphany on energy storage in 2016 when South Australia experienced a major blackout that lasted for several days and affected hospitals and other essential services. At the time, South Australia had rapidly expanded wind and solar generation under Australia’s renewable energy target. The state has some of the country’s strongest renewable resources, with excellent wind conditions and abundant sunshine. However, much of its coal-fired generation had closed and reliability depended heavily on transmission links with neighbouring Victoria. When severe storms damaged those connections, the system failed.’

‘The lesson for me was that although we were rolling out large amounts of renewable generation, nobody was paying enough attention to storage. That experience helped drive support for Snowy Hydro 2.0, which is now around three-quarters complete. The project will provide around 350GWh of storage and 2,200MW of generating capacity.’

Solar power’s extraordinary rise 
‘Australia has some of the highest levels of rooftop solar adoption in the world. More than a third of Australian households now have rooftop solar and we are also seeing strong growth in home battery installations.’

‘One reason is cost. Australia does not manufacture solar panels at scale, but imported panels are inexpensive. Costs have continued to fall, both because equipment has become cheaper and because installers have become more efficient through experience. In cities such as Adelaide and Perth, rooftop solar can meet much of daytime electricity demand during favourable conditions.’

Batteries and the changing electricity market 
‘The energy transition creates new challenges as well as new opportunities. In the National Electricity Market, which covers most of Australia, average wholesale electricity prices fell 12% year-on-year in the most recent quarter. Batteries are now the most frequent price-setting technology in the market, replacing gas. They absorb low-cost solar generation during the day and discharge electricity during peak demand periods. Renewables supplied 46.5% of National Electricity Market generation during the first quarter of this year, the highest first-quarter share on record.’

Energy security and electrification 
‘Australia exports large quantities of coal and gas, yet imports most of its liquid fuels. Much of that supply chain remains exposed to global events. The disruption in the Strait of Hormuz has demonstrated how vulnerable energy markets remain to geopolitical shocks. It is creating economic hardship, but it is also accelerating the transition towards electrification.’

‘Fatih Birol [Executive Director] of the International Energy Agency has described the current disruption as a larger shock than the oil crises of the 1970s. Those earlier crises transformed energy policy around the world. I believe today’s shock will accelerate the adoption of technologies such as electric vehicles, batteries, solar and pumped hydro.’

What is the real challenge facing the transition? 
‘The real challenge is not whether renewables can provide low-cost energy. They clearly can. The challenge is building enough transmission, storage and firming capacity quickly enough to maintain reliability and affordability throughout the transition. The technologies exist. The question now is whether we can deploy the supporting infrastructure at the pace required.’

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Australia orders 7.8GW of renewables and 7.9GWh of storage in latest auction’. Discover more about the 19 projects awarded under Tender 7 of the Australian government’s Capacity Investment Scheme.
• ‘Australia scales up battery storage nationwide as states race to replace retiring coal’. With three-quarters of Australia’s coal-fired power plant fleet set to retire by 2030, Australia’s state governments and investors are increasingly deploying grid-scale battery projects to deliver firm capacity, integrate renewables and help stabilise electricity prices. 

Rather than supplying large volumes of day-to-day electricity generation, such plants are designed to provide power during periods of high demand or when renewable generation cannot meet system requirements. The three facilities will be remunerated through a combination of capacity market agreements, system support services and peak power generation, with capacity market contracts extending to 2039.

According to Drax, the plant can also operate as a synchronous compensator, providing services such as inertia and voltage control without generating electricity. Such services are becoming increasingly important as renewable generation displaces conventional power stations that historically helped maintain grid stability.

A similar approach is being taken by Statera Energy, which recently completed the first engine firing at its 450MW Thurrock Power project in Essex, ahead of full commissioning later this year.

The facility is co-located with a 300MW/600MWh battery energy storage system (BESS), creating a combined site capable of delivering 750MW of dispatchable capacity. Statera said the BESS will manage short-duration balancing requirements, while the gas-fired plant will provide sustained support during extended periods of low renewable generation.

The Statera Energy facilities are intended to strengthen grid resilience across London, Essex and southeast England, supporting electricity demand equivalent to up to 2.4 million homes. The project has also been designed with a pathway to future hydrogen operation.

Statera Energy’s 450MW Thurrock Power project in Essex

Photo: Statera Energy 

The Drax and Statera Energy projects highlight the growing importance of flexibility as renewable generation accounts for an increasing share of electricity production.

That role comes as gas continues to lose ground to renewables in the wider electricity mix.

Analysis published by energy think tank Ember found that gas accounted for 21.8% of global electricity generation in 2025, down from 23.9% in 2020, marking the fifth consecutive year its market share has declined.

The organisation found that 61 of the world’s 124 gas-generating economies have already passed peak gas generation, including the UK, Germany, Italy and Japan. Ember said solar outcompeted gas in 2025, with solar generation growing 17 times faster than gas generation and accounting for around three-quarters of new global electricity demand growth.

According to Ember, renewables are increasingly meeting new electricity demand growth, while concerns over fuel-price volatility, energy security and geopolitical disruption are encouraging greater investment in domestically produced electricity.

The findings suggest gas is increasingly playing a supporting role within electricity systems. While renewables continue to capture a growing share of generation, investment is continuing in assets designed to provide balancing services, system support and back-up capacity during periods of lower renewable output.

Workers in the sector are also more productive than average, generating £119,300 in economic value per job, around 48% higher than the national average, while mean salaries are approximately 11% above the UK average.

The ECIU report identified six economic hotspots where low-carbon industries generate more than £1bn in GVA, including areas in Scotland, Yorkshire and North Wales. Among England’s regions, Yorkshire and the Humber recorded the highest share of such activity, supporting more than 79,000 jobs.

Researchers also highlighted the scale of future activity already in development. The UK’s renewable energy pipeline now represents £455bn of planned investment across 262GW of capacity, with around two-thirds of projects either under development or in the construction phase.

Separate studies examining Scotland and Wales found that industries linked to the energy transition contributed more than £14bn in combined GVA during 2025 and supported nearly 150,000 jobs, underlining the growing role of low-carbon industries in the economies of the UK’s devolved nations.

In Scotland, industries linked to the transition contributed £10.2bn in GVA and supported more than 105,000 jobs in 2025, equivalent to 4.9% of Scottish economic output and 3.9% of employment. Activity spans energy generation and infrastructure, advanced manufacturing, engineering, construction, environmental services, and professional and technical services.

The report highlights Scotland’s central role in future UK energy infrastructure development. Around £211bn of planned UK energy infrastructure investment is located in Scotland, representing 34% of the national pipeline. Major projects include offshore wind developments, grid reinforcement schemes and energy storage infrastructure.

In Wales, energy-transition industries contributed £4bn in GVA and supported more than 41,300 jobs, accounting for 4.3% of economic output and 3.1% of employment. The sector includes more than 1,300 businesses operating across renewable energy, manufacturing, construction and engineering supply chains.

Researchers found that firms operating in the transition economy generate around £117,500 of value per worker, approximately 1.7 times the Welsh average. Planned renewable energy infrastructure projects worth £13.1bn could support further growth in the years ahead.

The Scottish and Welsh studies suggest the transition is becoming an increasingly important contributor to economic activity across the UK’s nations and regions.

The reports conclude that future growth will depend on converting planned investment into completed projects, supply-chain activity and long-term employment. Workforce development, policy stability and industrial capacity are expected to play an important role in determining how much of the economic value generated by the transition remains within the UK.

Pakistan provides a notable example. In 2022, solar module imports increased by 189% to $1bn, partly driven by the global fuel price shock following Russia’s invasion of Ukraine. Small-scale solar installations in the country reached a record 18.3 GW in 2025 following years of steady growth. This expansion has been supported by high electricity tariffs linked to costly LNG imports, as well as persistent power outages and load-shedding.

BNEF also highlights persistent overcapacity as a defining feature of global supply chains, largely driven by substantial Chinese investment. Manufacturing capacity is estimated to exceed global demand by more than 200% across the value chain, contributing to sustained margin compression for key clean tech products. Wind and battery markets are similarly oversupplied. At the same time, efforts to expand manufacturing capacity outside China are adding to the global supply surplus, with regions such as Southeast Asia, India and Turkey emerging as key solar manufacturing hubs alongside developing markets including Egypt and Ethiopia.

The analysis further examines efforts to ‘onshore’ manufacturing. Despite the introduction of numerous policy frameworks across Western economies, the findings indicate that the US and EU are unlikely to become competitive exporters at a global scale. Although factory capacity has increased, expansions have been concentrated downstream, while a number of previously announced projects are now facing delays or cancellations due to slow demand, shifting policies and intensifying competition.

Even though overcapacity persists, the report notes that clean energy equipment prices are no longer declining as rapidly as in recent years. Solar prices continued to fall in 2025, although the rate of decline slowed, primarily due to rising silver prices. Battery pack prices fell from $118/kWh in 2024 to $108/kWh, but again at a slower rate, largely reflecting elevated battery metal prices. In contrast, onshore wind equipment prices increased slightly as turbine manufacturers sought to recover earlier losses.

Hybrid renewables deliver cost-competitive 24/7 power, IRENA finds 
A separate report by the International Renewable Energy Agency (IRENA) confirms the increasing cost-competitiveness of round-the-clock renewable power through hybrid systems combining solar or wind and battery storage. The analysis finds that, in high-quality resource regions, such hybrid systems can deliver continuous power at lower cost than fossil fuel alternatives.

Firm levelised costs of electricity for solar-plus-storage are estimated at $54–$82/MWh in high-quality resource regions, compared with $70–85/MWh for new coal in China and more than $100/MWh for new gas globally. These hybrid configurations optimise the use of constrained grid connections, enable electricity generation to shift to higher-value periods and reduce exposure to price volatility. They are also said to be well-suited to energy-intensive users requiring uninterrupted supply, such as AI and data centres, and support the production of clean fuels for hard-to-abate sectors.

IRENA’s analysis shows that firm costs have declined rapidly, driven by falling costs for solar PV, wind power and battery storage. Since 2010, total installed costs declined by 87% for solar PV and by 55% for onshore wind, while battery storage costs have declined by 93%.

Further cost reductions are expected as a result of continued technological learning, increased manufacturing scale and improved supply chain integration.

IRENA analysis of solar-plus-battery configurations shows that firm costs have fallen from above $100/MWh in 2020 to around $54–82/MWh by 2025 in high-irradiance solar regions. Additional reductions of around 30% by 2030 and 40% by 2035 are projected, potentially bringing costs below $50/MWh at leading sites.

Firm wind plus storage systems are also becoming increasingly competitive. Estimated costs for 2025 range from approximately $59/MWh in Inner Mongolia to around $88–94/MWh across Brazil, Germany and Australia, with projections indicating further declines to around $49–75/MWh by 2030. 
 

Wind accounted for most of the awarded capacity, with 5.5 GW. The largest project selected is the 1.5 GW Yanco Delta wind farm in New South Wales, to be developed by Origin Energy. Other major projects include the 1.2 GW Bungaban wind energy project by Windlab and the 1 GW Theodore wind farm by Theodore Energy Development (led by RWE), both in Queensland.

Almost 2.5 GW of the total generation capacity will be delivered by solar projects, including the 200 MW Weasel solar farm being developed in Tasmania by Gamuda Renewables and Alternate Path.

Eight of the successful projects were hybrid, six of which were solar. They include the Birriwa 600 MW solar farm and 2,400 MWh battery being developed by Acen, and Lightsource BP’s Gundary 320 MW solar and 1,391 MWh battery project, both in New South Wales.

Federal Energy Minister Chris Bowen said the projects are expected to involve around $17bn in private investment and support approximately 19,000 construction jobs, while contributing to a more reliable electricity system.

RWE brings Australia’s first eight-hour battery into full operation
RWE has received approval from the Australian Energy Market Operator (AEMO) and transmission operator Transgrid to operate its Limondale battery energy storage system (BESS) at full capacity.

The 50 MW/400 MWh battery, located near Balranald in southern New South Wales, is the first in Australia capable of discharging at its rated output for more than eight hours. The system comprises 144 Tesla Megapacks which are uniquely registered to charge at 100 MW and discharge at 50 MW.

The project, located adjacent to the RWE Limondale solar farm, has completed grid compliance and performance testing, and has now moved from commissioning into full operations.

The data backs this up too. Evidence from the UK’s Energy Savings Opportunity Scheme (ESOS) scheme suggests that around 97% of recommended actions are technology-based. Leaving only 3% focused on people-based solutions.

The challenge is rarely a lack of technology. It is the human part of energy management. Who owns the problem, how they are using data, what gets prioritised, and all the bad habits that quietly undo good work. Handovers lose value. Enthusiasm fades. Good technical intent drifts.

This is the problem EnCO was created to solve.

Who we are
The EnCO Foundation (EnCO, for short) is a not-for-profit Charitable Community Benefit Society run by industry practitioners, for industry practitioners. EnCO is on a mission to make people-based solutions mainstream in global energy management and create energy conscious organisations everywhere.

‘People-based solutions’ is the term we use for the effective combination of technology, process and culture that makes energy performance stick. It includes what used to be labelled ‘behaviour change’, reframed into something more practical: how teams work, decide, govern, learn and improve.

How we got here
EnCO began as a response to a gap that practitioners across sectors kept running into. Consultants could propose relevant individual interventions but struggled to embed them. Organisations could fund projects but couldn’t sustain the gains. Individual behaviour change programmes were delivering results in some organisations, but the approaches behind them lived in the heads of a handful of experienced practitioners. No shared framework existed to describe what ‘good’ looked like on the human side of energy management.

A group of experienced practitioners, all part of the Energy Institute community, began piecing an idea together. They drew on decades of delivery experience and lessons from adjacent fields such as safety culture and quality management – where the shift from technology-only to people-and-process has long since happened – to develop the EnCO framework. And started what was at first simply an initiative to get this framework and surrounding theory into the hands of more practitioners. This became The EnCO Foundation, set up to support the industry.

What started out as a small working group is now a growing international community and centre of excellence for people-based solutions. Today, EnCO is a thriving network of trained consultants in 23 countries, as well as committed and certified energy conscious organisations across every sector, region and even size.

A community of practice – for practitioners, by practitioners
For Energy Institute members, this is perhaps the most important part of the story. EnCO is, first and foremost, a community of practice. It is a place where practitioners exchange what is working on the ground, stress-test approaches with peers, and contribute to the shared methodology the Foundation maintains and develops. The community meets regularly through working groups, case study exchanges and open forums, and it is deliberately international in outlook.

At its core, EnCO is a framework designed on the premise of continual improvement and commitment to good energy management practice. This is all made actionable through the five EnCO pillars that underpin the EnCO Matrix – a tool that supports the benchmarking of an organisation’s energy consciousness and supports the ability for continuous review and regular improvement.

The five pillars define what ‘energy conscious’ looks like in practice:

• Engagement: ownership and participation across the organisation, not just in facilities or sustainability teams.
• Alertness: making energy visible, understandable and hard to ignore, so people notice waste and act.
• Skills: building energy literacy and role-specific capability to spot opportunities and deliver change.
• Recognition: reinforcing the right behaviours through feedback and celebration, not only targets and reports.
• Adaptability: keeping programmes resilient as priorities, people and operating conditions change.

The EnCO Matrix takes those pillars and maps them against levels of maturity – from initial awareness through to fully embedded practice. It is the practical assessment tool that turns the framework into a clear picture of where an organisation stands today (ie defining reality), where it could be and what to prioritise next. Two organisations can both score strongly on ‘Engagement’, for example, yet land at very different points on the Matrix overall because one has senior-sponsored ownership and the other is running on the goodwill of a single champion. Together, the pillars define the ‘what’ and the Matrix defines the ‘how far’.

If this resonates, there are three easy ways to get involved today: explore the consultant training pathway if you want to lead programmes; get your organisation’s benchmark score and kickstart the EnCO conversation; support The EnCO Foundation by joining as a member and attend our events or webinars to see the evidence for yourself.

Energy is a people business. Technology adds the finishing touch. But people are the enabler. If we want the energy transition to stick, we need to get the human side right first – let’s do it together.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘The power of sharing experience on the road to net zero’. Achieving net zero emissions will require greater collaboration, cooperation and sharing of knowledge from a broad range of stakeholders, writes Paul Webb MEI, Chartered Energy Manager, Author, Podcaster and founding Director of B2B Energy.
• ‘Engaging colleagues in energy behaviour change in 2023’. A successful energy transition depends on behavioural changes, but these can be challenging to inspire, maintain and direct. Dr Mark Burrows, Client Development Director – Plan Zero, Mitie Energy, and Member of the EI Energy Management Panel presents some recommendations.

When an energy consultancy (or more precisely, a third-party intermediary) brokers an energy supply contract on behalf of a client, it earns a per-unit commission on every kilowatt-hour consumed for the duration of that contract. The revenue is recurring and relatively friction-free. It requires no site visits, no project management and little technical risk. It arrives automatically, indexed to the client’s consumption, for as long as the contract runs.

This income stream is, by a considerable margin, among the highest-margin activities most energy consultancies perform. The cost of servicing it is negligible once the initial procurement is complete. The gross margin substantially exceeds anything achievable through advisory services, energy audits or project delivery.

The consultancy’s business model is therefore optimised for maintaining energy consumption at a time when clients are increasingly trying to reduce it through efficiency, electrification and self-generation.

Every kilowatt-hour the client consumes generates revenue. Every kilowatt-hour the client saves reduces it. This creates a structural tension that much of the industry has yet to fully resolve.

The delivery disincentive 
The tension between procurement revenue and project delivery is not subtle. Yet the industry continues to treat it as a peripheral concern rather than a defining strategic challenge. Consider the commercial logic that follows a successful energy efficiency project.

A consultancy recommends a building services upgrade (LED lighting, HVAC optimisation or renewable generation) that permanently reduces a client’s annual energy consumption by a material percentage. The recommendation is sound. The client benefits. The carbon reduction is real. The consultancy’s reputation is enhanced.

The consultancy’s business model is therefore not optimised for reducing energy consumption. It is optimised for maintaining it.

But the consultancy’s procurement revenue is also reduced by the same proportion. The per-unit commission that flowed automatically from every kilowatt-hour consumed now flows from a smaller base. The reduction is not temporary. Every successful project the consultancy recommends, and every project it delivers, reduces its most profitable recurring revenue line.

The delivery project itself generates revenue, of course. But it is typically one-off revenue, earned at margins significantly lower than procurement commission. The delivery project also carries risk, requiring site management and consuming operational bandwidth. This is the commercial tension at the heart of the prevailing energy consultancy model.

Why the cultural resistance? 
In many energy consultancies, the individuals who hold the most senior commercial positions have built their careers, and compensation structures, around procurement revenue. Departmental budgets, commercial performance and internal influence are often closely tied to the margin performance of the procurement book.

These individuals are not irrational. They recognise the value of project delivery in principle. But when a specific project proposal crosses their desk (one that will permanently reduce metered consumption for a key client) the commercial calculus becomes more complicated.

The result is a form of institutional resistance that rarely presents itself as opposition to delivery. Instead, it manifests as caution: concerns about liability, questions about capability, requests for further analysis or suggestions that the timing is not right. The consultancy’s genuine lack of delivery experience can become a justification for reluctance that is, at least in part, commercially driven.

Regulatory and transparency pressures are beginning to surface these dynamics. Clients are increasingly aware of the commission structures embedded in their energy contracts, and some are demanding greater disclosure.

But transparency alone does not change the underlying incentive structure. A consultancy may disclose that it earns commission on energy consumption, but the commercial reality remains the same: successful energy reduction can still reduce its most profitable recurring revenue stream.

Why is this a threat to energy consultancies? 
The commission paradox would be an internal strategic problem, uncomfortable but manageable, if it existed in isolation. It does not.

The market in which energy consultancies operate is fragmented, competitive and increasingly transparent. A consultancy’s reluctance to deliver is not invisible to the market. It is an opportunity for competitors offering integrated advisory and delivery capability.

If a consultancy’s client has committed to net zero targets, adopted a science-based carbon reduction pathway or simply recognised that energy efficiency projects deliver genuine cost savings, that client will seek delivery from someone.

The question is whether the reluctance to deliver is fundamentally a capacity problem or a compensation mechanism.

If the incumbent consultancy cannot or will not deliver, the client has two options: procure delivery independently or engage a competitor that offers both advisory and delivery as an integrated service.

The competitor that takes the delivery relationship does not stop at project management. It builds a direct relationship with the client’s facilities team, develops operational familiarity with the estate and demonstrates delivery capability. When the procurement contract comes up for renewal, that competitor is already embedded within the account.

The incumbent consultancy’s choice is therefore not between full procurement revenue and reduced procurement revenue. It is between a smaller revenue stream (procurement commission reduced by successful delivery) and potentially no revenue stream at all because the client relationship has migrated elsewhere. That is the strategic reality now emerging across parts of the sector.

What is the point of greatest vulnerability?  
The sharpest expression of this competitive risk occurs at contract renewal. Procurement contracts typically operate on multi-year cycles. For the duration of the contract, the incumbent consultancy’s position can appear secure. Revenue flows. The client relationship appears stable.

But renewal creates a moment of re-evaluation. Procurement teams and increasingly sustainability teams ask a relatively simple question: what has this relationship delivered?

If the answer is advisory reports and procurement services alone, the incumbent may become vulnerable to competitors offering advisory, procurement and delivery as a combined proposition.

The competitor does not necessarily need to undercut on price. It only needs to demonstrate that it can convert recommendations into measurable outcomes. For consultancies with large procurement books, this vulnerability is not theoretical. It recurs every time a contract approaches renewal.

What can be done?  
The consultancies navigating this transition most successfully tend to share one characteristic: they have stopped pretending the conflict does not exist.

The commission paradox is not a problem resolved through incremental improvement, additional sales training or simply bolting on another service line. It requires a structural response – a deliberate decision to build or partner with delivery capability that allows the consultancy to convert its own recommendations into implementation.

One possible response is a delivery assurance model in which a specialist layer sits between the consultancy and the subcontractor, managing procurement governance, contract architecture, site oversight and margin protection. The consultancy retains the client relationship and advisory revenue. The subcontractor carries the delivery risk. The assurance layer manages the interface.

Within this structure, commission erosion created by successful delivery can be offset through additional revenue streams, including delivery margin, maintenance and monitoring contracts, and stronger long-term client retention.

The consultancy does not replace procurement revenue with delivery revenue. It supplements a reduced procurement stream with a broader and potentially more resilient commercial base. But this approach requires an honest internal conversation.

The question is not simply whether the consultancy lacks the technical skills to deliver because those gaps can often be addressed through partnership. The question is whether the reluctance to deliver is a capability issue or in fact a compensation protection mechanism.

The consultancies that address that question honestly are likely to define the next phase of the energy services market. Those that do not may find themselves increasingly exposed as client expectations, competitive pressures and commercial models continue to evolve.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘The consultancy ceiling: why energy advisory firms struggle to capture delivery revenue’. Energy consultancies occupy a paradoxical position in the market. They are trusted to diagnose problems, quantify savings and recommend solutions – yet the moment a client asks ‘Can you deliver this?’, the most profitable part of the relationship walks out the door. The solution is to build a delivery layer, argues Managing Director of Optimised Energy David Hesketh.
• 'Connecting the dots for SMEs’ net zero journey’. Where do I start? This is the question most small and medium-sized enterprises (SMEs) ask themselves as they try to respond to increasingly ambitious sustainability and net zero goals. Discover the answer.

The Copi project is the second critical minerals mining development approved by the Minns Labour government in four months, following the Aeris Resources Constellation project for copper ore. The project was also recognised at the 2025 Quad leaders’ summit, where the US, Japan, India and Australia designated it as a supply chain asset and announced financing from the US Export-Import Bank (EXIM).

‘Receiving NSW development approval for the Copi project is a defining moment for RZ Resources, for the Wentworth community and for Australia’s critical minerals sector,’ stated David Fraser, Founder and Executive Chairman of RZ Resources. He added that the deposit represents an ‘opportunity that will help Australia and its allies secure supply chains for the materials which underpin energy, manufacturing and defence’.

Government officials stated that the approval aligns with broader state policies targeting the extraction of critical elements. ‘NSW is home to some of the world’s most significant critical mineral deposits and we are focused on turning that potential into long-term investment and industry growth,’ said NSW Minister for Natural Resources Courtney Houssos, noting that the state contains 21 of the 31 minerals identified on Australia’s national critical minerals list.

NSW Minister for Planning and Public Spaces Paul Scully stated that the development ‘will help secure the supply of critical minerals to help power clean energy, telecommunications and medical device technologies while supporting hundreds of jobs in NSW’s Far West’.

A growing divide

The expansion of critical mineral assets in Australia illustrates a growing divide between where minerals are extracted and the nationality of the entities that own them. For example, data from Wood Mackenzie shows that while African geography will account for 13% of global lithium extraction by 2030, corporations based in African nations are expected to own only 1% of total output.

‘With few exceptions, Africa’s lithium growth has been financed by Chinese capital,’ Pedersen stated, highlighting structural issues related to ‘ownership, value capture and long-term supply chain influence’.

Wood Mackenzie also identified a structural constraint, as brine-based lithium extraction methods require longer timeframes and more complex scaling processes compared to the rapid expansion seen in hard-rock spodumene and lepidolite mining operations elsewhere.

Analysis from Wood Mackenzie shows that Chinese corporations are on track to control 39% of global lithium extraction by 2030, up from approximately one-third in 2020. ‘Lithium production and lithium ownership are increasingly diverging, and it is changing the global critical mineral supply chains,’ stated Allan Pedersen, Research Director for Energy Transition and Battery Materials at Wood Mackenzie. ‘While production growth is becoming more geographically diverse, ownership remains concentrated among a relatively small group of companies, mostly led by China.’

The regional distribution of global mineral supply is expected to change by 2030, particularly in established mining regions such as Australia. In 2020, Australia accounted for 43% of global lithium extraction, but Wood Mackenzie forecasts this will fall to 25% by 2030 due to faster growth in other countries. This market share adjustment is said to be primarily driven by expanded extraction operations in Africa.

New lower cost lithium extraction process

Beyond changes in regional ownership, industrial mining processing requirements are also driving international technical research into extraction costs and infrastructure changes. Researchers at the US Massachusetts Institute of Technology (MIT) have developed an alternative process for extracting battery-grade lithium from hard-rock spodumene minerals. The researchers have developed a closed-loop extraction process that operates at room temperature to break down the rock matrix. This method uses a liquid chemical reagent mixture consisting of water and ammonium fluoride to dissolve the silica components first.

The research team estimates that the closed-loop process reduces processing costs by half compared to traditional high-temperature hard-rock lithium extraction methods (baking at 1,000°C, followed by chemical leaching). This cost reduction is projected to make hard-rock processing cost-competitive with lithium extraction from traditional brine-water evaporation operations.

‘Hard rock is abundant; you can find it everywhere. But most hard rock refining is done in China. Our central thesis is to enable regional production,’ explained Camden Hunt, former Project Manager at MIT’s Centre for Electrification and Decarbonisation of Industry and co-author of the study.

‘We believe this approach is the lowest-energy, lowest-cost way of getting lithium not only out of hard rock, but period,’ stated Yet-Ming Chiang, co-author of the study and Kyocera Professor of Materials Science and Engineering at MIT. ‘That’s what’s motivating us to scale this. It will enable the energy transition through batteries that use lithium.’

Critical mineral production in 2025, along with figures for some 10 other key energy commodities, will be published on 30 July in the Energy Institute 's Statistical Review of World Energy. Sign up to receive updates via https://www.energyinst.org/statistical-review
 

Ofgem said higher wholesale energy costs accounted for most of the increase for households on standard variable tariffs.

Energy consultancy Cornwall Insight has warned bills could rise again later in the year if wholesale market pressures persist, particularly after renewed instability in global gas markets linked to tensions in the Middle East.

Trade body Energy UK said the increase would place additional pressure on households already struggling with energy affordability.

National Energy Action, which campaigns on fuel poverty, warned vulnerable consumers would be disproportionately affected by higher bills.

The Energy and Climate Intelligence Unit (ECIU) said rising gas prices linked to instability in the Middle East were continuing to feed into household energy costs because gas can still play a disproportionate role in setting wholesale electricity prices.

However, the situation continues to change, as renewables account for a larger share of UK electricity generation.

Recent analysis commissioned by UK energy firm Drax said the UK grid came close to fossil-fuel-free operation for sustained periods during April as high renewable generation reduced demand for gas-fired power generation.

The company also said the UK is now the most interconnected large power system in Europe, with interconnectors allowing electricity to move between the UK and neighbouring markets when supply and demand conditions change.

According to the report, written by Imperial College London researchers, growing interconnection capacity and the ability to shift electricity demand could play a larger role in balancing future low-carbon electricity systems as renewable generation expands.

It also suggested major power consumers, including AI data centres, could help balance the system by shifting some electricity consumption away from peak periods or towards times of high renewable output.

Wren Kitchens’ rooftop solar installation in Barton on Humber is said to become the UK’s largest, at 6.6 MW capacity, once some 13,000 panels are installed
Photo: Wren Kitchens
 

The plant was developed by UK-Spanish joint venture Biscay Eco Aggregates in partnership with Northern Ireland-based O.C.O Technology, which has previously deployed accelerated carbonation systems in the UK. The companies describe the project as the first full-scale deployment of the technology in continental Europe.

The process uses industrial waste materials, including fly ash from waste incineration, together with captured CO₂, to produce construction aggregates. Under controlled conditions, the CO₂ reacts with the waste material to form the stable mineral calcium carbonate (CaCO₃). The technology is attracting growing attention across the construction materials sector as producers explore ways to reduce emissions linked to cement, aggregates and infrastructure development while also reusing industrial waste streams.

The growing focus on industrial carbon capture comes as UK industry groups warn that cement-sector emissions are becoming a growing constraint on future infrastructure delivery.

Recent analysis from the Mineral Products Association (MPA) reportedly suggests carbon-capture infrastructure could become increasingly important if the UK is to maintain domestic cement production while meeting future carbon budgets.

The MPA has argued that carbon capture and storage (CCS) is expected to deliver a substantial proportion of the emissions reductions required under the cement sector’s net zero pathway. Industry groups have also warned that delays to carbon-management infrastructure could increase reliance on imported cement and construction materials, potentially shifting emissions overseas rather than reducing them.

Industry groups increasingly argue that delays to carbon-capture infrastructure could affect future housing, transport, energy and industrial projects as emissions limits tighten.

The cement sector faces particular pressure because a significant proportion of emissions generated during cement manufacturing come from the cement (clinker) production process itself, making them difficult to eliminate through electrification and energy-efficiency measures alone.

As a result, producers are increasingly exploring a combination of carbon capture, alternative fuels, clinker substitution and material innovation as part of broader decarbonisation strategies.

The overhead line refurbishment coincides with a separate capacity upgrade at the western end of the circuit. On 23 May 2026, a 120-tonne supergrid transformer arrived at the Mannington substation to increase local transmission capacity. The transmission line refurbishment is scheduled to finish in November.

The maritime industry is a crucial sector upon which offshore wind power relies. When considering hypothetical major incident scenarios for the industry, with potential for multiple casualties or catastrophic asset damage, most will involve a vessel. Keeping our people safe while on vessels, whatever the task, is imperative. The vessels must be safe, be operated safely, and coordinating marine traffic is crucial, especially where the seabed is getting busier and the industry interfaces with other users of the sea.

But it is important to recognise that the same vessel standards, and even the same vessels, are used in offshore wind as in other maritime industries, with the same international offshore regulations, guidelines and practices applying.

And offshore wind has benefited from decades of evolution in safety and the accumulated operational experience from wider energy, maritime, manufacturing and construction sectors. Offshore wind has not developed in a vacuum and with no understanding of what came before.

But the nature of the offshore environment alone doesn’t mean offshore wind exposes workers to the levels of occupational hazards managed on a daily basis by other types of energy sector operations. We’re not talking about a direct connection to huge reservoirs of hydrocarbons, for example, or working near radioactive nuclear fuel that requires continuous active cooling. In both cases, not managing those hazards can have enormous environmental and human impacts. Yes, there are operations in offshore with the potential for multiple casualties. But also, no, that potential is neither constantly present for the majority of the lifecycle, nor is it to the level seen in other energy sectors.

Offshore wind has benefited from decades of evolution in safety and the accumulated operational experience from wider energy, maritime, manufacturing and construction sectors.
 

G+ recognises the importance of working with industry best practice, so it has adopted the safety data reporting definitions used by the International Association of Oil and Gas Producers (IOGP). That means that it is feasible to compare injury rates published by the two industry bodies. But just because comparisons are possible doesn’t mean that they are necessarily helpful, and may lead to misleading conclusions. When we do headline comparisons, we can miss the nuance and complexity each unique dataset has, and therefore miss opportunities to meaningfully learn from each other.

In this specific case, it is important to recognise that the G+ dataset was, until 2019, a European dataset, and even though the last couple of years have seen a large spike of activity in the Asia-Pacific and US, work hours from Europe hover around 60% of the database. This matters because injury rates in Europe, as reported by IOGP, are much higher than for other regions.

Another crucial point is to understand that the assigned category of severity of an injury (eg lost work day cases) depends on the working context, among other factors, not just the actual severity of the injury. A considerable proportion (between half and a third depending on year) of lost time injuries in the G+ data are due to sprains or strains, or resulting in bruises or contusions. In wind, workers are primarily travelling to their offshore worksite daily, with very physically demanding transfer to reach the assets and perform their roles. This means that for offshore wind workers, even relatively minor injuries that might be otherwise categorised as ‘first aid’ or a ‘medical treatment’ case will be counted as ‘lost work days’ when they lead to a wind technician not being cleared to transfer to the turbine or substation.

Good practice guidance
In a previous life, I was part of the IOGP task force that developed the Life-Saving Rules. To do that we read through the descriptions of nearly 500 fatal incidents that had occurred in the previous 10 years. I will never forget that experience. These days at G+, when I read through the narrative descriptions of even the worst incidents in the G+ database, cases where someone lost their life or had a permanent injury are a rarity.

G+ is proud of its data-led good practice guidance programme, such as the Safe by Design workshops that have led to recommendations to the industry that have changed how turbines, equipment and systems are designed. And we do so through collaboration whenever we can; for example, with the DROPS dropped object safety scheme, HeliOffshore for our helicopter guidance, or the International Marine Contractors Association (IMCA) on so many topics. We collaborate to achieve our common safety goals.

Still, offshore wind is not so naïve as to declare that serious accidents can never happen. Multiple fatality events have happened (although not to G+ members). It is crucial to explore our blind spots and understand our changing risk profile.

Injury rates can be poor indicators of broader safety. While the G+ data also includes asset damage data, and there are some leading indicators in our hazards and near-miss reporting, we still have work to do to develop a better understanding of leading indicators for the safety and reliability of the system. Data must support us as we seek to better understand our multiple casualty scenarios and probe the presence and strength of the barriers we have in place to prevent them. Research and fresh perspectives play a significant role in continuing to examine the changing risk profile of the industry and supporting the G+ mission to ensure the safety of those who build, maintain and decommission offshore wind farms. G+ welcomes all such efforts.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Health and safety: Why the new G+ lifesaving rules for offshore wind are so important’. What are the 10 fundamental safety rules for those building and working on offshore wind energy? Find out about the rationale behind the rules and why they are needed.
• ‘Making industry safer, one job at a time’. Discover the value of reporting incidents both for individuals and companies working both in offshore wind and in other industries, according to Siemens Gamesa’s Graeme Paterson, Global Head of Health, Safety and Environment for Offshore.

Benchmark crude prices have swung sharply amid continued uncertainty over whether the US and Iran will reach an agreement to reopen the Strait and end the conflict. According to the IEA, North Sea Dated crude rose to a peak of $144.68/b in early April before easing back towards $111/b by month-end.

Despite the scale of disruption, the immediate supply-demand gap has been partly contained because the market entered the crisis in surplus and because both producers and consumers have adjusted rapidly to changing conditions.

Saudi Arabia and the United Arab Emirates have redirected some exports to terminals outside the Strait, while emergency stock releases and higher output from producers outside the Middle East have helped offset part of the losses. Observed global inventories, including oil in transit, have continued to fall as consuming countries draw on strategic and commercial reserves.

Supply growth expectations from producers in the Americas have also been revised higher, while Atlantic Basin crude exports have increased sharply since February as suppliers attempt to compensate for reduced Gulf flows. Additional shipments from the US, Brazil, Canada, Kazakhstan and Venezuela are increasingly being redirected towards Asian markets.

At the same time, higher prices and supply constraints are reducing demand and refinery activity across several major markets.

Global oil demand is now forecast to contract in 2026, with the IEA expecting the sharpest decline during the second quarter as higher prices, weaker economic conditions and demand-saving measures impact consumption.

Petrochemical feedstocks and jet fuel have been among the most heavily affected product segments following the loss of Gulf exports. Chinese crude imports have fallen sharply since February, while major import reductions have also been recorded in Japan, Korea and India as refiners scaled back activity.

The slowdown in global refinery activity has temporarily eased pressure in crude markets. However, the IEA warned supply pressures are increasingly spreading into refined product markets instead.

Even under the IEA’s ‘base case’ assumption that the conflict ends by early June and flows through Hormuz gradually resume during the third quarter, the agency expects supply to remain below demand through most of 2026.

Its latest estimates suggest the cumulative oil deficit will continue widening through the summer despite coordinated emergency stock releases. Rebuilding depleted strategic and commercial inventories could require several years of additional supply growth on top of underlying demand recovery.

While higher refinery output later in the year could ease some pressure in refined fuel markets, the report suggests the effects of the Hormuz disruption are likely to continue shaping global oil supply and demand well beyond the immediate crisis period.

Countries including Vietnam, Japan, Indonesia and India paid between 3% and 6% of their GDP on energy imports in 2025. The European Union and China currently spend 2.3% and 2.7% of GDP on energy imports respectively, but will rapidly reduce these liabilities over the next decade, as net exporters such as the US and Saudi Arabia are also forecast to see modest declines in imports.

While energy security concerns may prompt some coal-rich nations to re-emphasise coal use, BNEF says the fuel cannot compete on cost over the long term. It expects its share of power generation to fall to around half of current levels by 2050.

Under this scenario, electricity meets two-thirds of new energy demand over the next 24 years, while natural gas supplies a further 25%, with demand driven largely by electric vehicles (EVs), data centres and other electrification.

One big consumer of electricity is AI. Global data centre capacity reached 84 GW in 2025, consuming 500 TWh of electricity – around 1.9% of total demand – up 20% year-on-year. In the forecast, demand from data centres will more than double to 1,114 TWh (3.6% of total demand) by 2050, representing a 10th of electricity consumed worldwide.

The report expects energy transition timelines to diverge widely by region. China is rapidly electrifying, with electricity already the dominant final energy carrier by 2023. Coal’s share of power generation is forecast to fall from about 54% in 2025 to 19% in 2035 and 7% by 2050. In India, electricity will overtake oil and coal by 2041 despite continued coal use in industry. In Europe, electricity becomes the dominant fuel by 2043, while the US transitions more slowly (by 2047).

The report also predicts that solar will become the world’s largest generator of electricity by 2032, driven by massive overcapacity and falling prices. Additionally, the outlook for battery deployment has increased, with storage jumping 17-fold from 223 GW in 2025 to 3.8 TW by 2035.

David Hostert, Chief Economist at BloombergNEF, commented: ‘We’re living in another moment of crisis, but unlike in past decades, today there are real options for countries to react. We now have viable technologies that can be deployed at scale and fast, at an overall lower cost to the system than the fossil fuel technologies that used to be the primary choice. Through clean power and electrification, we can strengthen energy security and reduce harmful emissions along the way.’

Global energy transition investment reached a record $2.3tn in 2025, but BNEF estimates far higher spending will be needed by mid-century to deliver a fully decarbonised system. That gap was echoed by the International Renewable Energy Agency (IRENA), which warns that current energy systems remain structurally unprepared to meet the 1.5°C climate goal, even if renewable capacity is tripled and energy efficiency doubled by 2030.

Under IRENA’s revised 1.5°C scenario, the share of global energy consumption taken by electricity rises from 23% today to 35% in 2035 and more than 50% in 2050, with most of the increase met by renewables. Over the same period, fossil fuels would fall from around 80% of energy use today to 20% or less in 2050.

IRENA says that whilst electrification is becoming the primary driver of fossil fuel decline across all major sectors, delivering this shift will require a fundamental restructuring of energy infrastructure and investment allocation. Countries must invest in grids, storage and system flexibility to ensure reliable and affordable electricity systems capable of supporting growing demand.

The report finds that infrastructure has become a critical bottleneck, with around 2,500 GW of wind and solar globally awaiting connection to grids. Upgrades by 2035 and 2050 will not be achieved without permitting fast-tracked and investment scaled up. IRENA estimates grid investment needs at $1.2tn per year on average, more than double the $0.5tn invested in 2025. Additional investment will also be needed in hydrogen, alternative fuels and electrification infrastructure, from EV charging to building retrofits and industrial systems.

Unlike batteries, solid oxide systems either produce hydrogen using electricity and steam, or generate electricity from fuels such as hydrogen and natural gas. Developers believe the high-temperature electrochemical systems could help reduce emissions in sectors that are difficult to decarbonise while improving efficiency in industrial processes and off-grid energy systems.

One of the clearest signs of industrial scale-up came from German electrolysis company Sunfire, which recently announced plans to build a solid oxide electrolysis test facility at chemical company BASF’s site in Schwarzheide, Germany.

Solid oxide electrolysers use electricity and high-temperature steam to produce hydrogen and are seen as potentially more efficient in industrial environments where heat is already available. The BASF facility will evaluate large-scale hydrogen production using steam and industrial waste heat generated on site.

Developers see particular potential for the technology in sectors such as chemicals, refining and heavy manufacturing, where hydrogen demand is expected to increase as companies pursue lower-carbon production processes.

At the same time, solid oxide fuel cell systems, which generate electricity from fuels such as hydrogen or natural gas, are increasingly being explored as alternatives to diesel generation for backup and off-grid electricity supply.

Centrica and Taiwanese electronics manufacturer Delta Electronics recently launched a scalable off-grid power solution aimed at applications including remote infrastructure and data centres. The companies said the modular system is designed to provide continuous low-emission power generation in locations where grid connections are either constrained or unavailable.

Interest in fuel cell systems has increased in recent years as operators seek more reliable and lower-emission power options for critical infrastructure, particularly as data centre electricity demand continues to rise.

Companies are also focusing on improving the economics and operational performance of hydrogen production systems. Schneider Electric and Microsoft recently demonstrated what they described as India’s first fully autonomous solid oxide electrolyser system, using AI-driven monitoring and optimisation tools to improve performance and reduce operating costs.

The system uses real-time analytics to monitor plant and equipment performance, with automated recommendations designed to improve efficiency, extend operating life and optimise hydrogen output. According to the companies, autonomous optimisation could reduce production costs by up to 10%.

The growing emphasis on scalability and operational flexibility was also reflected in the launch of Endura, a new solid oxide platform from UK-based fuel cell and electrolyser developer Ceres. The company said the system has been designed to support both power generation and hydrogen production applications, with a focus on scalability and integration into industrial energy systems.

In more negative news, Danish firm Topsoe has announced a review of its clean hydrogen strategy, which reportedly includes temporarily closing the Herning, Denmark, solid oxide electrolyser cell factory that it opened in October 2025 because of weak customer demand.
 

Together, they will provide 4 GW of installed capacity, which the developers said will generate enough electricity to power about four million average UK homes each year. According to industry association RenewableUK, this decision provides a boost to the UK’s energy security, with the combined capacity of these projects equivalent to a quarter of the UK’s entire current operational offshore wind fleet.

Dogger Bank South advanced financially this year through the UK’s renewable subsidy framework. In January 2026, both projects secured contracts for difference (CfD) from the UK government during Allocation Round 7 (AR7). With planning permission granted, RWE and Masdar stated they will now complete the final design and procurement, aiming to reach a final investment decision in 2027.  

The North Falls project will be located approximately 40 km from the East Anglia coast at its nearest point and would be an extension to the existing 504 MW Greater Gabbard offshore wind farm. The DCO allows for the construction of up to 57 wind turbine generators, their associated foundations and up to two offshore substation platforms and associated foundations. Following the DCO, the project will fine tune its designs in order to determine the final installed capacity. The project will target a future CfD in advance of a final investment decision.

Deployment slowdown and grid targets
These approvals occur amid warnings from energy sector representatives about the pace of deployment. The 2026 Wind Insight report by trade association Offshore Energies UK (OEUK) states the UK must install at least 5 GW of new offshore wind capacity each year to reach the government’s clean power targets. Current projections show the UK will reach just over 30 GW of offshore wind capacity by 2030, which the report noted is well below the government’s target of 43 GW by the end of the decade.

The report recommends that the government increases the capacity awarded in upcoming subsidy auctions, targeting up to 7 GW in Allocation Round 8 (AR8). This target, OEUK stated, aims to keep projects affordable and secure the required volume.

Second, the report warns that new wind farms cannot deliver electricity unless the domestic grid keeps pace with offshore construction. OEUK says that all planned grid upgrades must be completed by 2028 to unlock projects in development.

Third, OEUK backs a fixed schedule of annual auctions to deliver at least 5 GW per year from 2026 to 2030. Thibaut Cheret, OEUK’s Wind and Renewables Manager, said that a clear timetable helps supply chains plan investments, keep skilled jobs, reduce costs and position the UK to export offshore expertise.

The Bristol-based company, which uses treated biosolids as a feedstock, said the deal provides a key component for scaling its production process.

Under the agreement, Altaca will supply its CatLiq hydrothermal liquefaction technology, which converts sewage sludge into a crude oil substitute. The process is intended to form part of Firefly’s ‘wet-to-jet’ system for producing aviation fuel.

Firefly plans to source raw material for its first project from UK water companies, positioning the facility as a potential solution to both waste management and low-carbon fuel demand.

Other partners include Chevron Lummus Global, which will provide downstream refining technology. Airline Wizz Air has also signed a £5mn, 15-year agreement to purchase up to 525,000 tonnes of fuel produced by the project.

In other news, Kingston University has joined a European Union-funded project aimed at transforming wastewater into renewable energy and fertilisers.

The project, known as CeSuds (Circular Economy approaches to Digested Sludge Utilisation), brings together research and industry partners across Europe to develop new ways of converting sewage sludge into usable resources.

The four-year project, led by the University of Limerick, will focus on hydrothermal carbonisation, a process that uses heat and pressure to turn sludge into fuel, biogas and nutrient-rich materials that can be used in fertilisers.

Researchers will also examine how to remove harmful contaminants such as pharmaceutical residues and so-called ‘forever chemicals’, which are making traditional sludge disposal methods like land spreading increasingly difficult.

Kingston University will analyse how these pollutants break down during the process and how treatment methods can be optimised.
 

Theoretical maximum efficiency for conventional silicon photovoltaic (PV) cells sits at around 29%. While leading commercial products are already approaching the upper end of that range, they are running out of headroom. Incremental improvements remain possible, but they are becoming harder and more expensive to achieve.

It is within this context that perovskite-based multi-junction solar cells have emerged as one of the most closely watched developments in renewable energy.

Why perovskites are attracting attention 
Perovskite materials have attracted global attention because they can capture sunlight more efficiently than conventional silicon alone. Unlike traditional solar cells, perovskites can be engineered at a molecular level to absorb different parts of the solar spectrum more effectively. When combined with silicon in tandem or multi-junction solar cells, this allows more of the sun’s energy to be converted into electricity from the same surface area.

Demonstrations of perovskite tandem solar cells have already exceeded 30% efficiency, with the potential to surpass 35%. Such advances represent more than a technical milestone. They could materially alter the economics of solar deployment.

Higher efficiencies would allow more electricity to be generated from the same surface area. For rooftop systems, this could improve energy self-sufficiency without requiring additional space. For utility-scale solar farms, it could reduce land-use requirements, infrastructure costs and accelerate return on investment.

The technology also offers advantages beyond efficiency. Perovskites are compatible with lightweight and flexible substrates, opening potential applications beyond traditional PV panels. Building-integrated photovoltaics could transform façades, windows and roofing materials into energy-generating assets integrated directly into urban infrastructure.

The challenge is now commercial readiness 
The potential of perovskite multi-junction solar cells is clear, but significant challenges remain before the technology can achieve widespread deployment.

The central issue is no longer laboratory performance. It is whether the technology can demonstrate long-term durability, scalability and bankability under real operating conditions.

Unlike silicon, which is chemically and structurally robust, perovskites are more vulnerable to environmental stress. Exposure to moisture, heat and prolonged ultraviolet radiation can degrade performance over time. While encapsulation techniques and material improvements are advancing rapidly, the industry still needs confidence that perovskite systems can operate reliably over the 25 to 30-year lifespans expected of commercial solar assets.

Manufacturing scalability presents another challenge. Much of the progress achieved so far has been in laboratory environments using fabrication techniques such as spin-coating that are unsuitable for industrial production. Commercial deployment requires processes capable of delivering consistent quality at high volumes and competitive cost.

Techniques such as vapour deposition, where ultra-thin perovskite layers are applied in controlled conditions, and roll-to-roll printing, which allows solar cells to be manufactured continuously at large scale, are being explored, but these must still be refined and validated at scale.

This is where independent testing, engineering guidance and certification frameworks become increasingly important. Organisations such as RINA play a role in helping emerging technologies demonstrate not only efficiency, but also long-term reliability, operational resilience and financial viability under real-world operating conditions.

Toxicity also remains a consideration. Many perovskite formulations contain lead, raising environmental and regulatory concerns. Research into lead-free alternatives continues, though these often involve trade-offs in performance.

Why Australia?  
Australia has emerged as one of the most strategically important environments for next-generation solar research and deployment. Its combination of high solar irradiance, geographically diverse climates and a rapidly evolving electricity grid with high penetration of renewables makes it an ideal testbed for next-generation photovoltaic technologies. Australia’s extreme climate, including intense UV exposure and demanding wind loads, enable accelerated degradation studies, providing insights into long-term performance that would take significantly longer to obtain in more temperate regions.

Government-backed initiatives played a decisive role in placing Australia at the forefront of next-generation solar. Funding from the Australian Renewable Energy Agency (ARENA) has supported the development of perovskite and tandem solar cell research, enabling institutions such as the Commonwealth Scientific and Industrial Research Organisation (CSIRO) and the University of New South Wales (UNSW) to advance work in stability, scalability and large-area manufacturing.

Beyond materials research, Australia is also at the forefront of system-level innovation. High penetration of PV and battery energy storage systems is driving research into grid-forming inverters, hybrid plant optimisation and system-strength remediation, all of which are essential for maintaining stability in increasingly renewable-dominated grids.

Emerging applications such as floating solar are also gaining traction, particularly across inland water bodies, expanding the scope of solar deployment in the region.

From RINA’s perspective, Australia represents an important bridge between laboratory innovation and commercially bankable deployment. The combination of advanced research capability, supportive policy frameworks and complex operating conditions makes the country strategically valuable in validating emerging solar technologies under real-world conditions.

What’s the next step for perovskite?  
The first phase of the solar transition focused heavily on reducing costs and scaling deployment. The next phase is likely to place greater emphasis on system integration, infrastructure constraints and energy density.

Higher-efficiency technologies such as perovskite multi-junction solar cells could help address some of these pressures by increasing output from constrained physical footprints while supporting a broader range of deployment models.

However, the industry should avoid assuming that strong laboratory performance alone guarantees commercial success.

Questions around manufacturing scale-up, certification standards, degradation rates, supply chains and environmental compliance remain unresolved. The sector has seen similar technology cycles before, where promising research outcomes did not automatically translate into durable commercial deployment.

Independent technical validation and certification will therefore play an increasingly important role in bridging the gap between scientific progress and industrial adoption.

Perovskite multi-junction solar cells represent one of the most promising frontiers in solar technology. But their long-term significance will depend less on efficiency records alone and more on whether the industry can successfully deliver reliable, scalable and bankable deployment at commercial scale.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘TNO develops perovskite solar roof tile’. TNO’s new perovskite based solar roof tile is claimed to demonstrate the integration of flexible PV modules onto curved roofing surfaces with minimal efficiency loss. Meanwhile, a new monitoring system that enables module-level fault detection in utility-scale photovoltaic plants is being developed by researchers at the Fraunhofer Institute in Germany.
• ‘Shining a light on solar capacity factors’. By 2029 solar PV is on course to be the largest source of renewable generation worldwide. But that does not mean all solar panels are as effective in generating power as others. Discover more about the solar capacity factors of the top 20 solar PV generating countries and the technologies being developed that could improve them.

The government sees Local Plans as having a role to play in identifying land suitable for energy infrastructure. This is not mandatory, however, and it is difficult to see how, practically and meaningfully, broad areas of land can be identified in Local Plans as suitable for the mix of renewable energy generation types, as well as for energy storage, balancing and distribution.

It requires a much more granular approach which marries suitability with deliverability. Rather than searching for broad areas suitable for energy development, Local Plans could adopt a site specific, evidence-based, allocation process specifically for energy infrastructure. To make this process truly meaningful requires two key changes:

• A new early stage in the Local Plan preparation process, to invite the energy industry to put forward land and sites that it considers suitable: a ‘call for energy sites’ process. 
• An award of ‘permission in principle’ for energy development on land subsequently allocated for energy development in the Local Plan.

Crucially, this approach would shift the emphasis from identifying theoretically suitable broad areas of land to identifying suitable sites for deliverable energy development.

At present, grid connection processes favour schemes with full planning permission as a proxy for construction readiness. This incentivises, or rather pushes, developers to secure permissions earlier than they would like, when details of the scheme are still to be finalised. Grid connection dates are often beyond the standard three-year lifetime of a planning permission. A lot can change up until energisation of a project: the specification of apparatus, grid capacity, land availability, political make-up etc. This leads to a need to amend permissions or obtain new ones, creating additional cost, uncertainty and confusion.

An alternative approach to seeking a premature planning permission is to secure a land allocation, accompanied by a permission in principle, through a Local Plan process.  

Why might a flexible approach to allocations and consents work better?
In considering specific sites both for allocation in a Local Plan and an accompanying award of a permission in principle, the evidence of site suitability would be proportionate and based on development parameters, rather than a fixed and final scheme design and layout. This way, the final specification, technology types and generating/storage scale could all be fixed and agreed at a subsequent consenting stage closer to the date of energisation.

The principal environmental effects of the proposed development could still be assessed under a parameters-based approach and, at the same time, local communities could have their say.

Such a flexible approach reflects how projects are financed and delivered, and where certainty on principle is often needed before detailed investment decisions are made.

It would not remove the need for planning permissions, but it would give greater weight to, and added benefit of, Local Plan allocations for energy infrastructure. It would incentivise the energy industry to engage meaningfully in the Local Plan process.

How long a planning timeframe is required?
Local Plans are intended to endure for a decade or more and be reviewed periodically. Allocations of sites for energy development would, therefore, align with the time periods for grid connections running into the 2030s. The allocation, and accompanying permission in principle, would then safeguard the site from alternative uses or incompatible uses on neighbouring land over the lifetime of the allocation.

The National Energy System Operator (NESO) and the distribution network operators (DNOs) would be asked to view allocations and an accompanying permission in principle as having the same status as a full, detailed planning permission when considering and awarding connection dates.

DNOs could themselves choose to promote sites through this Local Plan process. If an allocation is then forthcoming, the connection agreement would run with the site allocation and be available for a developer to secure.

Overall, national planning policy is clearly supportive of energy infrastructure. The planning system’s contribution to delivering energy infrastructure could, however, be much greater with the introduction of a bespoke energy-specific Local Plan allocation process. One that the energy industry would see value in engaging with.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘A national LAEP forward – hastening ‘place-based’ decarbonisation efforts’. Think globally: act locally – the most effective way to decarbonise a town or community is to design a locally-appropriate strategy. This can be particularly the case for domestic heating. Andrew Clark, Business Leader – Place at UK Energy Systems Catapult, explains how ‘place-based’ local area energy planning is already happening. 
• ‘How local energy benefits local people’. Local energy projects deliver enormous benefits compared to commercial projects, writes Angela Terry MEI, environmental scientist and CEO of climate action charity One Home.

According to analysis from Aurora Energy Research, Germany leads the ranking due to its market size and stronger potential returns compared with standalone renewables projects.

The UK’s position is supported by its significant installed capacity and a project pipeline backed by contracts for difference (CfD), which help offset ongoing grid connection delays. Bulgaria, which shares second place, benefits from strong subsidies, a robust development pipeline and favourable project economics.

The report also highlights Spain, Hungary and France as key markets to watch, citing regulatory changes and reforms.

Sameer Hussain, Senior Research Analyst, Aurora Energy Research, said: ‘As renewable penetration accelerates, grid congestion, curtailment and price volatility are becoming defining features of Europe’s power markets. Co-location is no longer a niche solution: it is increasingly critical to protecting project economics and sustaining investment momentum.’

Across Europe, co-located renewable capacity reached 6.3 GW in 2025, led by solar-plus-storage projects accounting for more than 60% of deployments. While maturity varies widely, Aurora expects a significant volume of new capacity to come online within five years. Spain, the UK and Germany lead in total capacity, while smaller markets such as Bulgaria and Romania stand out relative to their size, with co-located solar exceeding 40% of installed photovoltaic capacity.

Grid access remains a central challenge. Over 1,600 GW of renewable and storage capacity is awaiting grid connection across Europe, including around 550 GW in the UK alone. In markets such as the Netherlands, Greece and Hungary, co-location can improve grid access or reduce costs. High grid charges in regions such as Ireland and the Netherlands are also strengthening the case for combining storage with renewables, the study finds.

Market pressures are also intensifying. Negative price hours surged in 2025, with Spain, the Netherlands and Germany exceeding 500 hours. Capture price cannibalisation is expected to deepen, particularly for solar in Iberia, where discounts could approach 50% by 2030, and for onshore wind in Germany, where they may exceed 25%. Curtailment across key markets is forecast to increase from more than 10 TWh in 2024 to around 33 TWh by 2030.

At the same time, battery revenues are projected to fall by around 20% by 2040 as markets become more saturated. Co-located storage is seen as a way to mitigate these risks by shifting generation, reducing curtailment and improving capture prices.

Subsidies continue to dominate as the main route to market, although hybrid power purchase agreements (PPAs) – integrating renewables and energy storage systems under a single contract – are gaining traction. Two sided CfDs that allow co-location remain central in several countries, including the UK, France, Romania and Estonia. Additional targeted support is available in markets such as Bulgaria, Greece and Germany, alongside growing capital expenditure support for co located battery projects.

Rebecca McManus, Research Lead, Aurora Energy Research, said the hybrid PPA market, while still at an early stage, gathered pace in 2025 with more than 700 MW contracted. ‘This growth points to rising confidence among both corporate offtakers and generators in co-located and hybrid asset structures,’ she said.

Although still nascent, hybrid PPAs are beginning to emerge across Iberia, France, the UK and Bulgaria. Spain currently leads activity, but Aurora expects the greatest value uplift in France and Portugal, where hybrid and peak-shaving structures could increase contracted volumes and boost PPA capture values by up to 50% compared with pay-as-produced agreements.

‘We demonstrate that it is possible to charge just as fast as today, but with substantially less long-term degradation,’ said Meng Yuan, a researcher at the Department of Electrical Engineering, Chalmers.

Battery lifetime was measured in equivalent full cycles (EFCs) – the number of complete charge and discharge cycles a battery can undergo before its capacity falls to 80% of its original level, typically considered the end of life for EV use.

Using the new method, the battery was able to sustain a higher number of full cycles than under conventional charging. At the same time, charging time remained virtually unchanged: 24.12 minutes on average, compared to 24.15 minutes for the standard method.

Fast charging is known to accelerate battery degradation because high currents can trigger side reactions inside the cell. One of the most significant is lithium plating, where metallic lithium builds up on the electrode, reducing capacity and, in some cases, affecting safety.

Conventional charging strategies use fixed voltage and current limits, regardless of the battery’s age or condition.

In the study, researchers instead used reinforcement learning, a form of machine learning in which an algorithm learns by interacting with its environment. In this case, the system was trained to optimise charging in real time, balancing speed with long-term battery health.

‘This work shows that the true bottleneck of fast charging is not simply current limits, but the evolving electrochemical state inside the battery,’ commented Changfu Zou, Professor at the Department of Electrical Engineering. By integrating AI with physics-based understanding, we move closer to health-aware charging strategies that maximise both performance and lifetime.’

The resulting charging strategy dynamically adjusts to the battery’s condition, rather than applying a fixed profile.

According to the researchers, the approach could potentially be implemented through software updates to existing battery management systems, without requiring additional hardware.

The team said further work is needed to adapt the method to different battery chemistries and to validate the approach in real-world conditions.

Each of the wind turbine foundations weighs an average of 1,670 tonnes and is 90 metres in length. The XXL monopiles are the largest used by Ørsted on any of its European wind farms to date. Each will be topped by a 15 MW turbine supplied by Siemens Gamesa. The other 196 monopiles will be installed over the course of 2026 and into 2027.

In related news, Mubadala Investment, an Abu Dhabi sovereign investor, has announced a $325mn investment in Hornsea 3. It is investing alongside a consortium led by Apollo-managed funds, which includes USS and La Caisse. The investment follows Apollo Funds’ acquisition in late 2025 of a 50% stake in Hornsea 3. Ørsted retains the remaining 50% ownership and will continue to lead the development, construction and operation of the project.

Ørsted’s sale of a 50% stake in the Hornsea 3 project followed a period of continued cost pressures across the wind sector’s global supply chains and political headwinds in the US. The Danish wind developer had paused the planned development of the Hornsea 4 wind project in May 2025, stating that increased supply chain costs and higher interest rates, coupled with rising construction and operational risks, had made the project financially unviable in its current form. Then, in October 2025, Ørsted unveiled plans to slash its global workforce by a quarter – some 2,000 jobs – by the end of 2027, as it refocused attention on offshore wind projects in Europe as part of a wider restructuring plan.

Meanwhile, offshore wind is seen as a critical component of the UK government’s clean power plans, with a target of 43–50 GW of offshore wind in operation by 2030. A record 8.4 GW of offshore wind capacity was secured under the government’s latest contracts for difference (CfD) Allocation Round 7 (AR7) in January 2026, marking the largest single offshore wind procurement of its kind in Europe to date. Of the total capacity awarded under AR7, 8.2 GW went to fixed-bottom offshore wind projects, with a further 192.5 MW allocated to floating offshore wind.
 

‘Heavy reliance on geographically concentrated fossil fuel supply and critical transit routes exposes economies to large, sudden and recurrent disruptions, which transmit rapidly through prices, trade and inflation. The scale of the current shock, affecting around 20mn b/d of oil and 20% of LNG, may increase fossil energy costs by around 20% this year, if high prices are sustained.’

They continue: ‘Reliance on long and exposed supply lines [such as in fossil fuels] can constrain both industrial activity and the functioning of critical infrastructure. By contrast, clean energy systems shift towards distributed domestic resources, electrification and long-lived capital assets, significantly reducing exposure to price shocks and supply interruptions.’

The ETC argues that emergency responses must protect vulnerable households and essential services, while avoiding long-term fossil fuel lock-in. Expanding fossil fuel infrastructure may appear to strengthen security, but risks reinforcing exposure to volatile global fuel markets.

The report sets out a more durable crisis response: accelerate renewables, electrification, cleaner fuels and fertilisers, and energy efficiency.

The authors say: ‘As in the aftermath of Russia’s invasion of Ukraine in 2022, our view is that the right response is to accelerate the clean energy transition, not to increase fossil fuel dependence. High and volatile fossil fuel prices make zero-carbon alternatives competitive. But seizing this opportunity requires clear strategic direction, strong policy action and careful management of near-term trade-offs.’
 

Its Energy transition outlook: hydrogen to 2060 report has revised down its mid-century outlook by 25% since its last (2022) report, but even so predicts production to grow 100 times. A third of that growth comes from China.

Clean hydrogen uptake is expected to be strongest in emerging demand sectors by 2060, led by steelmaking (18% of total clean hydrogen use), aviation (18%) and maritime (15%), followed by fertiliser and methanol.

DNV said there were still some technical hurdles to overcome for hydrogen to succeed. ‘Going forward, it is about fine-tuning the regulations, implementing these in legislation, and verifying safety concepts, documenting technical performance, and certifying emission reductions. That is how renewable and low-carbon hydrogen can make a difference for hard-to-electrify sectors,’ said Magnus Killingland, Global Segment Lead Hydrogen.

Elsewhere, a clean hydrogen trade body, the European Resilience Alliance for Clean Hydrogen & Derivatives (ERA), has been established by a number European industrial companies and in cooperation with trade association Hydrogen Europe.

At the launch, MEP Andrea Wechsler said: ‘Europe’s energy transition is not just about decarbonisation – it is about building a resilient sovereign energy system that delivers for both citizens and industry. Resilience must become one of the guiding principles of our energy policy, grounded in diversification, system integration and credible market frameworks that turn ambition into investment.’

The group aims to provide a unified voice to policymakers, create the conditions for a cost-competitive clean energy value chain and coordinate from energy production and infrastructure to industrial demand and finance to identify and resolve practical bottlenecks. Reducing the cost of electricity, which it says accounts for 70% of the cost of hydrogen, is said to be a key priority.

ERA’s founding members include Enagás, Fluxys, Fortum, Gasgrid Finland, Moeve, Nordion Energi, OGE, RWE Generation, SEFE, Stegra and Thyssenkrupp.

To coincide with its launch, ERA has released a white paper that highlights that despite a large pipeline of projects across the clean hydrogen value chain, fewer than 7% have reached a final investment decision (FID). The paper identifies the reasons why Europe’s clean hydrogen deployment is falling behind ambition, namely the fragmented implementation of EU regulation, complex renewable fuels of non-biological origin (RFNBO) rules, high electricity costs, insufficient demand certainty, and uncertainty around infrastructure development.
 

This is not a failure of ambition. Most energy consultancies recognise the opportunity. The problem is structural: advisory businesses are built to think, not to build. Their operating models, their risk appetites, their commercial frameworks and their talent pipelines are all optimised for analysis and recommendation – not for procurement, site delivery and contract management. The result is a revenue ceiling that has nothing to do with pipeline quality or sales capability.

The ceiling exists because the consultancy cannot convert its own recommendations into installations. The pipeline is full. The capability to deliver against it is not. For firms with genuine growth ambitions – particularly those backed by investors expecting compound returns – this ceiling is not an inconvenience. It is the single largest constraint on enterprise value.

The three delivery traps
When energy consultancies attempt to bridge the gap between advisory and delivery, they typically fall into one of three structural traps. Each appears rational in isolation. Each creates compounding problems over time.

The contractor trap
First is the contractor trap. The most common first move is to hire a delivery-minded individual – a project manager, a site supervisor, an ex-contractor – and bolt them onto the existing consultancy team.

The logic is straightforward: we need someone who knows how to build things. The problem is cultural. Contractor organisations operate on speed, pragmatism and margin protection. Consultancy organisations operate on rigour, client relationships and intellectual credibility. These are not complementary cultures – they are opposing ones.

The hired individual either adapts to the consultancy culture (and loses the delivery edge that made them valuable) or retains their contractor instincts (and creates friction with the advisory team, the client relationship managers and the compliance framework). Neither outcome produces a functioning delivery capability.

The procurement trap
The second trap is treating sub-contractor selection as a procurement exercise. The consultancy issues a scope of works, collects three quotes and awards to the lowest price. This is how organisations buy stationery, IT equipment and office furniture.

It is not how organisations should procure construction and installation services. The cheapest quote in energy installation almost always carries the most hidden risk: thinner margins mean less contingency, fewer site supervisors, cheaper materials and a greater likelihood of variation claims.

The consultancy, lacking delivery experience, cannot distinguish between a competitive price and a price that will unravel on site. More critically, the consultancy’s client is watching. If the sub-contractor underperforms – delays, cost overruns, poor workmanship, safety incidents – the client does not blame the sub-contractor. They blame the consultancy that recommended them. The consultancy’s reputation, built over years of careful advisory work, is now in the hands of the cheapest bidder.

The liability trap
The third and most dangerous trap is accidental risk absorption. In the transition from advisory to delivery, consultancies frequently sign contracts, accept obligations or make commitments that transfer design, delivery or performance risk from the sub-contractor onto themselves – often without realising they have done so.

A consultancy that specifies equipment in its recommendation and then manages the installation has, in effect, accepted design liability.

A consultancy that signs a fixed-price contract with a client and then sub-contracts on a measured-term basis has absorbed the cost overrun risk.

A consultancy that provides performance guarantees based on its own energy modelling has warranted outcomes it cannot control.

These are not theoretical risks. They are the precise mechanisms by which advisory firms with excellent reputations find themselves exposed to six-figure liabilities on projects they believed were low-risk.

The structural solution
The consultancies that successfully navigate the transition from advisory to delivery share one characteristic: they do not attempt to become contractors. Instead, they build – or partner with – a delivery assurance function that sits between the consultancy and the sub-contractor. This is not a project management overlay. The delivery assurance layer is a structural layer that operates as an independent function with clear accountability boundaries and performs four distinct functions.

• Procurement governance: managing sub-contractor selection on capability, track record and risk profile rather than lowest price. This ensures the consultancy’s client is protected by the quality of the appointment, not exposed by it.
• Contract architecture: structuring agreements so that design risk sits with the designer, delivery risk sits with the installer and performance risk is allocated to the party best equipped to manage it. Therefore, the consultancy retains none of the risk that belongs elsewhere.
• Site oversight and variation management: monitoring delivery against programme, identifying variations before they become disputes and protecting the consultancy’s margin from the scope creep that characterises poorly managed installations.
• Margin protection: ensuring that the revenue the consultancy earns from delivery is genuine profit, not a contingency reserve that gets consumed by the first cost overrun.

Why the structure works
The delivery assurance layer succeeds because it respects the boundaries between advisory and delivery. The consultancy retains its client relationship, its intellectual credibility and its advisory revenue. The subcontractor carries the delivery risk, the design liability and the site accountability.

The assurance layer manages the interface between them – ensuring that procurement is rigorous, contracts are correctly structured and delivery is monitored. No party absorbs risk that belongs elsewhere. No party is asked to operate outside its core competence. The consultancy does not become a contractor. The contractor does not become a consultant. The client receives an integrated service from a team that understands its respective roles.

This is not a theoretical model. It is the operating structure used by the most successful advisory-to-delivery transitions in the UK energy services sector. The consultancies that get this right do not just add a revenue stream – they fundamentally change their enterprise value by demonstrating to investors that their pipeline converts into delivery, not just recommendations.

The measurement question
The consultancy ceiling is not difficult to quantify. It requires answering two questions.

First, of all the recommendations made to clients in the last 24 months – such as ESOS actions, carbon reduction measures, energy efficiency upgrades, renewable installations – how many became delivered projects? Not projects the client delivered with someone else. Projects the consultancy delivered or facilitated.

Second, for every recommendation that did not convert into a delivered project, what was the potential delivery revenue? Not the advisory fee already earned. The installation value, the project management fee, the ongoing maintenance contract, the performance monitoring revenue that follows a successful delivery.

The gap between those two numbers is the consultancy ceiling. It is the revenue the business could have earned – should have earned – but structurally could not capture. For a consultancy processing several hundred ESOS assessments per year, each generating an average recommendation value of £150,000 to £500,000 in installation works, the ceiling is not a rounding error. It is a multiple of current advisory revenue.

The question is not whether the ceiling exists. It is whether the business intends to do something about it – and whether it intends to do so before its competitors work it out for themselves.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Connecting the dots for SMEs’ net zero journey’. Where do I start? This is the question most small and medium-sized enterprises (SMEs) ask themselves as they try to respond to increasingly ambitious sustainability and net zero goals. Discover the answer.
• ‘Beyond carbon measurement: why businesses must apply the rigour of financial accounting to sustainability’. Even the best-intentioned company may unwittingly undermine its own efforts and plans to reach net zero by failing to properly understand and account for its carbon emissions, writes Matthew Paver, Chief Operating Officer of Carbon Responsible. He advocates a more analytical approach.
   

We are moving towards a decentralised, electrified system with millions of generation points, new demand from data centres, transport and heat, as well as increasing complexity. It is no surprise that the system is straining at the seams.

There is a growing narrative that the solution lies in shifting demand. The National Energy System Operator’s (NESO) commitment to incentivise consumers and businesses to use electricity at off-peak times has a role to play, but it does not address the underlying challenge.

The National Grid itself projects that upgrades to infrastructure will cost £35bn over the next five years. At the same time, the queue to connect new projects to the grid has grown by 460% in the last six months, and critical components such as transformers are in short supply.

The reality is that the grid alone cannot carry the weight of net zero, no matter how much we shift demand, at least not within the timeframes we are working to. If we continue to rely on it as the primary route to decarbonisation, we risk snail-like progress, increasing costs and creating bottlenecks that delay projects across the economy.

This is why we need to think beyond the grid.

Relieving pressure on the system
Grid-edge technologies offer a practical and immediate way to relieve pressure on the system. These are solutions that generate and store energy at the point of use, rather than relying on central infrastructure. Solar thermal is a great example. It allows businesses to produce renewable heat directly on-site, using the sun, without drawing additional electricity from the grid.

This matters because heat is a major part of this challenge. Around half of global energy demand is for heat, yet much of the conversation remains focused on electricity.

When organisations electrify heat through technologies such as heat pumps, they increase demand on an already constrained grid. That is not a reason to avoid electrification, but it does mean it shouldn't be the automatic solution.

By integrating solar thermal alongside heat pumps, we can reduce that demand significantly.

Solar provides a base supply of zero carbon heat, actively reducing the total load the heat pump has to manage. The result is a more efficient system with lower operating costs and a smaller carbon footprint. Crucially, it also reduces the amount of electricity required, freeing up capacity on the grid for applications where it can be used more efficiently.

Every kilowatt-hour generated and used on-site is a kilowatt-hour that does not need to be transmitted, distributed or balanced by the grid. At scale, that has a meaningful impact. It reduces the need for expensive infrastructure upgrades, lowers system-wide costs and accelerates the pace at which we can decarbonise.

The question should not be how we electrify everything, but how we deliver the most efficient, resilient and cost-effective energy system overall.

There is also a broader economic argument. The current approach relies heavily on large-scale infrastructure investment, much of which will ultimately be borne by taxpayers and consumers.

For example, the European Commission estimates €584bn is needed to upgrade electricity grids to reach 2030 net zero goals – that’s before you even consider the cost of reaching 2050 targets.

Distributed energy offers a complementary pathway. By deploying smaller, distributed systems, we can deliver low to zero carbon energy quicker and often more cost-effectively.

These systems can be installed today, without waiting for grid connections or major upgrades. They provide an immediate financial hedge to businesses, while reducing emissions and contributing to national decarbonisation goals.

Importantly, this is not about replacing the grid. We will always need a strong and resilient infrastructure to enable the energy transition. But we need a more balanced approach, one that recognises the role of both centralised and distributed solutions.

The question should not be how we electrify everything, but how we deliver the most efficient, resilient and cost-effective energy system overall. This includes combining technologies in a way that reduces demand on the grid from the outset, rather than only trying to shift demand by changing people’s habitual electricity use.

The conversation around solar overwhelming the grid highlights a deeper issue. It is not a failure of renewable energy, but is a signal that our infrastructure and our thinking need to evolve.

The path to net zero is not about choosing between the grid and decentralised solutions. It is about making them work together.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Solar heat has to play a bigger part in decarbonising Europe’ .Solar thermal technology offers considerable benefits to homes, industry and district heating schemes, and deserves more support, writes Valérie Séjourné, Managing Director of the Brussels-based trade association Solar Heat Europe.
• ‘Network reinforcement isn’t enough – we need smarter maintenance decisions’. The real opportunity in modernising the electricity grid lies in intelligence – understanding how high-voltage (HV) assets like transformers, switchgears and cables are behaving, and using that data to make better informed decisions about when and where to act, writes Jonathan Lewin, Head of HV Monitoring at power engineering company EA Technology.

Initially, I was set on a career in Formula 1 or aviation, so I applied to and was accepted to study aeronautical engineering at Imperial College London. During my third-year summer internship at National Grid, I reignited my interest in the energy industry. That experience led me to apply for a master’s in petroleum engineering at Imperial. Despite having other graduate offers, it felt like the most natural fit for me, so I committed to it.

Before starting the master’s, I was almost completely unaware of what the upstream energy industry actually did. But as I learned more, I was drawn in by the technical challenges and the sheer scale of the projects. I’m still working in the upstream energy industry today.

Q: How did you first hear about the Energy Institute and what motivated you to join?
A: The EI came onto my radar when I started looking into engineering chartership after several years in industry. I wanted to pursue chartership through a broader, energy-focused organisation, one that wasn’t solely centred on oil and gas.

That was partly because the potential to move to different parts of the industry was definitely in the back of my mind. But a bigger concern was that if I were chartered with a dedicated oil and gas body, I would not get exposure to challenges in adjacent areas, such as energy transmission and generation, for example. I’d still have access to the detailed technical knowledge needed for my role, but felt like I would be more rounded having a chartered qualification from the EI.

I applied relatively early, with around four years’ experience. I wasn’t successful. I took the feedback seriously and, with support from other EI members, used it to shape my development plan. It helped me identify where I needed to strengthen my experience and capability, and it had a real positive impact on my day-to-day professional growth. About 18 months later, I applied again and was successful in achieving CEng and becoming chartered as a petroleum engineer through the EI.

Q: Tell us about your current job and industry, and how your work is contributing towards a just transition to net zero?
A: I currently work at Origin Energy in Brisbane, within the Integrated Gas division. My role is Reservoir Optimisation Team Lead (Asset East). I lead a team of surface and petroleum engineers focused on optimising and understanding the performance of more than 1,300 coal seam gas (CSG) wells in Australia Pacific LNG’s (APLNG) Queensland fields. Together, these wells produce close to 800mn cf³/d and supply gas to local customers as well as export markets in Asia. [Editor’s note: APLNG is a joint venture between Origin Energy, ConocoPhillips and Sinopec.]

After more than a decade of work experience in the North Sea, one of the biggest adjustments for me has been getting to grips with the scale of the project and the very different set of technical challenges compared with my previous roles.

The gas these fields produce is important for both the energy transition and, more recently, energy security. My role is to help ensure we continue to deliver that gas safely and as efficiently as possible, while continuously improving performance and reliability.

With the onshore fields I work on now, we have thousands of wells to manage that might together produce the same amount as a handful wells offshore. With offshore installations, you are hyper-focused on selected wells, but onshore it's about trying to optimise the best for the majority. With either, health, safety and the environment is still paramount, but there are different risks. For example, driving is one of the key risk areas for onshore assets.

Moving all the family to the other side of the world was a very big decision. As a family we were keen for an adventure and always wanted to live in other countries. The work environment and the type of technical challenge was completely different, and that was the exciting part. Right now I am really enjoying the work and the family is taking to life in Australia, so we are very happy with the decision. In terms of career development, it is building and broadening my experience in areas where I had not worked before.

Q: How has being an MEI benefitted you in your career?
A: Once I achieved MEI and CEng status, I joined the EI’s Aberdeen, Highlands & Islands Young Professionals Network (YPN). We had a fantastic group and organised a range of events focused on energy and developing early-career talent. I found the experience so rewarding that I looked for other ways to contribute.

One of the standout benefits has been volunteering as an assessor for MEI and chartership. I’ve been fortunate to speak with professionals from around the world and across a wide range of industries. While the process is necessarily formal, I’ve learned a great deal from those conversations and it has helped me think more clearly about what I want from my own career. Getting that outside perspective on how others have grown and developed professionally has been invaluable.

Q: Tell us more about your CEng and how being a Chartered Petroleum Engineer has benefitted you in your career and what advice you’d give to an aspiring petroleum engineer?
A: You don’t stop learning once you leave university; it’s really just the start of your professional journey and development continues throughout your career.

Professional recognition is an important part of that journey for any engineer. Chartership demonstrates you’ve met a rigorous professional standard and it is widely recognised internationally. In some parts of the world, being chartered is essential – without it, you may not be able to sign off on your own technical work. Historically, chartership hasn’t been as strongly embedded in petroleum engineering as it is in some other disciplines, but that is changing. For me, it signals a commitment to high standards, professionalism and continual improvement – both to yourself and to the wider engineering community.

Technology moves at a rapid pace, whether it's new equipment to optimise and make things safer or the adoption of AI to drive efficiencies and bring more value. Either way, if you stand still and cannot adapt, then you will not last long in this industry.

My main advice to aspiring petroleum engineers is to stay curious, seek out varied experiences (technical and commercial) and treat chartership as a development framework – not just an end goal.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

If you’re keen to follow in Zubin’s footsteps, click to find more about how to become a Member of the Energy Institute (MEI) and the route to CEng status. 
 

Transmission lines are typically operated using fixed ratings based on conservative weather assumptions. DLR uses sensors to monitor line conditions and weather in real time, allowing operators to adjust capacity limits dynamically.

According to National Grid, this could increase capacity by around 8% on average, reducing the need for constraint payments, where generators are paid to stop generating to avoid overloading the electricity network.

The installations will take place in the North East (345 km of overhead lines), as well as the Humber region and East Anglia (240 km combined). Further deployments are planned over the five-year period.

In total, the rollout will bring the technology to 39 circuits covering over 900 km of National Grid’s transmission network, mainly along north-to-south routes.

The project will be delivered in partnership with grid tech companies LineVision, Ampacimon and Heimdall Power. Most installations are expected to be completed by 2028.

National Grid said it plans to use drones to mount sensors on live power lines to avoid the need for planned outages on key transmission routes.  

Rystad Energy’s analysis shows turbine selling prices rising by between 40% and 45% since 2020, outpacing manufacturing cost increases of 20% to 25% over the same period.

The report identifies the nacelle – which houses the generator, gearbox and power electronics that convert wind into electricity – as sitting at the centre of current supply constraints. Similar pressures are emerging in blade manufacturing, driven by increasing turbine sizes, longer production cycles and the logistical demands of transporting and installing next-generation components.  

The report warns that critical components are becoming increasingly concentrated. ‘If Europe doesn’t meaningfully expand manufacturing capacity or rethink how supply constraints are addressed in its auction frameworks, it won't deliver its post-2030 targets at the pace or cost the energy transition requires,’ noted Sander Baksjoberget, Senior Analyst, Offshore Wind Research.

Turbine technology has also shifted rapidly since 2020. Earlier years were dominated by smaller 9–10 MW turbines, while more recent deliveries are shifting towards the larger 14–15 MW class. Siemens Gamesa was the first to move into bigger turbines, signing contracts for its 14-MW model ahead of Vestas before moving into the 15-MW class, while Vestas’ V236-15-MW grew in popularity from 2024 onwards. Siemens Gamesa remains the largest supplier by delivered volume in recent years.

Rystad notes that the rise in turbine size is important context for understanding price increases: the turbines being built and installed today are significantly larger and more complex than those from five years ago, and that complexity is reflected in what original equipment manufacturers (OEMs) can charge.

The 40–45% rise in turbine selling prices since 2020 is not solely driven by input costs, the report says. Many contracts signed in 2020–2021 were based on stable cost assumptions, leaving manufacturers to absorb inflation during 2021–2023. As those contracts expired from 2023 onwards, pricing has reset higher, shifting more cost pressure on to developers.

The report adds that while developers continue to anchor project economics, turbine manufacturers are now in a stronger position to pass through cost increases via new contracts, although profitability across offshore divisions remains under pressure from scaling next-generation turbine production.

Rystad Energy also models a scenario in which a 30% rise in selected input costs would increase total manufacturing costs by around 17%, reflecting how different components are exposed to varying cost drivers.

UK needs 5 GW of offshore wind every year to stay on track for government goals
The tightening European supply chain comes as a new Offshore Energies UK (OEUK) report estimates that the UK needs to accelerate offshore wind deployment to deliver at least 5 GW each year to stay on track with its targets.

The report warns that while offshore wind remains one of the UK’s biggest success stories, progress is starting to slow at a critical moment.

OEUK says the government should aim to award up to 7 GW of offshore wind in the next renewables auction (AR8). This would allow the UK to meet the minimum need of 5 GW a year while making sure projects remain affordable compared with electricity prices and other renewable technologies.

However, new projects will not deliver power unless the electricity grid keeps pace. OEUK says all planned grid upgrades must be completed by 2028 to unlock offshore wind projects already in the pipeline.

At the current rate of progress, the UK would reach only just over 30 GW of offshore wind by 2030, well short of the planned 43 GW. The report calls for clearer deadlines, stronger accountability for grid companies and compensation where projects are delayed. If progress does not improve, it says the government should be ready to step in and fast track delivery.

Finally, OEUK says offshore wind needs steady, predictable growth, rather than stop start investment. It is calling for annual auctions delivering at least 5 GW a year from 2026 to 2030, so that supply chains can plan ahead, costs can be kept down and skilled jobs are retained in the UK. 
 

Fossil fuels accounted for slightly less than 60% of France’s final energy consumption in 2023, down from 65% in 2011, according to the roadmap. Although its extensive nuclear power plant fleet generates most of the country’s electricity, in other sectors, the country remains highly dependent on imported gas and oil, with over 95% of its fossil fuels sourced from abroad, leaving the economy exposed to geopolitical and price volatility, the document says. The roadmap targets a 40% reduction in fossil fuel use by 2030 and 30% by 2035, before reaching net zero by 2050.

Oil is France’s largest fossil fuel dependency, accounting for 38% of final energy consumption in 2024, with transport responsible for around two-thirds of use. Fossil gas accounts for 19%, mainly consumed in industry and buildings; while coal represents less than 1% of final consumption, and is mainly used for electricity generation and industry (85% of coal consumption).

Under the roadmap, France’s last two coal-fired power stations will close by 2027, enabling a full coal phaseout by 2030.

The more challenging transition concerns oil and gas consumption, particularly in transport, heating and industry.

To reduce oil demand, the government is relying heavily on transport electrification. It is aiming for two out of every three new cars sold in France to be electric by 2030, supported by expanded charging infrastructure and increased electrification of buses and heavy goods vehicles.

The roadmap also includes industrial targets to strengthen domestic electric vehicle (EV) manufacturing capacity, with French factories expected to produce 400,000 EVs annually by 2027 and one million by 2030. The objective is to avoid replacing dependence on imported oil with dependence on imported vehicles and technologies.

Public transport use is also expected to rise sharply, with a target for a 25% increase by 2030.

In buildings, the roadmap focuses on replacing fossil gas and oil heating systems with low-carbon alternatives. Installation of gas boilers in new residential and commercial buildings will be banned from the end of 2026, while government incentives will support deployment of heat pumps and energy efficiency upgrades. The aim is to install one million heat pumps annually by 2030. According to the roadmap, replacing gas demand with domestically produced energy could cut imports by around 20% (some 85 TWh) by 2030. The government also wants to reduce oil-fired boilers in residential buildings by 60% and in non-residential buildings by 85% by 2030. The goal is to phase out fossil oil for heating by 2035.

Alongside demand reduction measures, the strategy outlines a major expansion of low-carbon electricity generation and supporting infrastructure.

France plans to continue relying on nuclear energy as the backbone of its power system. That includes the construction of six new reactors based on a revised design of its EPR design, and lifetime extensions for existing plants. Nuclear currently supplies roughly two-thirds of French electricity generation.

Renewables deployment will also accelerate. Targets include reaching 15 GW of installed offshore wind capacity by 2035 (a 15-fold increase compared to 2017), adding 1.3 GW of onshore wind annually and tripling installed solar photovoltaic capacity by 2035.

The roadmap also calls for an additional 2.8 GW of hydropower capacity, including pumped-storage facilities, and deployment of up to 8 GW of electrolysers by 2035 to support domestic hydrogen production.

It is also planned to increase biomethane production sixfold and double biofuel consumption by 2035.

The government acknowledged that grid infrastructure will require substantial investment to accommodate rising electricity demand from transport, heating, industry and data centres while integrating larger volumes of variable renewable generation.

Environmental groups broadly welcomed the publication of explicit fossil fuel phase out dates, although some argued the roadmap lacked sufficient new policy measures. Speaking to the Agence France-Presse (AFP) news agency, Anne Bringault, Programmes Director at Climate Action Network France, said the government deserved credit for setting clear timelines after ‘two years of backsliding’ in ecological transition policies.

The roadmap was unveiled at the ‘First conference on transitioning away from fossil fuels’ in Santa Marta, Colombia, in late April. More than 50 nations had gathered for what was billed as the first international talks focused specifically on moving away from fossil fuels after the COP30 climate negotiations in Brazil.

France’s roadmap for transitioning away from fossil fuels can be viewed here.

Getting connected: two new wind farms commissioned offshore France
In other news, Ocean Winds (a 50:50 joint venture of Engie and EDP Renewables) has delivered two new wind projects offshore France.

The 500 MW Îles d’Yeu and Noirmoutier (EMYN) wind farm offshore the coast of Vendée, west France, is now fully operational following installation of the last of the project’s 61 turbines in late April.

At the same time, the Éoliennes Flottantes du Golfe du Lion (EFGL) floating wind farm (pictured), located 16 km off the coast of Port-la-Nouvelle in southern France, has produced first power to the French grid. Developed in partnership with Banque des Territoires, the project comprises three 10 MW turbines. Full capacity is expected in June. EFGL is the world’s first floating offshore wind farm to integrate artificial marine habitats, designed to promote biodiversity, according to Ocean Winds.

Meanwhile, Ocean Winds’ 500 MW Dieppe Le Tréport (EMDT) fixed-bottom offshore wind farm is currently under construction off the coast of Normandy, northern France. Due onstream by year-end, half of the jacket foundations and the offshore substation have already been installed at sea. The 250 MW Éoliennes Flottantes d’Occitanie (EFLO) floating offshore wind project in the Mediterranean Sea is also currently under development.
 

Two of the participants on the seven-week ‘military to wind’ pilot programme – which is supported by industry training bodies – have already been offered jobs, according to the company.

The pilot programme aligns with broader efforts from government and industry bodies to support a workforce transition. It was jointly funded by the Ministry of Defence and the Engineering Construction Industry Training Board (ECITB), which played a key role in shaping the course standards.

Participants are selected from service leavers with an existing Level 3 engineering background – mechanical, electrical or instrumentation.

‘The qualities service leavers bring – discipline, attention to detail, safety awareness, technical competence and the ability to perform in demanding environments – are exactly what the wind industry needs’, explained Andy Elrod, Director of Training, Aurora Energy Services. ‘Applicants completing the course will be site-ready so they can go out and be gainfully employed in roles including pre-assembly construction, and operations and maintenance.’

Participants undergo Global Wind Organisation (GWO) training, advanced rescue and safety certifications, and ECITB-accredited competencies, alongside additional modules covering wind turbine safety rules and technical theory.

The programme includes a defined employment pathway. Each successful participant is guaranteed a job interview with Aurora and other companies from a growing network of partners.

Declan Paterson, 33, served 13 years with the Royal Electrical and Mechanical Engineers Corp (REME) as a recovery mechanic. He recently started as a lifting technician at Aurora after completing the course. He said: ‘My background is recovery and cranes and that was always something I was looking for… The quality of [the course’s] training shone through... and the fact that you gain five or six qualifications was an important factor.’

Another course participant, Jason McLaughin, added: ‘As someone transitioning from a 20+ year career in the military, one of the biggest challenges I found entering the wind industry was simply getting in front of employers. [This] programme has completely changed that. It’s not just training – it provides direct access to employers and guaranteed interview opportunities, which is something that’s very difficult to achieve as a new entrant.’

Aurora is now exploring partnerships and funding with regional and industry bodies to support future cohorts. The vision is that the template could be rolled out by ECITB as a nationally recognised pathway into the wind sector for service leavers.

‘A key take-home message is that “bad credits” do not necessarily mean “bad projects”. Many projects have successfully slowed deforestation, even if more credits were sold than are justified,’ said Professor Julia Jones at Bangor University, a co-author of the study. It found that nine REDD+ projects in particular accounted for much of the over-crediting.

She added: ‘The over-crediting scandal in the voluntary carbon market has left many with the unhelpful impression that anything to do with funding tropical forest conservation through carbon finance is a bit dodgy. It is important to set the record straight, as forest conservation is so vital to tackling climate change.’

Dr Tom Swinfield, a researcher in the University of Cambridge’s Department of Zoology and first author of the study, said: ‘We found that many REDD+ projects were at far lower risk of deforestation than anticipated by project-led evaluations. Credits were issued based on predictions that these forests were at imminent risk of deforestation, but in reality this risk was often lower.’

According to the University of Cambridge, carbon credits are generated by comparing the anticipated deforestation in a region before protection, with the projected deforestation once areas of forest are protected through a REDD+ project. This depends on accurately selecting other, unprotected areas of forest against which robust comparisons can be made. The problem many independent evaluators have discovered is that the comparison areas chosen by crediting agencies were often more exposed to deforestation than project areas would have been, so too many credits have been issued.

The researchers say to avoid over-crediting, future REDD+ projects must draw on more representative reference forests to better assess the true contribution of projects to forest protection.

Elsewhere, Octopus Energy Generation has announced that it will invest $500mn in forestry projects in the US with Living Carbon, with the aim of removing up to 50mn tonnes of atmospheric carbon.

Maddie Hall, Founder and CEO at Living Carbon, said: ‘Our partnership with Octopus takes us from early-stage implementation to delivering long-term carbon removal at scale with institutional capital. This is a sign that this market is maturing into real project finance as corporate commitments to net zero increase.’
 

According to IEA estimates, energy accounts for 41% of global emissions of methane, amounting to just under 150mn tonnes, followed by agriculture (40%), waste (17%) and ‘other’ (2%).

Upstream activities currently account for 80% of oil and gas methane emissions, the report finds. Canada and the European Union recently introduced robust upstream regulations, while Brazil, Ghana and Kazakhstan are in the process of doing so, according to the IEA.

IEA analysis of energy sector methane emissions by type 

Source: IEA

The International Methane Emissions Observatory (IMEO) has published a list of the top 50 methane emitters in the world, as well as new data about international methane emissions responses, as it expands coverage of its satellite detection programme to include coal mines and landfill sites.

‘By making the biggest sources public, IMEO is scaling methane transparency to accelerate action. When a source is clearly and publicly identified, it becomes easier to act on and harder to ignore,’ said the United Nations Environment Programme (UNEP), which runs the programme.

It added that methane is 80 times more powerful than CO2 but has a much shorter lifespan, breaking down in the atmosphere after about a decade. That means cutting methane emissions acts like a climate emergency brake.

Of the top 50 sources, 12 are waste sites and 10 are metallurgical coal mines, while a similar number are mines for thermal coal.

In other news, a new report from Ember finds that in 2023, coal mines emitted 34.7mn tonnes of methane, comparable to oil and gas emissions, but there is a problem. The authors say that only a handful of countries account for the majority of coal mine methane (CMM) emissions, yet due to infrequent reporting, 89% of emissions were not reported to the United Nations Framework Convention on Climate Change (UNFCCC) in 2023.

In 2022, IMEO launched the Methane Alert and Response System (MARS) to warn governments of very large methane emissions based on data collected from more than 30 satellite instruments.

In May, IMEO said: ‘Prompt reaction to MARS notifications has led to the successful mitigation of methane leaks in several countries. However, the global response rate to MARS notifications remains relatively low.’

MARS country response rates, by country, for those with and without a dedicated point of contact for MARS notifications (1 January–31 December 2025)
Note: The response rate is calculated by dividing the number of emission sources for which IMEO has received a response by the number of sources for which MARS has issued an alert, over a rolling 12-month basis.
Source: IMEO

Another new report tracks how well countries are responding to MARS alerts. IMEO said that responding to a MARS alert requires countries and companies to investigate the root cause of the emissions and share information about the event, including whether operators have taken mitigation measures and, if so, what kind. Higher MARS response rates are associated with more mitigation action, but low response rates do not necessarily signal indifference.

Still, UNEP said: ‘Many countries’ response rates indicate room for progress. In some countries, low response rates point to technical barriers. Elsewhere, they signal a need to prioritise methane action.’

IMEO and the IEA have also launched guidance that offers a five-step process for responding to MARS notifications, to help governments make best use of the information.

The IEA’s Global Methane Tracker 2026 can be viewed at https://www.iea.org/reports/global-methane-tracker-2026, while Ember’s Global Coal Mine Methane Review 2026 report can be found at https://ember-energy.org/latest-insights/global-coal-mine-methane-review-2026/
 

The test programme covered 14 different scenarios over a total of 138 hours. It was independently observed and verified by testing and certification body TÜV Rheinland, with results meeting a range of international technical standards, according to the company.

The testing focused on grid-forming system behaviour under conditions associated with rising shares of renewable generation, which are increasing challenges related to system stability, fault response and recovery following disturbances.

The trials were conducted on a 30 MW grid simulation platform, designed to replicate full scale and extreme grid conditions. The facility includes equipment capable of varying short circuit capacity and carrying out real arc fault tests, enabling validation under physical conditions rather than relying solely on digital simulation.

Test scenarios included short circuit faults, frequency disturbances and full blackouts. During short circuit testing, Sungrow said its grid forming system remained connected and continued supplying fault current, in contrast to typical grid-following behaviour. The company reported response times of around 10 milliseconds and continuous fault current contribution during the tests.

Frequency performance was also assessed, with tests designed to compare grid forming and grid following behaviour under sudden disturbances. Results showed that the system maintained operation and stabilised frequency within milliseconds, including under weak grid conditions.

Black start capability was tested by disconnecting all external power from the site to simulate a full blackout. According to Sungrow, its grid forming power conversion system established system voltage within 19 seconds and restored the facility without external electricity supply.

Additional tests included transitions between grid-connected and off-grid modes, load switching and oscillation damping.

The test base features a 30 MW grid simulation platform

Photo: Sungrow

Under the first partnership, Overview Energy plans to collect solar power using satellites positioned in orbit around 22,000 miles above the Earth, where sunlight is continuous. The satellites, positioned in a geosynchronous orbit so that they rotate with the Earth and thus appear fixed in the sky, would transmit solar radiation as low-intensity near-infrared light to existing solar farms on the ground. This arrangement would enable them to generate electricity continuously, day and night.

Meta said the approach could increase the output of existing solar infrastructure without requiring additional land or significant grid upgrades.

Overview Energy is targeting an orbital demonstration in 2028. If successful, Meta commercial delivery to the US grid could begin as early as 2030.

Back on Earth, Meta has also partnered with Noon Energy to explore longer-duration energy storage, up to 100 hours, far longer than the duration of lithium-ion batteries. In this case, it consists of solid oxide fuel cells. When electricity is supplied, they store energy in a carbon-based storage medium and release oxygen to the atmosphere. When electricity is required, the process reverses.

Noon Energy’s 25 MW/2.5 GWh-capacity pilot project is expected to be completed in 2028. Meta has reserved up to 1 GW/100 GWh of capacity.

Ceres launches onsite solid oxide platform 

Meanwhile, UK-based Ceres has launched Ceres Endura, a solid oxide fuel cell stack platform designed to provide onsite power for data centres and other energy intensive facilities.

The company said the platform is designed for both power generation and hydrogen production from a single manufacturing base, allowing deployment across multiple applications.

Systems can initially operate on natural gas, with the potential to transition to hydrogen and other lower-carbon fuels. Ceres said installations can be deployed within months, offering an alternative to longer grid connection timelines.

The platform supports high-voltage direct current architectures of 800 Volts and above, aligning with data centre design standards.

Ceres added that the system operates at lower temperatures (450–630°C) than conventional solid oxide technologies, enabling the use of more widely available and recyclable materials while reducing cost by a third compared to competitor products. 
 

Commission President Ursula von der Leyen described the plan as both an immediate response to crisis conditions and a longer-term roadmap to resilience. She emphasised that accelerating the transition to clean energy is essential not only for climate goals but also for economic stability and security.

Fossil fuels still account for 57% of the EU’s energy consumption, with imports reaching €340bn in 2025, according to the EC. AccelerateEU seeks to address this dependency through a combination of short-term relief measures and systemic reforms, structured around multiple pillars.

The first focuses on strengthening coordination among member states. The EC will enhance oversight of gas storage refilling, oil stock releases and refinery capacity, supported by regular coordination meetings. The aim is to ensure consistent action across the bloc and avoid fragmented national responses during supply disruptions. To improve transparency and preparedness, a new Fuel Observatory will monitor production, imports, exports and stock levels of transport fuels, enabling early identification of potential shortages and more targeted interventions – particularly for sectors such as aviation and heavy transport.

Protecting consumers and businesses from price shocks forms the second pillar. The EC is urging governments to implement targeted support measures, including income assistance, energy vouchers and temporary reductions in electricity taxation for vulnerable households. A State Aid Temporary Framework will provide additional flexibility for member states to support industries most exposed to rising energy costs.

The strategy also depends on accelerating the deployment of homegrown clean energy. A forthcoming Electrification Action Plan will introduce an EU-wide target and outline measures to remove barriers in key sectors including industry, buildings and transport. The plan also calls for rapid deployment of sustainable aviation fuels and other low-carbon transport solutions.

Infrastructure development is considered to be a critical enabler. The EC is pushing for rapid progress on the EU Grids Package and full implementation of existing legislation to modernise electricity networks. Upgrading grids and maximising current renewable assets – through measures such as repowering wind farms and expanding offshore wind and hydropower – are expected to deliver quick gains in clean energy supply.

Financing remains a major challenge. The EC estimates that €660bn in annual investment will be needed through 2030 to meet energy transition goals. While €219bn is available through the Recovery and Resilience Facility, alongside other EU funding streams, public finance alone will not meet the need, it warns. To bridge the gap, the EC has launched a Clean Energy Investment Strategy and plans to convene an investment summit later this year to mobilise private capital.

Developer calls for greater electrification 
A new report from renewables developer Copenhagen Infrastructure Partners (CIP) argues that large-scale electrification and clean energy deployment are not only central to decarbonisation in Europe, but also essential for energy security and price stability.

Currently, imported fossil fuels meet roughly 40% of Europe’s energy demand at an annual cost of about €250bn, according to the analysis. CIP’s modelling, developed with Ea Energianalyse, suggests that transitioning to a renewable-led, electrified system could see Europe sourcing up to 95% of its electricity from domestic clean energy by 2050, while reducing power prices by as much as 40%.

The report also highlights the structural challenges facing Europe’s energy system.  CIP estimates that around €210bn/y will be needed through 2050 – broadly comparable to current annual spending on fossil fuel imports. A significant share of this investment must be directed towards electricity grids, which are widely seen as a critical bottleneck, it says.

The report also forecasts that Europe will need to invest approximately €2.9tn in grid infrastructure by 2050, or around €120bn/y, to support electrification and integrate large-scale renewable energy.

The report outlines 16 policy recommendations, including safeguarding electricity market design, implementing targeted tax and tariff reforms to improve the competitiveness of clean energy, and incentivising grid operators to invest ahead of demand.

The CIP report, titled Charging ahead – a roadmap for an electrified, competitive and resilient European energy system, can be viewed here.
 

The reasoning behind this mechanism is straightforward. If factories inside the EU are obliged to compensate for their carbon emissions when manufacturing their goods according to the EU Emissions Trading Scheme (ETS), other countries producing those products must face similar carbon expenses.

EU ETS is Europe’s carbon trading system. Within the EU ETS, large-scale industry players must purchase carbon allowances for each tonne of CO2 emitted. As the availability of carbon credits becomes rarer each year, the price of carbon rises.

However, as companies begin to prepare for the cost aspect of the programme, many are finding that the biggest CBAM savings today do not necessarily come from switching to cleaner production. Instead, they come from replacing default emissions values with verified emissions data using EU-approved methodologies and independent verification. In practice, moving away from conservative default values can significantly reduce CBAM exposure even when verified emissions are not especially low.

In the early stages of CBAM implementation, carbon performance alone will not always determine competitive advantage. In many cases, it is the availability of verified carbon evidence that currently defines the cost difference.

Where CBAM costs are really coming from 
CBAM requires all EU importers to report the ‘embedded’ CO2e emissions (ie the total amount of greenhouse gas emissions) associated with the imported goods. Importers must then compute the actual carbon cost based on the supplier’s reported product-specific emissions data. If no such product-specific emissions data is available, importers must instead apply the default emissions values specified by the European Commission.

To evaluate emissions, manufacturers determine the total amount of fuel and other direct inputs used during the manufacturing process, such as the fuel burned during production at a steel mill. These inputs are then converted into tonnes of CO2 using EU-approved methodologies. The results are subsequently verified by an independent expert who is accredited under EU rules. This verification process can be expensive and may be difficult to obtain in many developing countries.

CBAM also requires emissions from key precursor materials to be included. This means upstream suppliers’ emissions must also be calculated and verified. If they are not, importers must apply default values for those inputs. Since these upstream processes can account for up to 80% of a product’s footprint, companies may still face significant exposure to default values even when their direct supplier’s emissions are verified.

These default values are in general very high and often represent the maximum possible emissions of the most polluting facility within a specific country/region. A highly efficient steel plant in, for example, India, Brazil or Turkey would be evaluated as if it was the least efficient plant in that region, due to the lack of formally verified emission data which meet EU standards.

Equity issues exist here as well. Developing economy suppliers that have decreased their emissions will likely see no decrease in their CBAM costs if they have not had their improvements officially recognised by the EU. The system rewards verified performance (not just ‘green’ performance). However, obtaining third-party verification requires time, expertise and financial resources, which can present practical challenges for some suppliers.

All these measures take time and resources. If there is no verified data, then EU importers shall use default values. Applying such values to carbon pricing will increase the price of carbon significantly, even if a manufacturing facility uses more advanced technology than others. Therefore, data about carbon emissions has become another aspect of pricing.

Why reducing emissions isn’t enough on its own 
Many people think that simply changing to a more environmentally friendly way of producing something will result in significantly reduced CBAM costs. However, the reality is far more complex.

CBAM for products like steel does not just calculate emissions in isolation. Rather it calculates the difference between a product’s emissions and a benchmark based on the lowest emissions associated with production within the EU.

However, there is a second, commonly overlooked, factor which affects this calculation. For many types of steel products, most of the emissions associated with the manufacturing process occur at the blast furnace stage; upstream of the final production process. Therefore, a producer of finished or semi-finished goods destined for export into the EU may have to rely upon the emissions data provided by its own suppliers; one or two stages back in the supply chain.

Unless these upstream emissions have been verified, then the importer will have to apply default values to those parts of the product’s footprint even if the direct supplier provides accurate numbers.

Many people think that simply changing to a more environmentally friendly way of producing something will result in significantly reduced CBAM costs. However, the reality is far more complex.

How importers can avoid unnecessary costs 
CBAM will now become an inherent part of the cost structure of each shipment into the EU, directly affecting the profitability of imports via the landed cost. Therefore, importers must be aware of the points at which they are vulnerable to default values and how any missing links could translate into financial risk. If there is no verification of emissions data, then the conservative value will be applied, which might result in increased prices on imported products.

It will be important to have more transparent and timely communication with suppliers, setting out expectations on how they will track and calculate their emissions based on third-party verifications. Making assumptions on emissions data without supporting documentation will probably result in unpleasant surprises once the true cost of CBAM becomes evident.

Importers will have to go past the immediate suppliers and capture the emissions data throughout the supply chain, which includes even the raw material suppliers, since missing data higher in the chain may result in applying default values.

As we transition into the cost phase of the CBAM policy, companies that have been able to calculate their own emissions will become better competitors in the new trade environment.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘The carbon border shift – UK industries will need to brace for CBAM compliance’. UK business leaders need to start building a carbon strategy to ensure CBAM compliance and remain competitive, writes Lili Strege, Carbon Analyst at CFP Energy. 
• ‘EU sets binding 90% emissions reduction target for 2040’. The EU has agreed on a binding target to cut greenhouse gas emissions by 90% from 1990 levels by 2040, while expanding how member states can use carbon credits.

RAC Senior Policy Officer Rod Dennis said: ‘It took around 14 years for a million battery-electric vehicles to be on the UK roads, so for this figure to double in just a further two is impressive.’

The growth in EVs is driven by unprecedented manufacturer discounting and government incentives, according to the Society of Motor Manufacturers and Traders (SMMT), which has also released new data. It found that about 4.5% of all vehicles driving in the UK (42.5 million) are now zero emissions. More than double that percentage are electrified; battery-electric, hybrid, plug-in hybrid or fuel-cell electric.

But many customers aren’t buying. The SMMT points out that the UK’s cars are getting older, with the average age rising to 9.7 years, up from 9.5 in 2024, ‘as motorists hold onto vehicles for longer amid cost-of-living pressures and economic uncertainty’. It added: ‘If road transport emissions in terms of both carbon and pollutants are to improve faster, the pace of fleet renewal must also quicken, benefiting both the climate and air quality.’

The UK was the second-biggest EV market in Europe after Germany in terms of new registrations for the second year in a row, according to figures from Germany’s Centre for Solar Energy and Hydrogen Research Baden-Württemberg (ZSW). The UK overtook third-place France in 2024. New EV registrations in 13 European countries more than doubled EV registrations in the US and Canada, although China continues to lead the world.

ZSW said: ‘Even though almost all markets recorded partially significant growth, China now accounts for two thirds of the 21.4 million new registrations, totalling 14.2 million vehicles. Moreover, almost every second newly registered car there is an electric vehicle.’

It reported that there was a total of 74 million EVs on the road in 2025.
 

It quoted Secretary Wright as saying: ‘The future is extremely bright for the nations that join the United States in pursuing common sense energy policies that deliver prosperity and security for their respective people.’

In the near term, official figures find little headroom for increases in LNG output in the current market of constrained global supply thanks to the near-total closure of the Strait of Hormuz.

‘We expect US LNG exports will increase, but only by a small portion of the missing volumes,’ wrote authors of an in-brief analysis published by the US Energy Information Administration (EIA) in late April, referring to the closure of the Strait, which has impeded supply of 10bn ft3/d, 20% of global supply.

US LNG export was estimated at 17.9bn ft3/d in March. The EIA predicts those figures will rise to about 19bn ft3/d by the end of the year, rising above 20bn ft3/d towards the end of 2027.

In terms of growth of additional export capacity, the EIA predicts 2.4bn ft3/d of additional export capacity by the end of the year, due to expansions at Golden Pass trains 1 and 2, and Corpus Christi Stage 3 (trains 5–7).

QatarEnergy announced the first LNG export cargo from the 18mn t/y capacity Golden Pass, a partnership between QatarEnergy (70%) and ExxonMobil (30%), in April. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, and President and CEO of QatarEnergy, said: ‘This is a significant industry milestone that marks a new chapter in QatarEnergy’s global efforts to meet rising LNG demand and ensure reliable supplies to international markets.’

However, investment capital for new LNG capacity might come from an unexpected source: renewables developers. The US administration has brokered two more deals to incentivise offshore wind developers to voluntarily revoke their offshore wind leases – and not seek future ones – in favour of fossil fuel investments, following the first of a kind with TotalEnergies announced earlier this year. The deals relate to Golden State Wind, a Californian floating offshore wind project, and the 2,400 MW capacity fixed-bottom Bluepoint Wind project offshore New York and New Jersey.

The US Department of the Interior said: ‘These historic agreements provide dollar-for-dollar reimbursement for offshore wind leases that have been impractical to develop without relying on taxpayer subsidies.’

The statement also quoted Associate Attorney General Stanley E Woodward, Jr as saying: ‘The Department of Justice is committed to working with parties to reach agreements that are in the best interests of the Nation and the American people – protracted litigation benefits neither, and I am proud to have helped facilitate today’s historic deals that advance the President’s Energy Dominance Agenda.’

A number of executive orders and injunctions put forward by the US administration have been overturned in the courts in recent months.

Bluepoint Wind is 50% owned by Global Infrastructure Partners, and 50% owned by Ocean Winds North America. According to the Department of the Interior, Global Infrastructure Partners has committed to invest up to $765mn, the original bid amount for the Bluepoint Wind offshore project (Lease No OCS-A 0537), into a US-based LNG facility. Following this accelerated investment, the Department of the Interior will cancel the lease and reimburse the company’s bid payment in the amount invested in the LNG project.

Golden State Wind is 50% owned by Ocean Winds North America, and 50% by Reventus Power. Under the terms of the agreement, Golden State Wind will be eligible to recover approximately $120mn in lease fees after an investment has been made of an equal amount in the development of US oil and gas assets, energy infrastructure and/or LNG projects along the Gulf Coast. Michael Brown, CEO of Ocean Winds North America, a 50% owner of Bluepoint Wind and Golden State Wind, said: ‘Our priority remains disciplined capital allocation and delivering reliable energy solutions that create long-term value for ratepayers, partners and shareholders.’
 

The UAE Oil Ministry said the decision to exit OPEC was in the national interest, following a review of its production policy and capacity. It added that the UAE remained committed to market stability and would continue to cooperate with producers and consumers to that end. The ministry also noted that the UAE’s departure from OPEC would provide it with more flexibility to respond to market dynamics.

Although UAE oil export has been constrained by the closure of the Strait of Hormuz, it also controls a 1.5mn b/d-capacity pipeline from the Habshan onshore field in Abu Dhabi to Fujairah on the Gulf of Oman, outside of the Strait of Hormuz.

Commenting on the announcement, Jorge Leon, Head of Geopolitical Analysis at Rystad Energy, said: ‘OPEC and OPEC+ have only ever been as strong as the members’ willingness to hold barrels back from the market, and the UAE was one of those. Losing a member with 4.8mn b/d of capacity, and the ambition to produce more [5mn b/d by 2027], takes a real tool out of the group’s hands.’ 

He continued: ‘The timing tells you something about where the oil market is going. With demand nearing a peak, the calculation for producers with low-cost barrels is changing fast, and waiting your turn inside a quota system starts to look like leaving money on the table. Saudi Arabia is now left doing more of the heavy lifting on price stability, and the market loses one of the few shock absorbers it had left.’

The UAE’s withdrawal from OPEC and OPEC+ marks a significant shift for the oil-producer group. Alongside Saudi Arabia, it is one of the few members with meaningful spare capacity, the mechanism through which the group exerts market influence and responds to supply shocks. Its departure therefore removes one of the core pillars underpinning OPEC’s ability to manage the market, according to Rystad Energy.

The UAE joined OPEC in 1967, seven years after the oil cartel was first established by Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. The organisation was set up to manage the supply of oil to avoid price volatility and ensure a steady income, rather than leaving price determination solely to market demand or corporate decisions. The number of countries in OPEC has fluctuated over the years, with other countries leaving the cartel including Angola, Ecuador, Indonesia and Qatar.

Following the UAE’s departure, 11 countries will remain OPEC members – Algeria, Equatorial Guinea, Gabon, Libya, Nigeria and the Republic of the Congo, in addition to the five founding members. There are an additional 10 non-OPEC members in the wider OPEC+ alliance, including Russia, Kazakhstan and Azerbaijan.
 

This energy is sourced from over 1,600 behind-the-meter battery systems. Polarium’s cloud-based platform pools these decentralised units into a single resource, allowing RWE to manage them for grid balancing. The venture has set long-term targets to expand the portfolio to 300 MW and 810 MWh, integrating more than 10,000 individual battery systems.

Ulf Kerstin, Chief Commercial Officer at RWE Supply & Trading, stated that batteries are becoming essential for a stable energy supply. He noted that Polarium’s virtual battery is intended to complement RWE’s existing generation and storage portfolio.

Leif Ottoson, CEO of Polarium, shared that systems originally intended for local infrastructure can now play a role in the wider energy system. He said the aim is to maintain local availability while marketing excess flexibility.

Hungary: utility-scale hybrid assets
The European Bank for Reconstruction and Development (EBRD) has provided a €70mn loan as part of a €210mn financing package for a solar and battery project in Hungary. Developed by Renalfa IPP, the project combines a 450 MW solar photovoltaic parc with a co-located 250 MW/1 GWh battery storage system.

Located in north-eastern Hungary, the facility is expected to deliver approximately 448 GWh of renewable electricity annually. The project plans to sell electricity directly into the Hungarian market without a support scheme or a corporate power purchase agreement (PPA).

Ivo Prokopiev, CEO of Renalfa IPP, stated that the hybrid asset would allow the company to offer ‘green baseload’ products. This is said to be possible by using the battery to store excess solar energy for later distribution.

The EBRD notes that this investment marks its first energy project in Hungary since 2010. Anca Ionescu, the bank’s Regional Head, stated that the deal shows a commitment to Hungary’s goal of 30% renewable energy consumption by 2030.

Grzegorz Zielinski, EBRD’s Director of Energy for Europe, stated that the project sets an example for the region. He noted that combining solar and storage at this scale is intended to demonstrate how regional energy security can be enhanced.

Sweden: large-scale grid integration
In the Nordic region, Centrica Energy has signed an optimisation agreement for the Ånge Storage Solutions project in Sweden. The BESS facility has a capacity of 70 MW and 160 MWh and is a joint venture between Delta Capacity and Wood & Co.

Cassim Mangerah, Managing Director of Centrica Energy, stated that assets like the Ånge BESS are considered vital for a decarbonised power market. Centrica Energy will serve as the project’s optimiser, providing 24/7 trading services via forecasting tools and algorithms across wholesale markets and ancillary services. The battery is designed to provide rapid-response capabilities to balance fluctuations in production and consumption.

According to data provided by the partners, the Stellium facility achieved an hourly matching score of 95.4%. This figure is significantly higher than the current UK market average, which the report estimates at approximately 43%. Achieving this involved sourcing power from over 3,300 independent UK renewable generators.

Paul Mellon, Operations Director at Stellium, acknowledged criticism of data centres for inflexible energy use. He stated that hourly matching provides transparency and demonstrates that large-scale digital operations can align with decarbonisation goals.

The partners state that directly linking demand to local renewable energy output helps the facility avoid ‘greenwashing’ concerns associated with non-time-matched Renewable Energy Guarantees of Origin (REGOs). This approach is said to encourage the expansion of local renewable assets. By creating a direct market for hourly renewable power, the model provides more predictable revenue for independent wind and solar farms across the UK.

According to a recent International Energy Agency (IEA) report, global data centre electricity consumption rose by 17% in 2025, alongside a $400bn investment from the five largest technology firms to expand digital infrastructure. The IEA notes that AI-related power use is increasing faster than general data processing. The agency projects total data centre demand will double by 2030, while AI-specific energy consumption will triple.

The IEA adds that a growing number of global projects is putting pressure on national planning systems, leading to delays in grid connections and prompting technology providers to seek reliable power solutions. And plans are being held back by tightening supply chains for key components like transformers and gas turbines.

The IEA report identifies AI as both an ‘energy taker’ and a potential ‘energy maker.’ While AI consumes significant power, it also drives innovation in long-duration energy storage. The agency states that strong demand from the tech sector is accelerating the commercialisation of next-generation energy technologies, including increased interest in carbon-free sources that provide constant baseload power to data centres.

The IEA says that the ‘scramble for solutions’ will likely persist as AI models grow more complex and energy-intensive.

Reports from Good Energy and Stellium indicate that technology already exists to decouple data growth from reliance on fossil fuels. They suggest the industry must now scale these solutions to meet future demand without compromising environmental commitments.

In related news, the Greening AI Data Centres Coalition (GADCC), a new initiative involving nine global bodies, including the World Green Building Council and the Climate Bonds Initiative, was recently launched to establish clear, credible standards for sustainable development. By defining what green means – focusing on clean energy, water recycling and heat reuse – the coalition said it aims to help investors and operators cut through greenwashing and direct capital toward facilities that meet legitimate environmental criteria.

The importance of these standards is shown by the rapid scale of investment. Sean Kidney, CEO of the Climate Bonds Initiative, warned that without such guidance, the trillions currently being poured into AI infrastructure risk becoming a ‘climate disaster’. Beyond energy, the GADCC is focused on balancing this growth with ‘responsible development’ that protects local resources and energy affordability. This framework is designed to complement local innovations, like the Newcastle hourly-matching model, by providing a consistent, data-backed benchmark that is said to protect communities and energy security worldwide.
 

Today, the picture is very different. Electric vehicles are plugging into residential streets, heat pumps are reshaping winter demand, and data centres are drawing huge amounts of power on to networks that weren’t built for that purpose.

Electrification of transport and heating is dramatically changing load profiles. Distributed energy resources like solar panels and batteries are making power flows more complex and less predictable. Where electricity once flowed neatly from large generators through transmission systems to customers, in many cases it now flows in two directions, indicating a far more complex network and signaling the end of simple directional flow.

At the same time, climate pressures are increasing the stress on infrastructure. Higher ambient temperatures accelerate the ageing of cables and transformers, whilst more frequent extreme weather pushes equipment closer to its operational limits. The result is a growing risk of insulation degradation and unexpected failures.

Traditional maintenance strategies were not built for this level of complexity, with periodic inspections and time-based replacement cycles assuming relatively stable operating conditions. With modern energy systems, these methods risk missing early signs of deterioration while also driving unnecessary interventions on healthy equipment.

Scheduled maintenance to condition intelligence
A modern grid needs a modern solution, and by moving from time-based maintenance to condition-based decision making, digital monitoring and analytics become central to maintenance.

With continuous network asset data, operators can detect subtle changes in behaviour long before they escalate into faults. Instead of relying solely on scheduled inspections, engineers can focus on real indicators of deterioration, enabling targeted maintenance and earlier intervention. The principle is simple but powerful. If operators can see the early signals of failure, they can act before customers ever notice a problem, ultimately putting an end to network faults.

Partial discharge (PD) monitoring is a strong example of this approach in practice. PD activity is one of the earliest indicators of insulation breakdown in high-voltage equipment such as switchgears and cables. If left undetected, it can lead to catastrophic asset failure.

With the right monitoring techniques, it can be identified and addressed at a much earlier stage. Tools such as the UltraTEV Plus2 from EA Technology can make condition-based testing significantly easier and engineers can use the technology to detect the signals typically associated with PD during routine site inspections.

Meanwhile, continuous monitoring solutions provide ongoing visibility into asset health, alerting operators to emerging risks in real time. These insights transform maintenance from reactive firefighting into proactive asset management.

Intelligence requires trusted data
However, monitoring alone is not enough. Data only becomes valuable when it is reliably collected and interpreted correctly. The solutions available to HV asset owners can capture every aspect of a network’s health and performance, but without the capability to parse this data effectively, it’s limited in value. Especially in cases where data may be siloed or fragmented across teams.

Easy-to-use software – such as, perhaps, EA Technology’s Managed Surveys – is paramount to help interpret this data and empower operators to make better decisions around asset management and maintenance.

In practice, these systems break down the barriers between teams and present engineers, planners and asset managers with a shared view of the network. As a result, it becomes far easier to identify genuine network risks when regular monitoring data is combined with historical performance and operational load.

Without that joined-up intelligence, even the most advanced monitoring technology risks becoming just another stream of unused data.

Ultimately, the goal is not simply to build more grid infrastructure, it’s to build a smarter grid – one that understands its own condition and provides asset owners with the information needed to ensure smooth operation.

Smarter decisions for the energy transition
If operators can streamline their data, it paves the way for smarter investments. Smarter maintenance and better intelligence give network operators greater confidence in those decisions.

Continuous monitoring can reveal which assets are approaching failure and require reinforcement and show where infrastructure remains healthy and can safely operate for longer, supported by condition monitoring rather than immediate replacement.

This ability to differentiate helps direct limited resources to where they will have the greatest impact whilst also reducing unnecessary disruption, and ensures investment aligns with real network needs.

Ultimately, the goal is not simply to build more grid infrastructure, it’s to build a smarter grid – one that understands its own condition and provides asset owners with the information needed to ensure smooth operation.

That’s the real meaning of modernisation. We shouldn’t just reinforce what we have but be able to understand our infrastructure better. In the race to build a resilient, net zero energy system, that understanding may be the most valuable upgrade of all.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Why the grid will decide the UK’s energy future’. While much of the national conversation focuses on generation targets, it is the UK’s electricity grid itself that will determine how quickly, equitably and productively the country can reach net zero, explains Mark Neller, Arup’s Energy Leader for the UK, India, Middle East and Africa.
• ‘Modern grids will be the foundation for future growth in Europe’. As Europe seeks to strengthen energy security, stimulate sustainable growth and affordability, and reduce emissions, accelerating electrification and investing in modern grid infrastructure must become urgent priorities, writes Maxine Ghavi, Executive Vice President and Head of Europe at Hitachi Energy.
   

The Siemens Gamesa 14 MW turbine is around 262 metres tall with a rotor diameter of 236 metres. A single revolution of one turbine can generate enough electricity to power a UK home for more than four days.

The project is the first in the UK to feature 115-metre blades, which are seven metres longer than the previous offshore wind record of 108 metres, also set by Siemens Gamesa.

All 285 blades for East Anglia THREE are being manufactured in the UK at the company’s factory in Hull.

The project is expected to become operational at the end of 2026.

Global wind installations rise 40% 
Meanwhile, new data from the Global Wind Energy Council (GWEC) shows that 165 GW of wind capacity was installed globally last year, a 40% increase compared with the previous year.

The 2026 Global wind report indicates that this total includes 155.3 GW of onshore wind (up 42%) and 9.3 GW of offshore wind (up 16%). Global cumulative wind capacity has now reached 1,299 GW across 138 countries, with 28,395 turbines installed in 57 markets during the year.

China and India remained the largest contributors in Asia, adding more than 126 GW combined in 2025. China accounted for over 120 GW, while India installed a record 6.3 GW, nearly doubling its annual additions.

Europe added 19.1 GW of new capacity (up 16%), its second-highest annual total, supported by growth in Germany and Türkiye. The EU-27 installed 15.1 GW (up 17%), although this remains below the growth required to meet 2030 energy and climate targets, according to the report.

In the US, onshore wind installations increased by nearly 7 GW compared with the previous year.

Looking ahead, GWEC Market Intelligence projects that 969 GW of new wind capacity will be commissioned globally over the next five years, averaging 194 GW annually through 2030, equivalent to a compound annual growth rate of 5.2%.

While China is expected to account for around 63% of new installations in 2026, growth is projected to broaden geographically by the end of the decade, with increasing contributions from Southeast Asia, Central Asia, and Africa and the Middle East.

Global wind capacity is projected to exceed 2 TW by 2029, six years after surpassing the 1 TW mark in 2023.

US wind installations set to grow as market grows
A closer look at the US reflects this broader momentum, with new forecasts pointing to a near-term recovery alongside more measured growth through the rest of the decade, according to Wood Mackenzie’s US wind energy monitor report.

In comparison to GWEC, the report was even more positive, finding that installations rose to 8.2 GW in 2025, a 49% year-on-year increase, and are expected to reach around 11 GW in 2026, marking the strongest year for new capacity in five years.

In total, 48 GW of new wind capacity is forecast to be added by 2030, supported by a 15.4 GW pipeline of projects that have already cleared key commercial hurdles, providing a relatively high level of visibility in the near term.

Onshore wind is expected to dominate additions over the next few years, while offshore deployment is beginning to accelerate, with around 6 GW projected to come online by 2027.

However, the outlook remains uneven, the report warns. Policy uncertainty and permitting constraints – particularly involving federal approvals for land-based projects – continue to create bottlenecks, while elevated turbine and financing costs are adding pressure to project economics. Although recent clarity on tax incentives has improved near-term visibility, these factors could slow deployment beyond the current pipeline, even as rising electricity demand underpins the longer-term case for expansion.

To read GWEC’s 2026 Global wind report visit https://www.gwec.net/reports/globalwindreport.

To read Wood Mackenzie’s US wind energy monitor visit https://www.woodmac.com/industry/power-and-renewables/us-wind-energy-monitor/?utm_campaign=pandt_g&utm_medium=press_release&utm_source=tier_1&utm_content=WEM_Q1_2026
 

Conceived after the October 2020 blackout, which exposed vulnerabilities in the city’s power supply, the project improves Mumbai’s ability to import electricity from across Maharashtra and renewable-rich regions of India’s national grid.

Designed for a dense urban environment, the link includes a 30 km overhead line and a 50 km underground corridor, helping free around 2 km² of urban land.

Powered by Hitachi Energy’s voltage source converter technology, the converter station upgrade represents Mumbai’s most significant grid modernisation in nearly 25 years, increasing capacity from 250 MW to 1,000 MW.
 

All of those stocks were calculated before the release of 426mn barrels of strategic oil reserves earlier this year by International Energy Agency members.

Comparing country-by-country donations with the EIA data set provides additional context. For example, the quantity of crude oil agreed to be released by European OECD members in March totalled nearly 60% of the EIA’s figure for their publicly-held reserves. By similar comparisons, the US released 42%, Japan 30% and South Korea 28%. Those three countries and Europe released 381mn barrels of crude oil, leaving 553mn barrels remainining in public stocks, although many have significant commercial stocks as well.  

The EIA also reported that Saudi Arabia had stocks of 82mn barrels, Iran 71mn barrels, the United Arab Emirates 34mn barrels and India 21.4mn barrels.

Asked to comment about the situation on a visit to the Energy Institute on 23 April, former BP CEO John Browne said: ‘The price of oil is high, but it could have been much higher. There are a couple of things going on. One is the price is going up, so demand has come down. Demand always gets destroyed when the price goes up. And secondly, supplies were quite long in the world, and we’re drawing on inventory around the world. And very roughly, I suppose about half of the shortfall in supply as a result of the stress is coming from demand and half from stocks. The stocks never last forever, but right now they’re in good shape.’

Fig 2: Estimates of national crude oil reserves in late 2025 by country, including in some cases commercial holdings. (Note: Chinese commercial holdings are effectively state-owned.)
Source: EIA

‘Now it’s important to say this, we have already moved from gas setting the price of electricity around 90% of the time in the early 2020s, to around 60% today. And thanks to our clean power mission, we estimate gas will set the wholesale price around half of the time by 2030.’

‘But in addition to that, by building clean power we are expanding the proportion of generation on long-term fixed-price contracts, that’s CfDs [contracts for difference, in which the government contributes to guarantee underperforming assets], from around 20% today to over 60% by 2030, which is crucial because it helps break the link with volatile gas even further.’

The UK Energy Research Centre praised the plan. It said that it first proposed a ‘pot-zero’ CfD in 2022, which would place the older renewable energy schemes that receive Renewables Obligation payments (RO) on the fixed price CfD that has been used for new renewables schemes since 2017. It went on to say: ‘The “wholesale price CfD” announced by the government today stops short of the full pot-zero proposal, since it will leave the RO subsidy in place. This makes the potential savings smaller, but it will break the link with gas prices. The devil will be in the detail, but provided the majority of generators join the scheme, most of the UK’s power generation fleet will have a price that is not related to the global price of gas. Recent events demonstrate yet again the vulnerability of fossil fuel prices to geopolitical events that are impossible to predict.’

Not everyone was so positive. Trevor Wills, CEO of Pulse Clean Energy, said: ‘Direct market intervention can cause unintended outcomes which will be difficult to reverse. Distorted price signals are bad for consumers, producers, investors and businesses as they can create gaps which require further intervention to address. We need to avoid a game economic whack-a-mole that ends up slowing the very investment and energy scale-up that the country needs to enable future competitiveness and security.’

‘The issues we currently face on curtailment, grid economics and investment will remain. These are the issues we need to address. We welcome the engagement on Reformed National Price which the government has also announced and believe that this is the way forward. Without comprehensive market reform, where we can look at the whole picture and make some tough decisions, this proposal risks doing more harm than good.’

In March, solar power generation rose by 14% and wind by 8%. The new solar and wind capacity added in 2025 now generates twice the electricity previously supplied by LNG through the Strait of Hormuz. Excluding China, CREA reports the move away from fossil fuels was even stronger. In countries with real-time data, coal-fired power fell by 3.5% and gas-fired power by 4% in March, both offset by increased renewable generation.

CREA reports no significant increase in coal capacity and no decommissioned units were returned to service or had retirements delayed in March. A key economic factor limiting coal’s resurgence is that plants were already operating near maximum capacity before the crisis. Because coal is less expensive to operate than gas, these plants were already heavily used, leaving little room for further increases. The study uses near-real-time data covering 87% of global coal power and over 60% of gas-fired generation, including China, the US, the European Union and India.

Seaborne coal trade data reinforced that trend. According to analytics company Kpler, global seaborne coal transport volumes fell by 3% year-on-year in March, reaching their lowest level since 2021. This drop reflects reduced demand, not a supply disruption. Regionally, coal shipments to China and India fell by 9% and to South Korea by 4%. Türkiye and Vietnam saw even larger drops in coal imports, down 25% and 27% respectively, reflecting shifts in energy dynamics. In the US and India, solar power expansion was the main driver of reduced fossil fuel electricity generation. In India, non-fossil capacity rose rapidly, reaching 52.25% of total installed capacity by early 2026.

European countries like the Netherlands and Germany also made significant progress, with wind power making the largest contribution to displacing fossil fuels. In other countries, reductions in fossil fuel generation had more varied causes. In South Africa and Türkiye, improved operation of existing nuclear and hydropower plants drove declines, showing that diverse clean energy portfolios strengthen energy security.

While most major economies reduced coal use, CREA data show that Japan and South Korea were exceptions, recording significant increases in coal-fired power. The report notes these increases were due to weak nuclear output, not the global gas crisis. In China, coal-fired generation rose by 2% in March as coastal generators switched from gas to coal due to high prices. Despite this, coal generation remained well below 2024 levels, following a 6% decline in March 2025.

The Strait of Hormuz closure is accelerating demand for clean technologies, according to CREA. Governments are responding with ambitious new policy targets. Indonesia has established a task force for a 100 GW solar initiative, while Vietnam has revised its energy plans to further reduce reliance on coal and aims to have renewables make up 47% of installed capacity by 2030. Türkiye pledged to invest $80bn in renewable energy by 2035 to reach its 120 GW target and India’s Ministry of New & Renewable Energy (MNRE) has set a target to auction 50 GW of renewable energy capacity every year through 2028.

Lauri Myllyvirta, Lead Analyst at CREA, said that record clean power growth has mitigated the recent fossil fuel crisis. Myllyvirta noted that increased clean electricity generation prevented a projected surge in coal use that could have threatened climate goals. The data suggest the current crisis is making fossil fuels permanently more expensive than clean energy and storage.

Read the full analysis here.

The first round will focus on strategic sectors including rare earths, battery materials and defence-related raw materials – 17 materials in total – including battery-grade lithium, copper, aluminium and titanium. It is designed to support contacts between companies rather than intervene in commercial negotiations, contracts or pricing. The EC has presented it as a practical tool for firms, particularly smaller companies, seeking supply partnerships beyond their existing commercial networks.

Companies interested in taking part in this first round can register by the end of April.

The initiative reflects recent analysis from the International Energy Agency (IEA), which highlights the growing mismatch between the accelerating use of rare earths (which the EU specifies as neodymium, praesodymium, terbium, dysprosium, gadolinium, samarium and cerium) and the slow pace of supply diversification globally.

The IEA’s report finds demand for magnet rare earth elements – underpinning technologies such as electric vehicles, AI data centres, robotics and defence systems – has doubled since 2015 and is projected to rise by more than 30% by 2030.

‘Rare earth elements are indispensable to many of the technologies shaping the Age of Electricity and our increasingly digitalised economies, yet their supply chains remain among the most concentrated of all critical minerals,’ said IEA Executive Director Fatih Birol. ‘Recent disruptions have underlined how quickly these vulnerabilities can translate into real economic risks,’ he added.  

Among all the critical minerals analysed by the IEA, rare earths are among the most concentrated geographically across each stage of the value chain, with China accounting for around 60% of global mined production of magnet rare earths, while its share of refining is above 90%. Its dominance is even starker in downstream segments, with almost 95% of permanent magnet production, the report finds.

Recent developments have brought these vulnerabilities into sharper focus. Export controls introduced by China in 2025 led to significant short-term disruptions, with some manufacturers outside China facing difficulties in securing key inputs and, in certain cases, having to reduce production. While flows later recovered, the episode highlighted the potential exposure of downstream industries. The report finds that, if such controls were fully implemented, up to $6.5tn of economic activity outside China could be at risk each year, with automotive, electronics and other transport sectors heavily impacted.

Despite growing awareness of these risks, progress towards more diversified rare earth supply chains remains limited, the report notes. Current and planned projects outside the dominant supplier fall well short of projected demand. By 2035, existing and announced capacities are expected to cover only around half of mining requirements, a quarter of refining needs and less than a fifth of magnet demand outside China, highlighting a widening gap unless investment accelerates. The pipeline of downstream magnet projects remains particularly constrained compared with upstream mining developments, underscoring persistent bottlenecks in refining and magnet manufacturing.

Bridging this gap would require significant investment across the value chain. The report estimates around $60bn will be needed over the next decade to develop more diversified supply chains. While substantial, this is small compared with the potential economic losses from supply disruptions. Recycling and innovation could also play a key role, with recycling alone potentially reducing primary supply needs by up to 35% by 2050, while advances in material substitution and production technologies could ease pressure on the most constrained elements.

Achieving more secure and resilient rare earth supply chains, the report concludes, will require a coordinated international approach. Given the global distribution of resources, capabilities and demand, no single country can develop fully integrated supply chains in isolation, making cross-border cooperation essential to align investment and support project development.

To read the Rare Earth Elements: pathways to secure and diversified supply chains report go to https://www.iea.org/reports/rare-earth-elements
 

The funding forms part of the government’s Modern Industrial Strategy, under which the Department for Business and Trade is allocating £700mn to strengthen Britain’s advanced manufacturing sector. Agratas is the single largest beneficiary of the funding.

The facility is expected to create around 4,200 direct jobs and 300 apprenticeships, while generating an estimated £43bn in economic value over 25 years once fully operational. A corporate cousin of the facility under Tata is Jaguar Land Rover, which will become a key customer.

Major hydrogen investment to create 400 jobs in South Yorkshire
Meanwhile, a separate investment in a manufacturing site in South Yorkshire will support the expansion of electrolyser production.

Green hydrogen technology company ITM Power has secured £40mn from Great British Energy, alongside a £46.5mn government grant in principle, to significantly scale up its operations. The deal represents Great British Energy’s largest investment in domestic clean power to date.

The funding will support a 1 GW expansion of ITM’s Sheffield facility and is expected to support over 400 skilled jobs across manufacturing, construction and the wider supply chain.

The investment will accelerate production of ITM’s 2.5 MW capacity proton exchange membrane electrolyser Chronos.

The combined support builds on wider government backing for the hydrogen sector, including a £500mn commitment at the Spending Review for hydrogen infrastructure.

It also follows the signing of contracts for 10 of the first wave of UK green hydrogen projects, which are now set to become operational.
 

‘Initially, the deepest cuts in oil use have come in the Middle East and Asia-Pacific, mainly for naphtha, LPG and jet fuel. However, demand destruction will spread as scarcity and higher prices persist,’ said the IEA. It expects an overall oil contraction of 80,000 b/d of oil demand over the year as a whole.

In March, global oil supply fell by more than 10% to 97mn b/d. Global observed oil inventories fell by 85mn barrels that month. Floating oil stores within the Strait raised the Middle East total to 100mn barrels; onshore crude stocks rose 20mn barrels.

The IEA called the disruption ‘the most severe oil supply shock in history’, during which oil prices rose the largest ever in March. In mid-April, North Sea Dated crude was trading at more than double pre-conflict levels at $130/b.

According to the IEA, shipments through the Strait averaged around 3.8mn b/d in early April, compared to 20mn b/d beforehand, while pipeline exports from the west coast of Saudi Arabia and through Iraq and Turkey had increased to 7.2mn b/d.

It added: ‘The overall loss in oil exports exceeds 13mn b/d, with associated production curtailment and damage to energy infrastructure in the region resulting in cumulative supply losses of more than 360mn barrels in March and 440mn barrels projected for April.’

The IEA reports that oil inventories have been tapped to make up the shortfall. Where they are not available, operations are being reduced, with examples of cutbacks including Asian petrochemical producers and flight cancellations in the Middle East, Asia and Europe.

Some analysts view these changes as a key moment in energy trade, and not so temporary either. Javier Solis, Analyst at Wood Mackenzie – Maritime Team – said: ‘Europe’s diesel deficit and gasoline surplus, combined with Asia’s role as the balancing valve, represent a moving landscape in which pricing and flows remain tightly linked to political decisions rather than purely commercial signals.’

Wood Mackenzie reports that Europe, facing constraint in supply from the Middle East, has turned to long-haul North American crude and finished products. However, Europe is exporting surplus unleaded motor spirit and fuel oil to Asia and Africa.

In the meantime, European diesel prices remain high, because of heavy reliance on premium US imports. Diesel premiums are predicted to remain high for the rest of the year.

Asia has absorbed Europe’s excess gasoline and fuel oil alongside record volumes of North American crude.

International renewables agency IRENA contends that oil and gas supply disruptions show the risks inherent in fossil fuels.

‘The current crisis clearly demonstrates the strategic case for renewables as a national security imperative,’ commented IRENA Director-General Francesco La Camera.  

A new policy brief lays out national policies that can help in this regard. IRENA suggests nations: 

• Facilitate the deployment of distributed renewables.
• Use public information campaigns and mandates to reduce energy demand.
• Fast-track time-of-use tariff adoption to enable consumers to shift their electricity consumption to times where renewable supply on grids is high and prices are low.
• Implement fiscal measures such as grants, subsidies or tax rebates in support of electrification.
• Accelerate solar PV–battery hybrid mini-grids in off-grid and weak-grid remote areas.
• Accelerate two/three-wheeler electrification in emerging economies, incentivise electrification of public transport through financial and fiscal support, and encourage car-pooling where appropriate.

But large grid infrastructure projects can take up to 13 years to permit and build: far slower than electrification demand is rising. This demonstrates a clear challenge and, more importantly, an opportunity. Europe has decided to accelerate renewables deployment and electrification. Our grid must catch up, with urgency, to keep pace with the demands of European policymakers, industry and consumers.

At a societal level, what is electricity for?
Electricity is emerging as Europe’s new growth engine. Electrification strengthens Europe’s energy independence by reducing reliance on imported fuels, while enabling greater use of domestic renewable resources such as wind, solar and hydropower. Electrified industries are more efficient, more competitive, climate-friendly and less exposed to volatile fossil fuel markets.

The transition is already underway. Electric vehicles are transforming the transport sector. Heat pumps are becoming a central solution for low-carbon heating. Industrial electrification is accelerating in sectors from steelmaking to chemicals.

Data centres and digital industries are expanding rapidly. These developments reinforce a new reality: electricity now underpins industry, mobility, digital services and even defence, making the resilience, capacity and security of the grid foundational to Europe’s stability. Together, these trends are driving a structural increase in electricity demand across Europe.

This shift represents a historic opportunity. Electrification can underpin a new era of European growth – supporting innovation, strengthening supply chains and creating skilled jobs across the continent. Modern power infrastructure will enable new industries and technologies to flourish, from green hydrogen production to advanced manufacturing and AI-driven digital services.

However, electrification at this scale cannot happen without a corresponding transformation of Europe’s power grids and mobilising needed investments.

Electricity now underpins industry, mobility, digital services and even defence, making the resilience, capacity and security of the grid foundational to Europe’s stability.

Europe’s electricity networks were largely designed for a different era – one characterised by centralised generation and predictable patterns of consumption. Today’s energy system looks very different. Renewable generation is more geographically dispersed and variable, and cross-border electricity flows are increasing as European markets become more integrated.

As a result, Europe’s grids are facing unprecedented pressure. Across the continent, network constraints are already slowing the connection of renewable energy projects and delaying industrial electrification while generating additional costs for curtailment and negative energy prices. In most regions, grid capacity has become the major bottleneck to the energy transition.

Without rapid investment, grid limitations could constrain economic growth and delay decarbonisation. Electrification cannot advance faster than the infrastructure that supports it.

This is why Europe must urgently accelerate investment in smart, flexible and digital grid systems.

What is the role of future grids?
Future grids must do more than simply transmit electricity – they must actively manage a dynamic energy ecosystem as power systems fuelled by renewables are more complex to control. Digital technologies allow operators to monitor networks holistically in real time, optimise power flows and integrate distributed energy resources more efficiently while securing system resilience.

Digitalisation also is a security requirement. Europe faces rising cyber incidents, attempted grid sabotage and climate‑related stress on ageing assets. Modern grids must include hardened cyber‑physical systems, real‑time intrusion detection, advanced monitoring and climate‑scenario planning to maintain reliability.

Flexibility is equally critical. Demand response, energy storage and flexible generation will help balance increasingly variable renewable energy sources. Smart grids allow consumers to play an active role in the energy system – shifting consumption, providing flexibility and improving overall costs and efficiency.

Digitalisation also strengthens resilience. As power systems become more interconnected and complex, advanced monitoring, control and cybersecurity capabilities are essential to ensure reliability and protect critical infrastructure.

Investment in modern grid technologies delivers benefits far beyond the energy sector. Faster grid connections enable new industrial projects and reduce uncertainty for investors. Integration of affordable renewables and improved system efficiency lowers costs for consumers. Stronger infrastructure enhances energy security and reduces exposure to geopolitical risks.

Encouragingly, momentum is building. European policymakers increasingly recognise the importance of grid investment and new regulatory frameworks are beginning to reflect the central role of electricity networks. But the pace of change must accelerate significantly to match the scale of the electrification challenge.

What is to be done?
Europe now needs an ambitious Grid Action Plan – fully aligned with the EU’s Electrification Action Plan – that accelerates permitting, prioritises strategic cross-border corridors (especially north–south), increases long-term investment visibility, and introduces binding electrification and grid-development milestones.

To deliver this, European leaders should focus on three priorities:

• Treat grids as strategic infrastructure and fast‑track delivery.
• Invest smarter by targeting bottlenecks, deploying digital control technologies, and reinforcing substations and interconnectors.
• Harden the system through cyber‑physical resilience, climate adaptation and secure supply chains for critical grid equipment.

Europe has a clear opportunity to lead the global electrification transition. The technologies exist, the expertise is strong and the economic case is compelling. What is required now is coordinated action – bringing together policymakers, network operators, technology providers and industry to build the power system that Europe’s future depends on.

Electrification will shape Europe’s economy for decades to come. By investing today in modern, intelligent grid infrastructure, Europe can reinforce its security, strengthen competitiveness, unlock sustainable growth and build a resilient energy system fit for the future.

The path forward is clear: electrify faster, modernise the grid and power Europe’s next chapter of growth.

The views and opinions expressed in this article are strictly those of the author only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘Why the grid will decide the UK’s energy future’. Although much of the national conversation focuses on generation targets, find out why it is the grid itself that will determine how quickly, equitably and productively the UK can reach net zero, according to Mark Neller, Arup’s Energy Leader for the UK, India, Middle East and Africa.
• ‘Powering up: why electrification is key to building European competitiveness’. ‘Electrification is a catalyst for a resilient, competitive and climate neutral industry, shielded from fossil fuel volatility,’ according to a report by Eurelectric and Accenture.
   

Installed at the Gazéa farm, in Côtes-d’Armor, France, the facility has a production output of 180 tonnes of bioLNG and 330 tonnes of liquid bioCO2. Commissioning and testing will precede start of initial production later this year.

‘There is no future for agriculture in Brittany without livestock farming. Yet the future of livestock farming depends on the democratisation of biogas production and the support of this production. Sublime Energie’s model is a concrete solution to help livestock farms adapt,’ said farmer Alain Guillaume, Founder of Gazéa and of the French Association of Methanizing Farmers.

Sublime Energie’s next project, aimed to be commissioned by 2028, intends to connect 10 farms in the area to a shared processing hub.

In related news, the European Commission has approved a €3.7bn Czech plan to develop a biomethane market for transport, heating and industry with a price support scheme for new biomethane producers and existing biogas stations converted to biomethane.

The price scheme will involve a two-way contract for difference (CfD) that provides a bonus to producers selected through competitive tendering. It is expected to support installations with a total output of up to 350mn m3 of sustainable methane.

The scheme was approved under the EU’s Clean Industrial Deal State Aid Framework implemented last year.