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.
 

Having been named as GBE-N’s preferred bidder in June 2025, the design received regulatory justification from the Environment Agency in March.

Rolls-Royce SMR was selected as technology partner by Czech electrical utility ČEZ last year for the proposed installation of up to 3 GW of generation capacity.

The company said: ‘This contract with GBE-N will help Rolls-Royce SMR retain its crucial first mover advantage in a market that is growing and attracting significant international interest. The business is currently the furthest through any European regulatory process.’

The deal won’t immediately lead to construction of the plant, because the reactor design is still being assessed by the UK regulator, and is not due to complete that process until the end of the year.

In related news, the UK National Wealth Fund has announced plans to commit up to £599mn to Rolls-Royce SMR to help support development of its generic design.

National Wealth Fund CEO, Oliver Holbourn, said: ‘Today’s announcement marks a significant moment for the future of our nuclear industry… This is exactly what the National Wealth Fund has been established to deliver, backing promising homegrown projects and technologies that will deliver transformational impacts.’

I went on to earn a Master of Science in Information Systems and spent more than a decade working at the intersection of technology and enterprise transformation.

Q: How did you first hear about the Energy Institute and what motivated you to join? 
A: As a Senior Solutions Architect within AWS Energy, staying ahead of rapidly evolving energy policy, regulatory dynamics and cross-sector innovation remains critical. The Energy Institute has proven to be a powerful force multiplier in this regard:

• EI eLibrary and Publications – enabling industry-aligned, research-backed solution design.
• Events and conferences – connecting technology with real-world industry priorities.
• Global network – keeping me aligned with emerging trends and enabling broader influence.

Collectively, these resources have significantly amplified my ability to deliver impact – enabling me to bridge the gap between cutting-edge technology and the complex realities of the energy sector, and ultimately drive meaningful, scalable progress towards a more resilient and sustainable energy future.

Q: You were awarded EI Fellow under ‘Category 1: expertise in energy’. Please would you explain the nature of your energy expertise and how you have used this to best effect for your clients and wider industry?
A: My energy expertise sits at the intersection of cloud computing, AI, IoT [Internet of Things] and cybersecurity applied to energy and utilities. Over the past 12+ years, I have specialised in helping utilities and grid operators modernise critical infrastructure and accelerate decarbonisation through digital transformation.

In my role as a Senior Solutions Architect at AWS, I have translated advanced technologies into practical, scalable solutions such as AI and IoT driven predictive maintenance to reduce downtime and extend asset life, real-time monitoring to improve efficiency, and cloud migration strategies that lower costs and enhance resilience.

I also collaborate with executive leadership on long-term digital and decarbonisation strategies, ensuring that innovation aligns with sustainability goals. My contributions extend to the broader industry through thought leadership, research, engagement with IEEE [the Institute of Electrical and Electronics Engineers] and other professional organisations, and global speaking – driving the broader adoption of AI- and cloud-enabled energy solutions.

Q: Tell us about your current job and industry, and how your work is contributing towards a just transition to net zero? 
A: Today, I’m part of the energy team within AWS Strategic Industries, where I bring together my technical background and long-standing passion for energy to help some of the world’s largest energy organisations navigate this transformation. I lead strategic initiatives focused on leveraging cloud, data and emerging technologies to reimagine energy operations at scale – driving efficiency, resilience and innovation across the value chain.

A key focus area for me is grid modernisation. I help accelerate interconnection studies – a major bottleneck delaying new renewable projects. By significantly reducing study timelines, we enable faster integration of solar and wind into the grid, directly advancing the energy transition. This is not incremental improvement; it’s unlocking capacity that would otherwise sit idle for years.

My contribution to the net zero transition is embedded across every engagement. Today, nearly every energy company is pursuing ambitious decarbonisation goals – and I help translate those ambitions into executable, technology-driven outcomes. This includes:

• Applying AI/machine learning to improve renewable forecasting and grid reliability.
• Enabling faster, more accurate grid simulations for clean energy integration.
• Delivering data platforms to track and reduce carbon emissions.
• Architecting scalable cloud solutions that replace energy-intensive infrastructure.

The impact compounds across organisations – transforming not just individual companies, but the broader energy ecosystem.

The sector itself is uniquely complex: highly regulated, operationally critical and constrained by legacy infrastructure.

I’ve also been an early driver of Generative AI adoption in the sector, helping organisations reimagine operations through predictive maintenance, demand forecasting and intelligent grid management – delivering impact that extends beyond individual enterprises to the broader energy ecosystem.

Q: How do you see the future relationship between AI and energy? AI is a big consumer of electricity, but is changing the way we work. Are you an optimist or a pessimist?
A: I am fundamentally an optimist about the relationship between AI and energy, with a strong sense of responsibility. While AI is a growing consumer of electricity especially with large-scale data centres, its potential to transform the energy system outweighs its impact when applied thoughtfully.

AI already enables smarter grids, predictive maintenance, demand forecasting and improved renewable integration, reducing inefficiencies and accelerating decarbonisation. In practice, it drives meaningful gains in operational efficiency while reducing downtime and waste.

Looking ahead, AI will be central to a more dynamic, decentralised and resilient energy system. The key challenge is ensuring it is powered sustainably through renewable energy and efficient infrastructure. With the right governance and innovation, AI will be a net positive for the energy transition.

Q: In thinking about the future relationship between AI and energy, how would you allocate responsibilities between the tech sector and the energy sector?
A: The future relationship between AI and energy requires a shared responsibility model between the technology and energy sectors, with clear but complementary roles.

The technology sector must take responsibility for improving the energy efficiency and sustainability of AI systems. This includes designing energy-efficient algorithms, optimising data centre operations, investing in low-carbon infrastructure and increasing transparency around energy consumption. Tech companies should also build tools that enable energy providers to better forecast demand, optimise assets and integrate renewables.

The energy sector, on the other hand, must evolve to support the growing and dynamic demands of AI-driven workloads. This includes modernising grid infrastructure, enabling flexible and distributed energy systems, and accelerating renewable generation to meet increased demand sustainably. Energy providers must also embrace digital technologies to improve visibility, control and responsiveness across the grid.

Critically, the greatest impact will come from collaboration between the two sectors. I have seen how joint innovation combining cloud platforms with energy domain expertise can unlock transformative outcomes such as real-time grid optimisation, AI-driven forecasting and resilient infrastructure design. Ultimately, the responsibility is shared: the tech sector must make AI more energy-efficient, while the energy sector must make energy systems more intelligent and sustainable. Together, they form the foundation of a scalable and secure energy future.
 

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 Deepa’s footsteps, click to find more about how to become a Fellow of the Energy Institute (FEI).
 

In large PV installations, conventional monitoring systems typically operate at string or inverter level, meaning faults affecting individual modules often go unnoticed. Underperforming modules can therefore remain undetected until they begin to affect overall plant yield.

While intact bypass diodes can limit power losses when a module fails, defective diodes allow efficiency losses to spread across entire strings. This can significantly reduce energy yield and plant availability, leading to measurable economic losses.

The proposed system addresses this limitation through the deployment of compact sensors mounted on the rear of individual modules. These sensors measure current, voltage and temperature, while irradiation data is supplied via a separate weather station. Measurements are transmitted via a wireless mesh network to a central platform, where the data is synchronised and analysed.

AI models developed at Fraunhofer evaluate deviations from expected performance and can attribute anomalies to specific causes, including localised module faults, soiling or shading. Beyond fault detection, the system is designed to generate recommendations for corrective actions such as module cleaning or replacement.

Testing is currently underway at Fraunhofer’s Elbfabrik research facility, where sensor performance, communications reliability and AI based fault detection are being validated under controlled fault conditions.

Other project partners are Beia Consult International of Romania and INELSO Innovative Electrical Solutions of Turkey.

It will serve as the companies’ exclusive vehicle for onshore solar, wind and battery storage projects in nine countries in three regions: Southeast Asia (Indonesia, Malaysia, Singapore and the Philippines), Asia-Pacific (Japan and South Korea) and Central Asia (Azerbaijan, Kazakhstan and Uzbekistan).

‘Asia will be the main driver of global electricity demand growth this decade, and this collaboration with TotalEnergies will accelerate our progress across the continent,’ said His Excellency Dr Sultan Al Jaber, UAE Minister of Industry and Advanced Technology and Chairman of Masdar.

Patrick Pouyanné, Chairman and CEO of TotalEnergies, added: ‘We are delighted with the signing of this agreement with Masdar, which brings together two major renewable players to build a renewable champion in Asia. It will allow us to combine the strengths of our two companies to secure significant positions in these markets and create more value than if we were acting alone.’

The venture will be headquartered in Abu Dhabi, UAE, and will employ around 200 employees from both companies. The closing of the agreement is subject to regulatory approvals and conditions.
 

Gernot Gauglitz, Managing Partner of UKA, said that utilising the most efficient turbines is a necessity due to competitive auction environments. ‘From May 2026, I expect the auctions to be oversubscribed by 400% on a permanent basis.’ Gauglitz noted that success in future tenders depends on combining efficient technology with low construction costs and appropriate lease rates.

Karsten Brüggemann, Vice President Region Central of the Nordex Group, described the project as demonstrating the potential of modern technology at medium-wind sites. Nordex manufactured and supplied the turbines and hybrid towers, and also managed the construction of the wind farm.

German wind energy statistics 2025
Germany led European wind power growth last year, adding 5.7 GW of new capacity, primarily from onshore expansion (5.2 GW). Türkiye (2.1 GW) and Sweden (1.8 GW) followed, with all new capacity onshore. These figures are from trade association WindEurope’s new report Wind energy in Europe: 2025 Statistics and the outlook for 2026-2030.

The report states that Germany’s wind fleet has a total capacity of 77.6 GW, meeting 28% of national electricity demand. Onshore wind provides 68 GW, while offshore accounts for 9.6 GW.

Germany’s permitting policy has an average approval timeline of 17 months, ahead of the European average. In 2025, regulators approved a record 20.8 GW of new onshore wind capacity.

EU-wide, investors committed about €18.8bn to onshore projects, with German projects attracting over half (with the balance going to France and the UK), reflecting improved permitting and strong auction results, according to the report. The share of wind in the national power mix reached 28% in 2025. This level of generation places Germany among the top European nations for wind energy penetration. Wind met at least a quarter of electricity demand in only five other European countries during the same period: the UK (31%), Sweden (30%), Netherlands (29%), Finland and Portugal (both 25%).

Germany added 503 MW of offshore wind capacity at two wind farms, installing 28 turbines at Borkum Riffgrund 3 (913 MW) and 13 turbines at He Dreiht (960 MW).

Wind generation increased to its highest-ever fraction of 30% (a record 87.1 TWh), up from 29.2% (83.6 TWh) in 2024, due to increases in capacity. Offshore wind generated its highest-ever 17.9% (a record 52 TWh) in 2025, up from 17% (48.8 TWh) in 2024. Onshore wind output was similar to 2024, at 34.8 TWh (down from 35.1 TWh). Wind generated 57.1% of all renewable electricity last year, compared to 58% in 2024.

DESNZ stated that a 5 TW decrease in nuclear output to 35.9 TWh in 2025 (12.3%) meant that the share of generation from low-carbon sources (renewables and nuclear), of 64.8% in 2025 (188.3 TWh), remained similar to 2024. According to the report, the nuclear output was half the level of generation seen in 2015, reflecting the decommissioning of older plants and increased outages across the ageing fleet.

In 2025, solar reached new heights, providing a best-ever 6.9% (20 TWh) of the UK’s electricity last year, an increase from 5.1% (14.6 TWh) in the previous year, as capacity grew and average daily sun hours were higher.

Solar Energy UK said that the rising contribution to the grid from solar and other forms of renewable energy is good news for the consumer, particularly those with time-of-use tariffs. The price of electricity can plunge to zero or less during times of high solar and wind generation.

Generation by fossil fuels increased slightly from 31.9% (91.2 TWh) in 2024 to 32% (93.1 TWh) in 2025. The report states that almost all the fossil fuel generation was from gas, which increased from 87.4 TWh in 2024 to 91.5 TWh in 2025, a 31.5% share of the UK’s electricity generation in 2025 (up from 30.5% in 2024). Coal generation ceased in 2024. Coal production in 2025 rose to 120,000 tonnes, up 12% compared with 2024. This remains at historical low levels despite the increase.

RenewableUK’s CEO Tara Singh said: ‘These figures show renewables are now the backbone of Britain’s power system, supplying most of our electricity for the second year running, with wind doing the heavy lifting.’

Household energy consumption in 2025 was similar to 2024 but remains down on pre-pandemic averages. Higher energy and other prices, combined with record-high annual temperatures in 2022, contributed to this trend. Industrial energy consumption decreased by 6% and is at a consecutive record low. The last time this sector consumed this level of power was in the mid-1980s.

Net import dependency was stable, 43.5% in 2025 compared to 43.8% in 2024. Norway and the US were the principal sources of the UK’s imported energy in 2025.

Norway remained the UK’s largest source of imported natural gas, accounting for nearly 70% of total imports. This is equivalent to 47% of demand. LNG imports increased by 24% in 2025 compared with 2024. The US remained the largest source of LNG in 2025.

Energy production in 4Q2025 decreased by 2% compared to the same quarter in 2024. Production of all primary fuels fell except for wind, solar and hydro.

Total coal demand in 2025 fell to a record low of 0.9mn tonnes, 56% lower than in 2024. This was driven primarily by the end of coal use in electricity generation. The last coal-fired power plant at Ratcliffe-on-Soar closed on 30 September 2024. Coal use has been phased out as electricity generation now favours gas, nuclear and renewables. 

Primary oil production in the mature North Sea basin was up 2.4% on last year’s record low, to 31.4mn tonnes. Primary oil exports were at their lowest levels and at 27.5mn tonnes were down by 2.8% on the previous year. Refinery demand in 2025 was down by 5.1%. Production of petroleum products dropped to a record low of 49.4mn tonnes in 2025. This represents a 5.2% fall in 2024.

Outside of electricity production, gas demand was broadly stable in 2025, down 0.9%. Demand has remained at lows last seen in the early 1990s for the third consecutive year. Industrial gas demand continued to fall, down 7.5%, remaining at levels last seen in the 1970s. Demand by final consumers fell by 2.7% in 2025. Gas production fell by 3.3% to 332 TWh in 2025 compared with 2024.

Total electricity demand in 2025 increased slightly compared to 2024, up 0.2% to 320.2 TWh. Domestic consumption increased from 2024’s record low to 93.5 TWh, up 1.3%. Net imports fell by 11% to 29.7 TWh, compared to the record high in 2024. There was a 37.5% increase in exports to the second-highest figure in the published data series. UK-based generation increased by 1.5% compared to 2024, up to 290.6 TWh. 

The physics that shapes policy
At the heart of the debate lies a simple but powerful reality: efficiency. Heat pumps do not generate heat in the conventional sense. Instead, they move it – extracting ambient warmth from the air or ground using electricity. Their performance is typically measured by a seasonal performance factor (SPF), which commonly ranges between 200% and 400%. In practical terms, that means for every unit of electricity consumed, a heat pump delivers two to four units of usable heat.

Hydrogen boilers, by contrast, operate much like today’s natural gas boilers. They burn fuel to produce heat. But when the hydrogen is ‘green’ – produced by splitting water using electricity via electrolysis – the chain of energy conversions introduce substantial thermal losses. Electricity is first converted into hydrogen, typically losing around a third of the energy in the process. The hydrogen must be compressed, transported or stored, before finally being burned in a boiler that itself is less than 100% efficient.

The result is an unavoidable thermodynamic gap. Heat pumps multiply energy. A hydrogen system degrades it.

That gap, modest at the scale of a single dwelling, becomes enormous when magnified across 29 million UK homes.

A whole-system perspective
The Cranfield study uses an end-state decarbonisation resource analysis (EDRA) framework to explore this difference at the national scale. EDRA does not simulate transition pathways. Instead, it assumes the UK has reached full decarbonisation by 2050 under specified technological configuration, and then calculates the generation capacity, infrastructure, land use and capital associated with that system.

The model assumes that:

• The UK achieves complete energy independence and all energy is produced domestically.
• Baseload electricity demand is met by nuclear power to ensure system stability – a role currently performed by natural gas.
• Wind, solar, hydro, tidal, wave and non-biodegradable waste provide additional zero carbon electricity.
• Offshore wind is the main renewable generation technology, as it delivers the highest power output among all renewables in the UK.
• Hydrogen is produced from surplus renewable electricity and stored in underground salt caverns for use in hard-to-abate sectors and grid balancing.
• Direct electrification dominates in most sectors outside residential heating.
• Waste heat is recovered where feasible.

This deliberately ambitious ‘fully decarbonised’ vision provides a clean comparison between a heat pump scenario in which homes are heated primarily by heat pumps, and a hydrogen scenario in which homes are heated primarily by hydrogen boilers. All other sectors remain identical in both scenarios.

Demand: the hidden multiplier
The most striking difference between the two pathways lies in primary energy demand – the energy contained in raw sources before it is converted into consumable energy.

Compared with today’s fossil fuel-based system, a heat pump share of 82% in homes would reduce the UK’s primary energy demand for domestic heating by more than 50%.

Under a conservative assumption of a national average SPF of 2.54, the reduction is estimated at 53%.

By contrast, replacing gas boilers with hydrogen boilers at the same scale would increase home heating demand by more than 42%, even assuming a relatively high hydrogen boiler efficiency of 94%.

The divergence in electricity demand is even more dramatic. To meet identical heating needs, the hydrogen pathway would require more than three times as much electricity as the heat pump pathway.

In a fully decarbonised energy system – where every kilowatt-hour must be generated by zero carbon sources such as renewables or nuclear power – this multiplier effect directly dictates how much infrastructure must be built. More electricity demand means more wind farms, more nuclear reactors, more grid expansion, more electrolysers and backup power plants, and more land or sea areas devoted to energy production.

Demand reduction at the point of use, therefore, becomes a strategic lever. The technology chosen for home heating does not merely warm buildings; it reshapes the entire energy economy.

Generation capacity: a question of scale
Under the heat pump scenario, assuming onshore wind and solar meet the government targets of 29 GW and 70 GW respectively, the UK would require around 102 GW of offshore wind and 71 GW of nuclear power by 2050.

The implied build rate for offshore wind – about 4 GW/y – is broadly aligned with the current government ambitions for 2030. Nuclear expansion, at nearly 3 GW/y, remains formidable but not inconceivable within a coordinated industry strategy.

Under the hydrogen-dominated scenario, however, the picture shifts dramatically. Offshore wind requirements double to 206 GW. Nuclear capacity rises to 91 GW. Offshore wind deployment would need to exceed 8 GW/y – far beyond historical build rates and the current policy targets.

This issue is not theoretical potential. The UK has world-class offshore wind resources. The question is whether such expansion can be delivered within 25 years while also upgrading grids, training skilled workers, securing supply chains and maintaining public consent. The hydrogen pathway stretches feasibility to its limits.

Infrastructure: beyond the turbines
Generation capacity tells only part of the story. A hydrogen-heavy system demands a parallel build-out of supporting infrastructure. Compared to the heat pump pathway, the hydrogen scenario requires around 50% more total capacity in electrolysers, combined-cycle hydrogen turbines used for backup power and electricity grids, as well as over 27% more large-scale, long-duration hydrogen storage.

The result is a far larger and more complex system. Implementing parallel electricity and hydrogen systems increase engineering complexity and capital exposure. It also heightens delivery risk.

The physical footprint of the energy system expands accordingly. In the hydrogen scenario, offshore wind farm area more than doubles relative to the heat pump pathway. The required sea area approaches 6% of the UK’s total marine territory.

While offshore wind enjoys broad support, scale matters. Marine ecosystems, fisheries, shipping lanes and coastal communities would also feel the impact of a system built at hydrogen scale.

On land, additional substations, electrolysers and hydrogen infrastructure compound the spatial burden.

Capital investment requirements follow the same pattern. For generation assets alone, the hydrogen pathway requires around 60% more capital than the heat pump pathway.

In energy system analysis, large upfront investments are converted into annualised costs, which distribute capital spending across the lifetime of assets to reflect the yearly costs of financing and operating them.

Measured in this way, the hydrogen pathway results in approximately £58bn more in annualised costs each year.

Compared to the current fossil fuel-based system, the heat pump pathway delivers estimated annualised generation cost savings of around 42%. The hydrogen pathway achieves only 7%.

In other words, the economic advantage of heat pumps is nearly six times greater than hydrogen boilers.

These figures do not account for every variable, but the direction is clear: higher energy demand drives higher system cost.

Hydrogen’s strategic role
Importantly, the study does not dismiss hydrogen as irrelevant. On the contrary, the EDRA framework assumes hydrogen is indispensable for aviation and shipping, heavy industrial processes, long-duration energy storage and grid balancing during prolonged low-renewable periods. Hydrogen is essential in hard-to-decarbonise sectors.

The question is not whether hydrogen has a role, but where that role delivers maximum system value. Using hydrogen extensively in home heating consumes scarce zero carbon electricity that could be more effectively deployed elsewhere. Prioritising heat pumps for homes frees up hydrogen for sectors where alternatives are limited.

The Cranfield study’s verdict is clear. If Britain wishes to minimise resource strain, contain costs and improve the feasibility of its 2050 ambition, heat pumps should form the backbone of residential decarbonisation, with hydrogen reserved for the sectors that truly need it.

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: ‘Smart heat pumps: the potential for demand flexibility in the home’. A new study has demonstrated the transformative potential of smart heat pumps, not just as efficient heaters, but as powerful tools to support the management of the UK’s electricity system.
• ‘Hydrogen and ammonia in Europe – from hype to maturity in 2026?’ The long-term outlook for clean hydrogen and ammonia projects in Europe looks promising, but last year saw several setbacks around commercial viability and competition from oil and gas. However, the regulatory environment remains positive.
   

The report estimates cost rises in two scenarios. In the base case scenario, it predicts costs to rise in those three countries by $4.3/MWh. In the high fuel price sensitivity case, costs are forecast to rise by $14.4/MWh in South Korea, $17/MWh in Japan and $22.4/MWh in Italy. The base case assumes geopolitical de-escalation enables fuel price moderation in the latter half of 2026. The high case predicts that current elevated price levels persist through 2026. (For comparison, the report’s high case also predicts UK prices to rise by 27% to $14.3/MWh.)

‘These cost increases represent significant policy challenges, requiring governments and utilities to navigate difficult trade-offs between financial support mechanisms, regulatory interventions and retail tariff adjustments,’ said Allen Wang, Vice President Head of Asia Pacific Power and Renewables Research for Wood Mackenzie.

In the specific cases of coal-importing countries like South Korea, beyond the pain of higher prices, the analysis also points out that the price rises could affect the reliability of its energy system. The authors report: ‘South Korea faces the most acute exposure, with import-linked thermal capacity equivalent to 87% of peak demand.’

In 2024, South Korea’s electricity generation mix was 30% nuclear, 30% coal, 28% gas, 9% renewables, 1% oil, 1% hydropower and 1% other, according to the latest Energy Institute’s Statistical Review of World Energy. The country imported 63.6bn m3 of natural gas (as LNG) in 2024, ranking it third largest globally after China (105.2bn m3) and Japan (89bn m3). In the same year, South Korea consumed the same amount: 63.6bn m3. South Korea’s total coal imports amounted to 3.07 EJ in 2024, ranking it fourth largest in the world after China (11.62 EJ), India (5.3 EJ) and Japan (4.35 EJ). In the same year, South Korea consumed 2.85 EJ of coal.

The Wood Mackenzie report points out that, in contrast to Japan and South Korea, both China and India’s coal-fired power stations can be fed by mostly domestic resources.

The authors continue: ‘The government has already implemented electricity conservation policies and emergency fiscal support to reduce peak demand. The crisis is also accelerating a strategic shift, with energy security now rivalling climate policy as a driver of generation investment decisions.’

In early April, the South Korean Ministry of Climate, Energy and Environment reportedly announced plans to increase the share of power generation from renewables, particularly solar and wind power, to 100 GW by 2030, representing a share of 20%. This will involve shutting down 60 coal-fired power plants by 2040, supporting a transition to hydrogen-based steelmaking, electrifying naptha crackers and facilitating a shift to 40% electric or hydrogen-based vehicles by 2030, according to a Japan Wire/Kyodo News report.

The Wood Mackenzie report also pointed out that other countries, notably the US and Brazil, are essentially immune from the current war, thanks to their own domestic energy resources.
 

‘Geopolitical crises can act as powerful catalysts for long-term system change,’ said Prakash Sharma, Vice President, Scenarios & Technologies at Wood Mackenzie. ‘In this scenario, the world moves decisively towards energy independence, with lasting implications for global fuel demand and trade.’

The scenario sees a conflict which disrupts 15–20% of global oil and LNG supply resulting in a 9% drop in demand in the near term. Although that demand would gradually recover by 2030, the effect of government actions in the interim will increasingly start to take effect.

By 2050, compared to the base case, this scenario sees a 20% rise in coal demand as an alternative fuel. Nuclear generation would rise by 40%, and hydrogen and carbon capture diminish as they are seen as more costly and less secure.

‘Energy independence reduces exposure to external shocks, but it comes at a structural cost premium,’ said Lindsey Entwistle, Principal Analyst, Scenarios & Technologies. ‘This creates new competitiveness challenges for energy-intensive industries, while advantaging more self-sufficient regions.’

Near-term carbon increases are offset by increased electrification and nuclear deployment, meaning that the scenario aligns in terms of global warming with the Wood Mackenzie base case of about 2.6°C rise in global temperatures.

The College also operates three other facilities around the city and was founded in 2012 as part of the merger of Edinburgh’s Jewel and Esk, Telford and Stevenson colleges.

Vital Energi’s Regional Manager, Kieran Walsh, commented: ‘Normally, organisations decarbonise in phases, with several smaller projects, but Edinburgh College has been able to electrify their heating system in one single phase.’  

In addition to eliminating reliance on gas in a single phase, the project serves as an educational resource for the College’s Engineering, Renewables and Energy Efficiency Training Centre, where students can study the new low-carbon system.

Building on Edinburgh College’s example at the campus level, a parallel ambition for large-scale electrification is now being applied to the residential sector in Wales. GTC has secured a contract with Barratt Redrow to deliver energy systems for the Cosmeston Farm development in Penarth. The project, comprising 576 homes, is said to be the UK’s largest net zero carbon housing development and a major residential sustainability project in Europe.  

The site will use a smart home energy system that reportedly integrates networked ground-source heat pumps, solar photovoltaics and battery storage. GTC states that this whole-system approach enables lower energy bills through smart optimisation and grid flexibility earnings. Cardiff University will independently verify the site’s real-world performance.

John Marsh, Chief Innovation Officer at GTC, says the development showcases the ‘power of bringing together proven technologies and investment to create affordable, zero-carbon, smart homes’.

Oliver Novakovic, Technical and Innovation Director at Barratt Redrow, said: ‘Cosmeston represents a transformational step in how we design and build the next generation of zero-carbon communities. This project shows what is possible when industry partners collaborate to deliver homes that are not only beautifully designed, but future ready.’  

Finally, a new white paper from trade association BSRIA recommends making building performance testing a core requirement for all domestic retrofit projects to ensure intended carbon and energy savings. The report, Retrofit testing for warm homes, notes that reliance on assumptions and visual inspections often results in non-compliance and costly remediation. It cites failures in previous large-scale schemes, with tens of thousands of installations requiring remediation at a cost of hundreds of millions of pounds. BSRIA states that before-and-after testing is essential to restoring trust and ensuring quality in the UK’s £15bn Warm Homes Plan.

The report identifies five key actions:  

• Introduce before-and-after testing requirements, particularly for government-funded and social housing retrofit projects, to ensure transparency, compliance and public confidence.  
• Reinforce ventilation testing, including more explicit requirements for registered building inspectors to ensure tests have been completed by a competent person.  
• Upskill retrofit assessors, coordinators, designers and installers in testing methodologies to improve understanding and adoption.  
• Raise tester competence, supported by appropriate training, accreditation and equipment calibration.  
• Mandate data for performance, enabling continuous improvement and helping close the performance gap.  

The report concludes that targeted testing is a cost-effective way to protect public investment and ensure healthy, efficient homes. 

The report highlights regional disparities in the overall renewables numbers. In 2025, Asia accounted for 74.2% of new capacity, bringing total capacity to 2,891 GW, or 56.1% of the global total. Most of this growth occurred in China (440.1 GW). Europe expanded by 76.8 GW (9%), with Germany adding over 20.5 GW. Ukraine saw a decline of more than 7.5 GW in 2024 and no change in 2025. North America grew by 42.1 GW (7.4%), led by the US. Africa achieved record growth, adding 11.3 GW (15.9%), mainly from Ethiopia, South Africa and Egypt. Oceania increased by 6.1 GW (8.6%), largely in Australia. Central America and the Caribbean expanded by 9.1% (1.8 GW), the highest since 2016. The Middle East recorded its highest growth rate at 28.9% (12.7 GW), with Saudi Arabia leading this expansion.

Solar photovoltaic power accounted for nearly all solar capacity growth, with 510.3 GW added in 2025. Asia has more than doubled its installed solar power capacity since 2022, adding 317.1 GW in 2024 and 371.2 GW in 2025. However, the largest capacity increases occurred in China (315.1 GW) and India (37 GW), followed by South Korea (3.7 GW). Outside Asia, the US added 34 GW of solar capacity in 2025 – a 19.2% increase over 2024 – followed by Germany (15.1 GW) and Brazil (11.6 GW).

Wind energy additions reached a record high of 158.7 GW in 2025 – 14% more than in the previous year, according to the report. China led the expansion, accounting for nearly three-quarters of the total capacity added (119.4 GW), while India added 6.3 GW. Other countries with significant capacity growth included the US, Germany, Brazil, Türkiye and France. Offshore wind accounted for about 1.8% of total renewable power capacity and 7.1% of total wind capacity.

Renewable hydropower capacity grew by 18.4 GW in 2025. According to IRENA, this was 2.5 times the increase seen in 2024, with 96% of the growth coming from China. Other countries with increases in hydro over 0.5 GW included Ethiopia, India, Tanzania, Bhutan, Vietnam, Canada, Austria, Indonesia and Nepal.

Bioenergy capacity grew by 3.4 GW in 2025. IRENA shared that this growth was led by Japan, which expanded its bioenergy capacity by 1.1 GW – more than double the 2024 additions (0.5 GW). China followed with a bioenergy expansion of 0.8 GW. Other countries with major increases were Brazil (0.6 GW), Chile (0.2 GW) and Belgium (0.1 GW).

Geothermal capacity grew at a similar rate to the previous year, adding 0.3 GW in 2025. IRENA indicated that the Philippines and Indonesia each contributed 0.1 GW, followed by Germany, Türkiye and Japan.

Commenting on the findings, IRENA Director-General, Francesco La Camera said: ‘In the midst of uncertain times, renewable energy remains consistent and steadfast in its expansion. This not only indicates market preference but also makes a strong case for renewable energy resilience with brutal clarity. A more decentralised energy system, with a growing share of renewables and more market players, is structurally more resilient. Countries that invested in the energy transition are weathering this crisis with less economic damage, as they boost energy security, resilience and competitiveness.’

While renewable capacity reaches new highs, energy think tank Ember warns that grid constraints threaten Europe’s energy transition. The Crossed Wires report highlights that limited grid readiness has become a decisive barrier to the continent’s energy security and competitiveness goals.  

In many European countries, large volumes of renewables remain stuck in connection queues, manufacturers face multi-year delays in expanding production, and data centre developers relocate to regions with more secure and faster connections. Rising costs to manage grid congestion, ultimately borne by consumers, add further pressure. Additionally, the large volume of projects already in the queue for a grid connection agreement means new applicants are likely to face delays. Almost 700 GW of renewables are stuck in the grid connection queue across the eight reporting countries, highlighting the continued scale of demand for grid access.

Connection queues are compounding the issue. The report shows that, of the 13 countries publishing grid capacity data for distribution networks, six have insufficient headroom to accommodate expected growth in small-scale solar. This puts at least 16 GW of rooftop solar planned by 2030 at risk, potentially affecting up to 1.5 million households.

Ember lead author, Elisabeth Cremona, says that grid readiness should now be considered an indicator of economic readiness rather than a technical afterthought. The report warns that without rapid intervention, the continent’s security and competitiveness objectives are at risk.

Read the full IRENA report: Renewable capacity statistics 2026. 

These dynamics are all explored in Arup’s new Gridunlocked macroeconomic study, developed in collaboration with Cambridge Econometrics, which estimates that an additional £34bn invested in the grid over the next 15 years could unlock £194bn in additional gross value added (GVA) for the economy by 2040.

The economic opportunity 
The scale of potential value unlocked through ambitious investment becomes clear when alternative investment scenarios are compared. A supercharged pathway, which accelerates investment in line with the UK’s net zero trajectory, will deliver a 4:1 on investment by 2040.The benefits are not confined to the energy system itself, most economic uplift would flow into the services economy, particularly technology, finance and education, together contributing around £95bn in additional GVA.

There are also significant knock-on-effects elsewhere, such as increased demand for property and development activity, which would add a further £33bn GVA, and construction activity adding £20bn GVA. The electricity sector itself would see a similar uplift, and growth is spread more broadly across manufacturing, agriculture and water. Taken together, the message is straightforward – sustained investment in the grid acts as a foundation for wider, long-term economic growth, rather than representing an isolated infrastructure cost.

The cost of inaction is already visible. In 2024 alone, £1.3bn of renewable energy was curtailed because the network was unable to absorb available clean power. At the same time, the UK’s dependence on imported energy rose to 43.8%, increasing exposure to rising price volatility and geopolitical shocks as seen with the recent conflict between the US and Iran. These indicators paint a stark picture of the cost of inaction. Without sufficient grid capacity, the UK risks constraining domestic generation, slowing down electrification and undermining long-term productivity.

Unlocking new jobs
Grid investment is also closely tied to employment. Under the more ambitious, supercharged pathway, the UK could also support an average of 92,000 additional jobs each year, with 68,000 of those being in service sectors. The construction sector could also gain around 14,000 jobs, with property gaining 6,000 annually, as well as thousands more in industry, manufacturing, power and agriculture.

These are roles that will define the next phase of the transition, including electricians, offshore technicians and energy specialists. Many are highly skilled and aligned with the UK government’s Clean Energy Jobs Plan, representing long-term career opportunities as opposed to short-term project surges.

Without sufficient grid capacity, the UK risks constraining domestic generation, slowing down electrification and undermining long-term productivity.
 

Why delivery matters
Investment alone will not unlock the full benefits outlined in the study. The UK needs a cohesive, programmatic strategy for planning and implementing projects across generation, storage, transmission, distribution and demand side flexibility. This type of coordination can lower overall system costs and enhance reliability by leveraging greater operational and economic synergies.

That being said, delivering comprehensive system transformation involves complex interdependencies. Policy, finance, technical design, supply chains, environmental and community considerations all interact with each other and the UK will need a delivery model capable of working across these interfaces rather than through siloed projects. Without proper alignment, the UK could face slower implementation, increased costs and missed opportunities.

There are positive signs, as seen with the National Grid’s Great Grid Partnership, which demonstrates a programmatic approach by using standardised design and modern methods of construction to reduce costs and accelerate delivery. However, the complexity of the challenge means this kind of coordinated delivery needs to become more widespread. It should extend across consenting, environmental assessment, supply chain planning and community engagement, which is crucial. Early, transparent engagement that builds understanding and trust can shorten consenting times and improve outcomes. Communities will be essential partners in this transition and treating them as such will be critical to delivering at the scale and pace required.

The evidence is clear that if we invest wisely, design boldly and deliver with purpose, the electricity grid can serve as the foundation for a more secure, more affordable and cleaner energy future. The next few years will be critical, and the choices we make now – regarding coordination, ambition and delivery – will shape whether the UK achieves the full economic and social benefits of electrification.  

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 changing the UK’s voltage limit matters’. Without the managed reform of voltage standards across distribution networks, the UK’s reform of its power grid, which is essential to accommodate more low-carbon generation and other low-carbon technologies, faces unavoidable technical barriers, says Mark Dunk, Head of Engineering at the UK Energy Networks Association.
• ‘Powering the future: the need for smarter grid connections for EV charging’. Find out why the UK should consider stations with batteries and on-site power generation at scale for rolling out electric vehicle charging.

In 2025, it produced 3.05bn m³, making it the largest CBM-producing asset in China to date. A second phase of expansion is currently under way and is expected to add 1.5bn m³ of annual capacity.

This project is one of several key CBM developments in China, where national resources are estimated to exceed 40tn m³. Shanxi, the country’s leading CBM-producing region, accounts for over 80% of national output, with production reaching 13.43bn m³ in 2024.

CBM is different to other traditional gas reservoirs, as methane is held within the coal seams by adsorption. Extraction involves drilling down into coal seams and pumping out the groundwater. The resultant drop in pressure is sufficient for methane held within the coal to be released.  

China has set targets of 5tn m³ in proven CBM reserves and annual production of 40–50bn m³ by 2035 – however, achieving this scale of development presents several challenges. Coal seams with depths exceeding 1,500 metres are classified as deep CBM, where elevated formation pressures, temperatures and in-situ stress complicate permeability, gas desorption and well productivity, increasing both technical risk and development costs.

Meanwhile, infrastructure constraints, including pipeline connectivity and gas processing capacity, further affect project economics, while market access remains uneven across regions in China.  

Industry participants have called for stronger policy support to address these barriers. In 2025, Zhang Qingsheng, Executive Director of Sinopec Zhongyuan Oilfield under China Petroleum and Chemical Corporation, highlighted the need for increased investment, fiscal incentives and streamlined approvals, alongside continued advances in extraction technology to improve recovery rates.

Regulators have also moved to tighten methane emission rules. In April 2025, a revised Coalbed Methane Emission Standard lowered the methane concentration threshold for mandatory capture and utilisation from 30% to 8%. This revision, the first since 2008, aligns with a broader national action plan on methane emission control and is expected to drive additional investment in collection and processing infrastructure.

The conflict has significantly impeded energy trade flows through the Strait of Hormuz, creating the largest supply disruption in the history of the global oil market. Global supply of LNG has also been reduced by around 20% as a result of the situation.

The tracker groups actions into two main categories: measures to conserve energy and measures to support consumers. As new policies are announced and the situation evolves, it will offer an up-to-date view of how countries are addressing the crisis, the IEA says.  

The IEA has also published a menu of demand-side measures that governments, businesses and households can take to shelter consumers from oil price pressures and support energy security. In line with the IEA’s core mandate to safeguard energy security, member countries unanimously agreed on 11 March to carry out the largest-ever coordinated release of emergency oil stocks, making 400mn barrels of oil available to the market to help stabilise supply.

National implications: energy as the foundation of industrial strategy
At the national level, governments increasingly recognise that energy infrastructure and industrial competitiveness are inseparable. Energy-intensive industries – including chemicals, refining, metals, advanced manufacturing, data centres and transport fuels – require reliable, competitively priced and increasingly low-carbon energy. At the same time, many of the technologies underpinning the energy transition – batteries, hydrogen systems, electrolysers, renewable components and digital energy systems – are themselves becoming strategic industrial sectors.

As a result, energy systems are increasingly being designed not merely to supply power, but to anchor industrial ecosystems. Three policy trends are becoming evident. First, governments are increasingly aligning energy policy with industrial policy. Rather than relying solely on market forces to determine industrial location, many countries are actively shaping energy infrastructure to attract and retain strategic industries. This approach is visible in initiatives such as industrial decarbonisation clusters, hydrogen valleys, clean energy manufacturing zones and battery supply-chain ecosystems. These clusters enable industries to share infrastructure, access lower-carbon energy sources and reduce overall system costs.

Second, nations are investing heavily in domestic capability across critical energy technologies and supply chains. Control over battery manufacturing, renewable equipment production, grid technologies and critical mineral processing is increasingly viewed as strategically important. This reflects the growing significance of controllability within national energy systems.

Third, governments are strengthening system resilience by building more distributed and flexible energy networks. This includes expanding storage capacity, reinforcing electricity grids, encouraging distributed generation and strengthening strategic energy reserves.

Taken together, these policies are gradually transforming energy systems from passive infrastructure into active instruments of industrial strategy.

Regional implications: the rise of integrated industrial ecosystems
While energy systems remain nationally governed, their most effective development increasingly occurs at the regional level. Regions, whether within a country or across neighbouring states, often possess complementary assets: ports, logistics infrastructure, renewable resources, industrial capacity and skilled workforces. When these assets are coordinated, they can form integrated industrial ecosystems capable of attracting global investment.

This is particularly evident in the development of low-carbon industrial clusters. Such clusters typically combine multiple elements, such as renewable electricity generation, energy storage systems, hydrogen production and derivatives, carbon capture and storage infrastructure, circular materials systems, digital energy optimisation and shared logistics and port infrastructure. By integrating these components, regions can offer industries a fully decarbonised operating environment, significantly lowering the barriers to investment.

These ecosystems deliver several advantages aligned with the new energy trilemma. They enhance resilience by distributing energy supply across multiple sources and technologies. They increase diversification by integrating different energy vectors – electricity, hydrogen, fuels and materials – within a single system. They strengthen controllability by embedding energy production, storage and consumption within coordinated regional infrastructure networks. For regions with strong industrial heritage – such as petrochemical zones, steel corridors or port-based logistics hubs – this approach offers a pathway to industrial renewal rather than decline. Legacy infrastructure, skilled workforces and established supply chains can be repurposed to support the development of next-generation low-carbon industries.

Southeast Asia: a region of strategic opportunity
These dynamics are particularly relevant in Southeast Asia, where energy demand continues to grow rapidly while industrial development remains a central economic priority. The region faces a complex balancing act. On the one hand, the economies of Association of South-East Asian Nations (ASEAN) member countries must expand energy supply to support continued economic growth. On the other, they must progressively reduce emissions while maintaining competitiveness within global supply chains increasingly shaped by carbon standards and sustainability requirements.

The principles of the new energy trilemma provide a useful framework for navigating this challenge. Resilience in Southeast Asia will require strengthening regional energy infrastructure, including grid interconnections, storage capacity and distributed generation. The development of the ASEAN Power Grid (APG) could significantly enhance regional system stability while allowing countries to balance different renewable resources across borders.

Diversification will require expanding energy sources beyond traditional hydrocarbons while maintaining transitional fuels such as natural gas during the shift toward renewables. The region also has significant opportunities to develop supply chains around bioenergy, sustainable aviation fuels, hydrogen derivatives and battery materials. Controllability will increasingly depend on regional cooperation to build domestic and regional capability in energy technologies and infrastructure.

Rather than relying solely on imported technologies, Southeast Asia has the opportunity to develop its own energy innovation ecosystems, linking universities, industrial partners and investment platforms.

Such an approach could position the region as a global hub for next-generation industrial energy systems. These dynamics are particularly relevant in Southeast Asia, where energy demand continues to grow rapidly while industrial development remains a central economic priority.

Global implications: the rewiring of trade and industrial geography
At the global level, the emergence of the new energy trilemma is contributing to a broader reconfiguration of trade and industrial geography. Over the past three decades, globalisation has encouraged highly optimised supply chains centred on cost efficiency and scale. Production was often geographically separated from energy supply, raw materials and end markets.

That model is now being reconsidered. Energy intensity, carbon footprint, supply chain resilience and geopolitical alignment are becoming increasingly important factors in determining where industries locate. This is likely to accelerate the development of new industrial corridors and energy ecosystems around the world. Examples include clean energy manufacturing zones in North America and Europe, hydrogen export corridors linking renewable-rich regions with industrial demand centres, battery supply-chain clusters integrating mining, refining and manufacturing and port-based energy hubs combining shipping fuels, storage and industrial processing.

These developments suggest that the unit of economic competition is evolving. Rather than individual factories or corporations competing in isolation, future competitiveness may increasingly depend on the strength of integrated industrial ecosystems. Regions capable of combining reliable energy supply, low-carbon infrastructure, advanced logistics and supportive policy frameworks will become preferred destinations for global investment.

A new strategic map for industry and energy
The energy transition is often described primarily as a technological transformation. In reality, it is equally a geopolitical and economic restructuring. As nations redesign their energy systems to enhance resilience, diversify supply chains and maintain strategic control, they are also reshaping industrial policy and global trade patterns. The emerging landscape will likely be characterised by clusters of integrated industrial ecosystems, linked through regional energy networks and strategic trade corridors.

In this context, the new energy trilemma provides more than an energy policy framework. It offers a strategic lens through which governments, investors and industries can understand the future geography of economic development. Those regions that successfully align energy systems, industrial ecosystems and trade strategy will be best positioned to capture the opportunities emerging from the next phase of the global energy transition.

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.

In the first of this two-part comment – ‘The new energy trilemma – why national security is reshaping the global energy transition’, published on 18 March 2026 – Peter Godfrey reflects on what was said at International Energy Week 2026 and how the traditional energy trilemma is evolving into a new framework.

• Further reading: ‘Why global logistics cannot afford to ignore Gulf instability.’ With the push for battery-electric road transport transition solutions, alternative sustainable and waste-based fuels are underestimated, despite their bridging and complementary advantages, argues Matthias Maedge, Vice President, Commercial Road Transport Decarbonisation, at mobility and payment solutions company Eurowag.
• ‘Tomorrow’s benefits and today’s problems: CEOs agree to disagree at International Energy Week’. Discover how senior leaders of oil and gas majors and utilities differ in their perspectives about the importance of the transition away from oil and gas, and the relationship between the transition and energy security. 
   

Some 30 years ago, the European Bank of Reconstruction and Development (EBRD) mobilised to facilitate financing of a cover, called the New Safe Confinement (NSC), over the damaged reactor to protect it from the elements and prevent the ingress of rainwater. The arch, 110 metres high, 257 metres wide and 162 metres long, was slid into place in 2016 and commissioned in 2019.

It was designed, built and installed by French construction contractors Bouygues Travaux Publics and Vinci Construction Grands Projets. The project cost about €2bn.

In February 2025, a Russian drone strike tore a 15 m2 hole in the structure. About 200 m2 of panels were damaged, as was an internal membrane that made the structure airtight. In addition, the internal climate control and internal crane systems were affected.  

The damage prevents the shelter from doing its job of containing radiation and facilitating decommissioning of the reactor.

EBRD said: ‘Failure to restore the NSC to its original standard of confinement and ventilation before 2030 would seriously jeopardise its 100-year design life because of corrosion, undermining decades of international investment and creating environmental and safety risks.’

EBRD added that repairs could cost at least €500mn, not just to patch the hole but also deal with corrosion of the internal steel arch within the containment structure.  

The project is expected to proceed in three phases: research and investigation, engineering strategy, and detailed engineering and procurement.  

Donors to the fund, the International Chornobyl Cooperation Account (ICCA), which has also funded waste processing work at the site, include the European Union, France, Norway, UK, Canada, Germany, Taiwan Business-EBRD Technical Cooperation Fund, Belgium and Italy.  

The EBRD-managed ICCA currently holds some €70mn in donor funds. 

In terms of operational data, the project used telematics data captured from 160 test vehicles at more than 20 hauliers to draw some conclusions about operations.  

First, eHGVs were found to perform in the same way as diesels, in one respect at least. The study found that heavier HGVs of all types are less fuel-efficient than lighter ones. It said: ‘The median 35–40 tonne eHGV is 31% less efficient than a 20–25 tonne eHGV, while a 35–40 tonne diesel HGV is 36% less efficient than a 20–25 tonne diesel HGV.’ However, trip efficiencies varied a lot, because weight wasn’t the only factor, and there were few eHGVs at the heaviest weight classes.

Second, the slowest vehicles were the least efficient per kilometre driven, which the authors speculate being due to start-stop driving, together with the greater effect of heating, cooling and other ancillary loads over the longer periods of time it takes to complete each kilometre.

This is significant for hauliers, the authors say, because of range limits. ‘Weight and speed both have a strong influence on efficiency and need to be considered in route planning. This is a change from diesel operations, where similar patterns occur, but range on a tank of fuel is rarely a limiting factor.’  

‘While the overall pattern of efficiency for eHGVs is similar to diesels, the degree of variation is not. eHGVs are relatively more efficient than diesels at lower speeds (for example where there are many stops). Operators need to consider their specific route types, using their telematics data to understand range capabilities and allocate vehicles appropriately. Using a fixed range to plan routes is likely to result in vehicles being underutilised.’

The report has also found that winter conditions reduce the energy efficiency of eHGVs.

There was a more unexpected finding. HGVs are used much more heavily than passenger cars, and their larger batteries generally require more time to charge. However, the report’s authors found that those challenges can be overcome. ‘In most cases, existing HGV schedules potentially have enough slack time to allow eHGVs to charge and still complete the same duties. This does, however, require eHGV charging infrastructure to be made available at (or near to) locations where eHGVs dwell – for example at destinations and wherever drivers take a break, as well as at depots.’

The extra capital cost of eHGVs compared to diesel versions (two to three times greater) is a significant barrier to adoption. The report found a break-even in total cost of ownership (capital + operational costs) between eHGVs and diesel trucks after four years, assuming 80% depot charging at 20 p/kWh and 20% public charging 50 p/kWh, plus the £81,000 zero emission truck grant announced by the UK government in March (new EV vans get £5,000). In that case, after eight years the cost benefit of eHGVs reaches £94,000. The report goes on to explore three affordability scenarios in far more depth. One common factor is that the greater the distances, the more savings.  

The authors observe: ‘Financial viability varies less by route and more by how the vehicle is operated. To make eHGVs more viable it’s important that operators try to achieve higher mileages, lower electricity costs, lower infrastructure costs through higher charger utilisation, and use public charging where needed to extend journey lengths.’

A cost-benefit calculator is available and has been updated.  

Twelve depot and seven public vehicle charging sites are due to be set up by the end of the year. Development of public charging sites has been delayed. Only two of seven public charging sites opened in January 2026.

The report blamed the delays on ‘extended planning processes, significant grid reinforcement works negotiations and protracted with distribution network operators (DNOs)’. It continued: ‘These challenges are typical of first-of-a-kind infrastructure and have generated learning that will reduce risk and timescales for future delivery.’

A further delay to one site was caused by thieves cutting the 10 charging cables to sell the copper wire as scrap.  

These delays meant that most charging in the trial was done at the depot, which limited the range of the truck fleets and prevented some of the researchers’ ideas being tested.

The project is publicly funded and run by electric charging provider Gridserve and Hitachi ZeroCarbon, and supported by hauliers, truck manufacturers, charging locations and truck financiers.  

The trial is funded to run for another five years under the management of vehicle engineering consultant Ricardo.

Europe currently imports 99% of its lithium and demand for graphite is projected to increase 25-fold by 2040, according to Tozero, which expects a global supply gap exceeding 33% starting in 2035.

‘Europe doesn’t yet have the critical raw materials it needs to build and scale its own energy transition and battery industry,’ said Sarah Fleischer, Co-Founder and CEO of Tozero. ‘In just under four years, Tozero has gone from lab-scale experiments to industrial operations and we’re consistently proving that recycling isn’t just a pilot project – it can be delivered at a level capable of giving Europe a homegrown, circular supply of critical materials its future runs on.’

The project aligns with the EU Critical Raw Materials Act, which mandates that 25% of the EU’s annual consumption of strategic raw materials come from domestic recycling by 2030. 

On the use of Ming Yang smart energy turbines in the UK, Minister of State for Energy Michael Shanks said: ‘After careful consideration, government’s view is that we cannot support the use of them in UK offshore wind projects.’  

‘We will always act to protect our national security, and we are committed to strengthening and prioritising resilient and sustainable offshore wind supply chains,’ he continued.

The decision came after a lengthy deliberation process, with UK Trade Minister Chris Bryant saying in January that the government had to be sure the investment in the port was ‘safe and secure’. Bryant told the BBC’s Radio Scotland Breakfast programme the UK had to be ‘clear eyed’ about its relationship with China and challenge it on issues such as human rights.

Liam Byrne, Chair of the Business and Trade Committee, welcomed the move, saying the UK could not risk ‘new and unwise dependencies’ in its energy supply chain in an increasingly unstable world.

Scotland’s First Minister John Swinney said he was ‘deeply disappointed’ by the decision, adding: ‘At the very moment we should be building clean energy, they are sabotaging Scotland’s industrial future.’

A spokesperson for Ming Yang said the company would continue to engage with the UK government, including on national security concerns, and remained committed to supporting the UK’s ambition to become a clean energy superpower.

Vestas sets out plans to build nacelle factory in Scotland

Meanwhile, Vestas has announced plans to build a nacelle and hub factory in Scotland, representing a capital investment of more than €250mn. The site would produce nacelles and hubs for its flagship offshore wind turbine, the V236-15.0 MW, and create around 500 skilled jobs.

The move follows record-breaking AR7 auction results in January 2026, a growing UK offshore wind order book, and discussions between Vestas, the UK government and the Scottish government on developing and co-investing in the project.

A final investment decision is contingent on Vestas securing sufficient UK-based orders in AR7 and AR8. Subject to those outcomes and the planning process, production could begin in 2029 or 2030, it said. 

The deal transitions the project from early-stage and bridge funding to a long-term capital structure, highlighting, it said, growing lender confidence in EGS as a utility-scale energy source.

Located in Beaver County, Cape Station is expected to begin delivering power in 2026, reaching around 100 MW by early 2027, with plans to scale to 500 MW. The project is fully contracted under power purchase agreements (PPAs) with Southern California Edison, Shell Energy and community choice aggregators.

The financing package includes a $309mn construction-to-term loan, a $6mn tax credit bridge loan and a $51mn letter of credit facility. Proceeds will fund remaining construction costs for the project’s first phase and support credit obligations linked to its PPAs.

Project InnerSpace and SPE launch initiative to unlock geothermal investment

Geothermal nonprofit company Project InnerSpace has announced a partnership with the Society of Petroleum Engineers (SPE) to develop a global standard aimed at accelerating investment in geothermal energy.

The Geothermal Resource Management System (GRMS) will be modelled on the oil and gas industry’s widely used Petroleum Resources Management System (PRMS), enabling geothermal projects to be evaluated using an established financial and technical framework.

‘The financial community already understands how to speak the language of large-scale subsurface energy development through oil and gas. We hope that geothermal resources will soon be included in that same framework,’ said Simon Seaton, Chief Executive Officer, SPE. He added that GRMS is a ‘foundational step’ towards building the market structures needed to scale geothermal development globally.

The initiative follows a two-year analysis by Project InnerSpace involving experts across finance, energy, insurance and policy. It identified the lack of a standardised system for valuing geothermal resources as the primary barrier to large-scale investment.

By aligning geothermal with PRMS, Project InnerSpace says the framework could significantly reduce costs and delays across the sector. Standardised contracts enabled by GRMS are expected to cut legal and transaction costs by 40–60% and shorten deal timelines by up to five months. That could translate into more than $100mn in annual legal savings for the geothermal industry within four years.

An initial version of the GRMS framework is expected to be delivered within one year.

Arriving at CERAWeek less than two months later, this comment felt prophetic. In that time the world has been plunged into the largest energy crisis for decades, impacting all the Gulf states and interrupting global energy flows following the US/Israeli attack on Iran and the inevitable digging in and lashing out of Iran.  

I have been to CERAWeek many times as Upstream Director of Shell and Galp CEO, but this year my badge said President of the Energy Institute. I was amazed at the how the conference had grown (10,000 attendees) and also the consistent high quality of the speakers.  

The conference had been built around the theme of convergence and competition. There was a distinctly US flavour, with an upbeat mood, celebrating US energy dominance, anticipating a resurgence of Venezuelan output, but also acknowledgment of the massive growth of AI and the impact data centres are having on prices, the grid and generation.  

This certainly was a strong theme, and as US Secretary of the Interior Doug Burgum called it, winning the ‘AI arms race’ was central to US ambitions, where access to abundant, affordable energy was fundamental to AI. Chris Wright, US Secretary for Energy, talked up the strength of US oil and gas production, pointing to the record levels of supply to keep the lights on through the massive Fern winter storm in January. When challenged, the two Secretaries dismissed the current energy market crisis as temporary.  

The CEOs who spoke included Shell’s Wael Sawan and Patrick Pouyanne of TotalEnergies. They were more realistic around the depth of the crisis. Their focus was first and foremost on the safety of their people. Sawan updated the audience on the damage to the Pearl gas-to-liquids (GTL) plan in Qatar, where one of the two trains was damaged by an Iranian drone, which will take 1–2 years to repair. I spent a decade of my life leading the development of that project, handing over my role to Wael Sawan to lead operations in 2012, so for both of us, the attack was personal.  

While media reports have tended to focus predominantly on constrained oil production through the Strait of Hormuz, it was pointed out that whereas this may be just 10% of global oil production, it is however 20% of internationally traded oil. The lack of LNG from Qatar and the United Arab Emirates (UAE) also represents 20% of global flows.   

Secondary measures and impacts like the ban on oil product exports from China has magnified the crisis in jet fuel and diesel; the former is being sold at $250/b in some places. Shortages also impact products like fertiliser feedstocks, or even helium: 40% of the world supply, which is essential for computer chip manufacture, comes from Qatar.   

The CEOs reflected that the first impact we will see is on prices, but physical flows and shortages which have started in Asia will swing to Europe in the coming months. 

Another dominant theme was around the damaging impact of regulation on impeding energy flows. The US congratulated itself on how approvals had been sped up, but there was universal criticism of European regulation. The blame was put firmly at the door of the European Union (EU) in Brussels. As Pouyanne reflected, if you set up an organisation whose sole purpose is to regulate, you will get regulation! Even Katherina Reiche, Germany’s Minister for Economic Affairs and Energy, joined the throng criticising the EU. She was determined to drive down energy prices in Germany through deregulation.   

Geopolitical polarisation 

Often it is what is not said that speaks more than what is said. The complete absence of Chinese companies, or any discussion about the progress China has made in creating an advanced electrostate was extraordinary. It shows how geopolitically polarised discussions on energy are becoming between the East and West.   

In addition, there was hardly any mention of climate change, and any sense that energy leaders need to urgently address the impact of fossil fuels on the climate. Climate change is clearly on the back burner versus energy access and affordability. This is disturbing.  

The complete absence of Chinese companies [at CERAWeek], or any discussion about the progress China has made in creating an advanced electrostate… shows how geopolitically polarised discussions on energy are becoming between the East and West. 

What lies ahead 

As for what happens in the coming months, amongst delegates there was near universal despair for a quick resolution to hostilities in the Gulf. While one may think oil and gas executives would be relishing the higher prices, the inevitable demand destruction and governments’ imposition of windfall taxes would make any celebration short lived.   

The Middle East experts universally thought Iran now held a strong hand. The most prescient relevant quote went like this: ‘If Iran doesn’t lose, it wins, and if the US doesn’t win, it loses,’ meaning any kind of stalemate favours the Iranians.  

A high point for me was listening to Venezuelan opposition politician Maria Corina Machado (who was awarded the 2025 Nobel Peace Prize). She provided a very compelling story of her plans if she gets voted in as President. She outlined a new petroleum law, with attractive fiscal terms and legal protection, with equity participation. Her plan is that state oil company PDVSA would not be too involved, as she wanted the development of oil and gas in international hands. The prospect for western international oil companies, which are short of reserves, being given access to 300bn barrels of resources is game changing for them.  

On my way to the airport back home, I passed service stations advertising diesel prices above $5/g (£1/l); [in the UK diesel prices are nearing £1.80/l]. This could lead quickly to public dissatisfaction with the consequences of war in the US. It is hard to understand how the political leaders will be able to continue to normalise the energy world. The future surely is unpredictable!    

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: ‘Years of repairs loom over Middle East oil and gas facilities after only weeks of hostilities’. Damage to oil and gas facilities from the Iran-US/Israel war will take years to repair and cost billions, according to early reports from market analysts Rystad Energy and Wood Mackenzie. 
• ‘The new energy trilemma – why national security is reshaping the global energy transition’. The energy transition is unfolding in a complex strategic environment, defined by geopolitical competition, supply chain fragmentation, technological rivalry and climate-related disruption.

So, let’s analyse this challenge, using the familiar SWOT (strengths, weaknesses, opportunities and threats) analysis methodology.  

Strengths: institutional depth and financial firepower 

• The UK retains significant structural advantages. 
• Carbon budgets and legally binding targets provide rare long-term policy clarity.  
• British engineering and contracting firms are internationally competitive in offshore wind, grid modernisation and complex infrastructure management. 
• Capital markets remain deep and green finance instruments are well developed. 
• The industrial base exists.  
• Investor appetite exists.  

Conclusion: The constraint lies in scaling skilled execution.  

Weaknesses: the demographic cliff 

• The retirement of nearly one-third of experienced engineers, project managers and technical specialists represents a structural contraction in institutional knowledge. 
• Without accelerated recruitment, retraining and productivity gains, capacity could fall towards 70% of current levels while project demand expands. 
• Training pipelines remain fragmented.  
• Apprenticeship growth has not yet reached the scale required.  
• Mid-career transitions into energy are possible, but insufficiently structured. 
• Knowledge transfer from senior engineers to younger cohorts is inconsistent.  
• Contracting overseas labour may be costly, hazardous and politically sensitive. 

Conclusion: There is risk of an execution bottleneck, embedded within a growth agenda.  

Opportunities: transforming constraint into economic leverage 

Handled strategically, this skills challenge potentially becomes a catalyst.  

• A coordinated national energy skills compact – aligning government, contractors, further education institutions and labour representatives could synchronise workforce forecasting with infrastructure pipelines, reducing mismatch risk to improve regional allocation. 
• Structured reskilling pathways from adjacent sectors – oil and gas, heavy manufacturing, defence and transport infrastructure – offer a fast route to competency expansion, accessing technical skills which are transferable but currently lacking in certification speed and coordinated incentives. 
• Targeted immigration routes for high voltage engineers, nuclear specialists and offshore project managers might stabilise short-term skills gaps until domestic capacity scales.  
• Digital productivity gains matter. AI-enabled scheduling, modular construction, advanced simulation and digital twins have the potential to increase output per worker. Even a 5–10% productivity improvement across major programmes would materially reduce delivery risk. 
• Energy infrastructure carries a high fiscal multiplier.  
• Expanding workforce capacity does not merely protect projects, it also strengthens domestic value capture, tax receipts and exportable engineering capability.  

Comparative lens: China’s scaled response 

China is confronting demographic ageing on a far greater scale, while simultaneously executing the world’s largest clean energy buildout. This response offers vital lessons.   

Workforce retraining has been deployed at speed through technical institutes closely aligned to industrial policy. Transitions from legacy sectors into renewables manufacturing and grid construction are structured rather than left entirely to market dynamics. Crucially, transition is framed as part of a broader ‘social contract’ where industrial restructuring is accompanied by retraining, redeployment and state supported employment pathways across all age groups.  

Proof of concept – China is responsible for 90% of humanoid robots, 80% of solar PV, 70% of EVs, 70% of wind technology, 69% of renewables (1.4 TW), 60% of AI patents, 57% of STEM PhDs, 50% of installed green hydrogen, 46% of renewable energy jobs (7.4 million people), 30% of hydroelectricity, 30% of 60+ workforce (400 million people by 2035).  

Conclusion: The UK operates under a different political economy. However, this principle is transferable, potentially enabling national workforce strategies to be treated as core infrastructure, not an auxiliary labour policy.  

Threats: cost of inaction 

If workforce contraction collides with infrastructure acceleration, consequences may cascade: 

• Programme delays in generation connection and grid reinforcement.  
• Rising labour costs and procurement volatility. 
• Increased average cost of capital, due to price delivery uncertainty. 
• Greater reliance on imported engineering services.  

In a globally competitive talent market, shaped by US, European and Chinese clean energy expansion, skilled engineers are mobile, potentially compounding UK risk as they relocate to rebuild war-damaged infrastructure in the Middle East, to avoid high levels of domestic taxation.

Strategic inflection point 

The retirement of 30% of the UK’s highly skilled energy contracting workforce is foreseeable. This strategy makes it manageable, if it is treated with urgency.  

China’s example demonstrates that demographic pressure doesn’t need to translate into delivery failure if workforce transition is elevated into strategic priority.  

For Britain, the choice is clear. Treat the skills shortage as a reactive labour issue and accept mounting delivery risk, or treat it as a national growth lever, mobilising training, reskilling, immigration and digital productivity in parallel.  

In the race to 2030, capital and technology will not be the decisive constraint. Execution capacity will be. And its success will depend on people.  

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: ‘Renewables industry invests to train up next generation of workers’. Major utilities and educational institutions in the UK are collaborating to bridge the skills gap through immersive digital simulations, specialised training academies and research initiatives. 
• ‘UK unveils plan to create 400,000 green energy jobs by 2030’. The UK government plans to create 400,000 new clean energy jobs over the next five years, as part of a major workforce expansion to support the country’s transition to renewable power. 

At nearby Thorsminde Port, RWE has opened a new operations and maintenance building from where a crew of 50 will keep the wind farm running. The three-storey building includes a control room, warehousing, offices, canteen and rooftop terrace.  

In addition, a decision has been made that affects other Danish waters. The European Commission has approved a €5bn state aid project to provide support for two new wind farms, Hesselø (0.8 MW/3.2 TWh) and North Sea I Mid (1 MW/4.6 TWh), to be awarded through competitive tenders.

The aid will provide a monthly variable premium under a two-sided contract for difference (CfD), within which the bid price is compared to a reference market price, weighted by the monthly capability of the offshore wind farm. When the reference price is below the bid price, the developers are paid; when the reference price is above the bid price, the government is paid.

The project was allowed under the provisions of CISAF (the Clean Industrial Deal), to support key measures for net zero. It is in place until the end of 2030.

‘For production to restart, first we need hostilities to cease,’ said QatarEnergy’s CEO and State Minister for Energy Affairs Saad al-Kaabi, quoted in Hydrocarbon Processing.

At Bahrain’s Sitra refinery, two crude distillation units and a tank farm were damaged – one of which had only just been commissioned months before as part of a $7bn upgrade – again creating a force majeure claim across the site.  

‘Restoring the units will likely require international contractors to be re-mobilised at conflict-inflated costs and under uncertain war-risk insurance, as the damaged assets had only recently come online,’ said Rystad.

Rystad estimates the total costs at $25bn, but warns that they are likely to rise with further inspections.

One of two trains at the Pearl gas-to-liquids (GTL) site in Qatar was also damaged. New Energy World understands that damage is in the air separation units (ASUs), which separate oxygen from the air to feed the gasifiers, and repair will take one to two years.

Construction work in the planned 32mn t/y North Field East expansion has halted, pushing completion past the previous estimate of 2027, according to a report by Wood Mackenzie.

Bloomberg reported that damage to Iran’s South Pars offshore gas field has stopped the country exporting gas to Türkiye.  

The halt of Qatari LNG production in early March has stopped about 19% of the world’s LNG, 80mn t/y, according to Wood Mackenzie. It says that the disruption is globally significant. ‘With Qatar producing an average of 6.7mn tonnes per month in 2025, a disruption lasting five to six months would push annual global supply into year-on-year decline,’ said Wood Mackenzie Global LNG Research Director Daniel Toleman.

The market analyst predicts that Asian customers, including in Bangladesh, India and Taiwan, are most likely to be affected.

‘The state of the global climate is in a state of emergency. Planet Earth is being pushed beyond its limits. Every key climate indicator is flashing red,’ said UN Secretary-General António Guterres.

The State of the global climate report includes a new measure of energy balance in the Earth system. Whereas in a typical year, energy output would equal energy input, the amount of excess energy the world takes on keeps rising and reached a high in 2025.

‘Human activities are increasingly disrupting the natural equilibrium and we will live with these consequences for hundreds and thousands of years,’ said WMO Secretary-General Celeste Saulo.

More than 91% of the excess heat is stored in the ocean, which acts as a major buffer against higher temperatures on land. Ocean heat content reached a new record high in 2025 and its rate of warming more than doubled from 1960–2005 to 2005–2025, according to the WMO.

Of the rest, 5% of the heat goes into land masses, 3% into ice – which saw some of the lowest cover ever in the Arctic last year – and 1% into the atmosphere.

The authors pointed out the urgent need to integrate meteorological and climate data with health information systems to allow decision-makers to move from reactive response towards proactive prevention which saves lives. Climate change poses direct risks to populations – in heat stress, for example – to indirect risks, such as the spread of Dengue fever, which is spread by mosquitoes.

Countering the threat of climate change

In the UK, a new National Heat Risk Commission is being created to investigate how to improve efforts across the UK to tackle the wide-ranging impacts of high temperatures. The new Commission, which aims to issue a report in 2027, will be based at the Grantham Research Institute on Climate Change and the Environment at the London School of Economics and Political Science, and chaired by Emma Howard Boyd CBE.

She said: ‘Extreme heat is not an equal-opportunity killer. It disproportionately affects the most vulnerable in our society – those in social housing, the elderly, the very young, people with underlying health conditions and pregnant women. This Commission will provide the roadmap to ensure the UK is resilient to high temperatures without compromising our economic or climate goals.’

Supply chain body forms net zero alliance

Organisations from across the UK’s energy, transport and built environment sectors have signed a new climate commitment developed by energy infrastructure and energy systems trade association BEAMA.  

It said: ‘As Scope 3 emissions move to the centre of corporate climate strategies, businesses are facing increasing regulatory scrutiny, rising customer expectations and increasing reporting complexity. The commitment establishes a structured, industry-led mechanism to help organisations move from ambition to coordinated delivery and make measurable progress across their supply chains.’

Signatories commit to reducing Scope 1, 2 and 3 emissions, setting science-based targets aligned to 1.5°C, embedding sustainability into governance, integrating circular economy principles, engaging responsibly in policy development and collaborating to strengthen value chain alignment.

‘By working across the value chain, we can turn commitments into practical, scalable solutions that support decarbonisation, circularity and long-term industry resilience,’ said Yselkla Farmer, CEO, BEAMA. 

The project is operated by Azule Energy, a joint venture between BP and Eni with collaborative partners Cabinda Gulf Oil Company (Chevron), Sonangol and TotalEnergies. Initial gas exports from the Quiluma field have commenced at a rate of 4.25mn m3/d. Operators expect a steady ramp-up throughout 2026, eventually reaching a plateau of 9.34mn m3/d.

‘This project marks an important step for Angola's energy system and strengthens the country's energy mix as it looks to enhance its position as a global player in the natural gas market,’ said Gordon Birrell, BP’s Executive Vice President for production and operations.

The Quiluma start-up follows the November 2025 inauguration of the project’s gas treatment plant in Soyo. It is the latest in a string of operations for Azule Energy, which recently saw oil production start at the 175,000 b/d Agogo field (July 2025) and the 60,000 b/d Ndungu development (February 2026).

In North Africa, TotalEnergies has successfully restarted production at the Mabruk oil field in Libya. Production at the onshore site had been suspended since 2015. The restart follows the rapid construction of a new production unit with a capacity of 25,000 b/d, according to the TotalEnergies’ announcement. After construction launched in May 2024, the facility officially started up in February 2026.

‘This restart illustrates our long-term commitment in Libya, as we celebrate TotalEnergies’ 70th anniversary in the country this year,’ stated Julien Pouget, the company’s Middle East and North Africa Director.

Simultaneously, Eni has announced two gas discoveries following a recent offshore exploration campaign. The adjacent structures, Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3), were successfully drilled roughly 85 km off the Libyan coast. Preliminary data from Eni indicates the two structures jointly contain over 28.3bn m3 of gas. Due to their proximity to the Bahr Essalam field, Eni plans for a ‘rapid development’ by tying the new fields back to existing infrastructure. The gas is earmarked for both the Libyan domestic market and export to Italy.

Carbon-storing concrete undergoing trial

Full-scale trials of ultra-low and carbon-storing concrete mixes have been carried out at London’s Canary Wharf, as part of an industry collaboration aimed at assessing next-generation materials under real construction conditions.

The programme, led by developer Canary Wharf Group (CWG) with input from building materials supplier Holcim UK and a consortium of engineers, contractors and academic institutions, has tested a series of alternative concrete formulations incorporating biochar, graphene and low-carbon cementitious materials.

Trial pours were undertaken in April and September 2025, including a test slab at CWG’s Wood Wharf site and two-metre-deep raft foundations at its Bank Street site. The works follow earlier smaller-scale applications, including underwater counterweights for the ‘Whale on the Wharf’ public art installation.

One of the primary mixes utilised biochar derived from coppiced timber and spent coffee grounds collected from Canary Wharf coffee shops. According to project data, the initial formulation achieved an 80% reduction in net global warming potential (GWP) (A1–A3) compared to a standard CEM 1 concrete, resulting in a projected combined fossil and biogenic GWP of 69 kgCO2e/m³.

Subsequent optimisation of the mix resulted in a calculated net GWP (A1–A3) of –14 kgCO2e/m³, when accounting for both fossil emissions and biogenic carbon storage. The negative value reflects the sequestration of carbon captured during the biomass growth phase and retained within the concrete matrix.

A separate mix incorporating graphene demonstrated a reduction in embodied carbon of more than 50% compared to a CEM 1 control, alongside improvements in compressive strength and durability performance, thereby potentially reducing the amount of concrete required in certain applications and improving cover of reinforcement (such as rebar).

Materials will be subject to a two-year monitoring phase to evaluate in-situ performance, durability and long-term carbon outcomes. 

UK’s first hydrogen-fuelled asphalt production

Hydrogen has been successfully used to decarbonise asphalt production on an industrial scale for the first time in the UK, at Heidelberg’s Criggion plant in Powys, Wales.  

During the trial, hydrogen replaced liquid fossil fuels powering production of more than 1,300 tonnes of asphalt, without any impact on the quality or performance of the material, the company claims.  

The project demonstrated hydrogen as a viable alternative to fossil fuels in asphalt production, achieving a 76% reduction in Scope 1 (direct) emissions equating to a 23% reduction in the overall carbon footprint of the asphalt produced.   
 

In total, 4,522 kg of hydrogen was used during the trial, saving 25,105 kg of CO2. If scaled across the UK asphalt industry, savings could reach 450,000 tonnes of CO2 a year.

The Criggion trial is part of the UK government’s Industrial Hydrogen Accelerator programme and received part-funding from the Department for Energy Security and Net Zero. 

Hydrogen was used to replace liquid fossil fuels to produce more than 1,300 tonnes of asphalt at Heidelberg’s Criggion plant in Powys, mid Wales  
Heidelberg 

UK Net Zero Carbon Buildings Standard Version 1 launched

The first full version of the UK Net Zero Carbon Buildings Standard has been launched, said to provide a unified framework for defining and verifying net zero carbon performance across the built environment.

Developed through a collaboration of industry bodies including CIBSE, RIBA and the UK Green Building Council, the free-to-access technical standard aims to eliminate ambiguity around net zero claims while aligning building performance with the UK’s legally binding climate targets.  

Version 1 builds on a pilot released in September 2024 and sets out requirements covering performance targets, evidence, reporting and verification. It also introduces several new annexes, including guidance for landlord- or tenant-only assessments, a completion tracker and alignment with existing schemes such as NABERS UK and Passivhaus.

Katie Clemence-Jackson, Chief Executive of the UK Net Zero Carbon Standard, said the framework would provide ‘much-needed clarity and consistency’ while helping the industry measure and reduce emissions in line with climate goals.

The updated version also includes revised performance limits, refined following industry feedback, while maintaining alignment with a 1.5°C pathway.

Verification of buildings against the standard is expected to become available in 2Q2026. Once in place, projects will be able to undergo independent assessment to achieve ‘net zero carbon aligned’ status.

‘Weakening the EU ETS will not solve Europe’s competitiveness challenges. On the contrary, it can lead to increased uncertainty and slow down the power sector investments Europe urgently needs. The EU has already decided to reduce its emissions by 90% by 2040. The EU ETS delivers a clear and credible price signal that guides long‑term investment into renewable power, flexibility and electrification. It is the backbone of Europe’s net zero strategy,’ says Birgitte Ringstad Vartdal, President and CEO of Statkraft.  

The letter highlights that ETS revenues support European industry through transition and electrification without putting additional pressure on public finances. The companies encourage EU leaders to enable efficient redistribution of ETS revenues and to establish the Industrial Decarbonisation Bank announced under the Clean Industrial Deal. The companies stress that Europe stands at a critical crossroads: ‘Either accelerate the energy transition and innovation to close the competitiveness gap, or risk undermining decades of progress in European energy and industrial transformation.’

The CEO of European energy company Vattenfall, Anna Borg, has taken a firm stance, stating: ‘Don’t mess with ETS.’ The company argues that short-term interventions to lower carbon prices would only shift costs to future generations and state budgets. Vattenfall likens abandoning the ETS to stopping the insulation of a house halfway through because it feels expensive – only to face much higher repair and energy costs later.

‘Regulatory stability is not a nice to have; it is what enables the massive investments required for the transition. Keep marginal pricing and the ETS as the pillars of the transition intact and give businesses the regulatory certainty needed to keep Europe in the lead. Only a decarbonised Europe is a competitive Europe,’ Borg adds.

Analysis from European think-tank Bruegel characterises the ETS as an ‘ally, not an enemy’ of industrial competitiveness. The report warns that weakening the carbon market would create a ‘laggard’s dividend’, penalising companies that invested early in green technology. Bruegel suggests evolving the system from ‘cap-and-trade’ to ‘cap-and-invest’, using auction revenues to fund a ‘strong industrial decarbonisation bank’ to scale low-carbon investments.

In a keynote address at the 2026 EIB Group Forum, European Council President António Costa declared 2026 the ‘year of European competitiveness’. Addressing high energy costs, Costa clarified that the EU ETS is responsible for only a small fraction of the price gap between Europe and its global competitors like China and the US. He argued that the true culprit is a continued reliance on imported fossil fuels and urged the completion of a ‘One Market for One Europe’ to scale clean energy solutions.

Climate think-tank E3G states that the EU ETS is essential for a secure Europe. Its analysis refutes claims that carbon pricing is the primary driver of high energy prices, noting that fossil fuel volatility is the real threat. E3G emphasises that the ETS generates substantial fiscal revenue and that the industry has reportedly received four times more support through ETS-funded innovation than it has paid in carbon costs since 2021.

The revision of the EU ETS will determine its shape beyond 2030. Following the Commission proposal in 2026, the Council and European Parliament said they will start negotiating on the future of the EU ETS.

Additionally, a separate system (ETS2) for road transport and buildings is set to begin in 2028, eventually bringing the total coverage of EU emissions to 75%.

Vineyard Wind 1 is an 806 MW offshore wind energy project offshore Massachusetts. It consists of 62 GE Haliade-X turbines of 13MW. Also paused last summer, it restarted construction in January 2026.

Construction continues on three other wind farms that had been blocked over the past year by the Trump administration, latterly on national security grounds, and formerly on an executive order. All three projects were disputed in the courts.

Ørsted’s Sunrise Wind project restarted construction in February. It has a 25-year power purchase agreement to deliver 924 MW to New York State.

Dominion Energy’s 2.6 GW Coastal Virginia Offshore Wind (CVOW) project, consisting of 176 turbines, is reported to be 70% complete. In October 2025, all monopile foundations were installed.  

Empire Wind 1 is an 810 MW wind farm offshore Long Island supplying power to New York City. The project, consisting of 54 Vestas turbines, restarted work this January, at which point it was estimated as more than 60% complete.

In response, trade association Oceantic Network said: ‘US offshore wind continues to power forward. With the third US project now delivering desperately-needed electricity to the grid – and lowering winter energy bills for millions of Americans – the domestic offshore wind industry is demonstrating its true potential every day. The burgeoning, 40-state American supply chain supported installation across five different projects simultaneously – a feat rivalled by few other markets – while creating more than 12,000 jobs and driving $25bn of American investments flowing directly into our shipyards, ports, and manufacturing centres.’ 

TotalEnergies to pull out of US offshore wind

In a surprise announcement, the US wind sector was dealt a blow earlier this week with TotalEnergies announcing it will no longer develop offshore wind projects in the country. The company has signed settlement agreements with the US Department of the Interior (DOI) to relinquish its Carolina Long Bay lease and its New York Bight lease, both awarded in 2022, along with its partners. As a result, TotalEnergies will no longer develop offshore wind projects in the US.

TotalEnergies reports that studies on the two leases had shown that ‘offshore wind developments in the US, unlike those in Europe, are costly and might have a negative impact on power affordability for US consumers’. It added: ‘Since other technologies are available to meet the growing demand for electricity in the US in a more affordable way, TotalEnergies considers there is no need to allocate capital to this technology in the US.’

Patrick Pouyanné, TotalEnergies CEO, comments: ‘TotalEnergies is pleased to sign these settlement agreements with the DOI and to support the Administration’s energy policy. Considering that the development of offshore wind projects is not in the country’s interest, we have decided to renounce offshore wind development in the United States, in exchange for the reimbursement of the lease fees.  

TotalEnergies says it plans to reinvest the refunded lease fees to finance the construction of the 29mn tonne Rio Grande LNG plant and the development of the company’s oil and gas activities, ‘to support the development of US gas production and export’.  

‘These investments will contribute to supplying Europe with much-needed LNG from the US and provide gas for US data centre development. We believe this is a more efficient use of capital in the United States,’ said a company statement.

TotalEnergies also signed recently a letter of intent with Glenfarne, lead developer of the Alaska LNG project, for the long-term offtake of 2mn t/y of LNG over 20 years, subject to the project’s final investment decision. Alaska LNG will have a total capacity of 20mn t/y, with direct access to Asia, the world’s largest LNG market. 

The pipeline will form the backbone of a clean energy corridor designed to boost regional economies, protect and create jobs, and enhance energy security, National Gas said in a statement.  

Ian Radley, Chief Commercial Officer at National Gas, described the announcement as ‘a hugely significant moment in Britain’s energy transition’. He added: ‘The East Coast is the natural place to start. It’s one of the most important industrial heartlands with enormous hydrogen potential.’

The plans build on findings from National Gas’s FutureGrid test facility, where it has been demonstrated that blends of up to 100% hydrogen can be safely transported using existing infrastructure.  

By repurposing existing natural gas pipelines and building new ones where needed, up to 1,500 miles of hydrogen network will be created in the UK under Project Union. Early analysis suggests it could support around 3,100 jobs at peak construction and generate £300mn annually in direct economic value.  

Planned route of Project Union: East Coast

National Gas

Launch of Humber Hydrogen consortium

The announcement follows a recent partnership between National Gas, Centrica, Equinor and SSE Thermal to secure government funding for Britain’s first hydrogen cluster – Humber Hydrogen.

The Project Union East Coast underground pipeline will link into the Humber Hydrogen cluster, connecting major production, storage and industrial demand centres across the region.  

The consortium is preparing a bid under the government’s Hydrogen Transport and Storage Business Model. A funding decision, expected to be worth around £500mn, would unlock infrastructure critical to large-scale hydrogen deployment.

Several major projects are already planned in the Humber, including hydrogen production facilities at Easington and Saltend, which together could deliver up to 3 GW of capacity.  

Mike Finnerty, Chief Nuclear Inspector and Chief Executive of the Office for Nuclear Regulation, said: ‘As an enabling regulator, we look forward to working in close partnership with the government, industry and all stakeholders to drive forward the cultural and practical changes needed to safely deliver nuclear projects more efficiently and effectively in support of the country’s clean energy goals.’

Bob Anstey, Sector Director, Defence and Nuclear Energy at contractor Costain, called the changes ‘sensible steps that will help to streamline the regulatory burden for megaprojects like Sizewell C and the UK’s SMR Programme’.

At the same time, the government has announced funding for four times as many doctoral research positions as currently, to 500, as part of £66mn backing seven new university research programmes in nuclear technologies.

In other news, the Rolls Royce small modular reactor (SMR) planned for Anglesey has received regulatory justification from the Environment Secretary Emma Reynolds MP. The Nuclear Industry Association, which applied for the justification, said: ‘Regulatory justification is an important step in the approvals process for new nuclear power plant designs, ensuring that the benefits and potential detriments of a new nuclear technology are fully assessed before construction can proceed.’ (However, the government noted that, following reforms, this might be the last time a light-water reactor would have to go through this step.)

Elsewhere, further information has been published about a new government scheme to prequalify small-scale private-sector projects, called the UK Advanced Nuclear Pipeline.  

According to newly-updated guidance, the process works like this: ‘...Projects submit detailed plans across five core areas: technology and supply chain; developer capability; finance/funding/investment; siting; and operator/end-user arrangements. The Department for Energy Security and Net Zero (DESNZ) and GBE-N will then conduct eligibility checks and a structured Project Readiness Assessment (PRA) (rapid triage, then deep dive). Projects assessed at or above the threshold may be invited to join the Pipeline, subject to ministerial approval and agreement to Pipeline terms. Pipeline Membership confers a Statement of Limited, In-Principle, Endorsement, signalling that government considers the project credible and potentially deliverable in the UK, thereby helping developers and investors progress financing and due diligence. Pipeline projects may engage with DESNZ on potential revenue support, eg a Contracts for Difference (CfD)-style mechanism that stabilises future revenues, and High Impact, Low Probability (HILP) risk protections where private markets cannot efficiently bear residual risks.’

A focus on the commercial sector is also evident in a new national strategy for nuclear fusion (combining atoms rather than breaking them apart). This breaks down the £2.5bn fusion R&D investment promised last year over 25 years. It will include £200mn (to 2029) for construction of STEP, a fusion energy plant in a former coal plant in Nottinghamshire. That partner was named as ILIOS, a consortium led by a joint venture between Kier and Nuvia, and supported by AECOM, AL A Architects and Turner & Townsend. Delivering that project will be UK Industrial Fusion Solutions (renamed as UK Fusion Energy) with a £1.3bn cheque. There’s also a £45mn payment to build a UK Atomic Energy Authority/University of Cambridge supercomputer for fusion. About the same amount (£50mn) will be spent on fusion skills and innovation.

In other news, Eni has joined UKAEA in the H3AT fusion fuel cycle facility in Culham, Oxfordshire, due to be completed in 2028 and fully commissioned in 2030. Its design and fabrication partner was also named as Kinectrics of Canada, which is said to bring decades of experience with tritium – a radioactive isotope of hydrogen that is an essential fuel for future fusion power plants.

Imagine if the UK were faced with these prices on 5 January when every natural gas plant was turned on in the UK and natural gas accounted for over 55% of the electricity mix. UK industrial companies, whose energy demands do not naturally decline when it gets warmer and who are not protected by a price cap, will suffer the most. But this pain will be passed on to the workers and the taxpayer. The emergency support measures to address the gas price crisis when Russia invaded Ukraine cost the UK taxpayer over £51bn, debt that continues to weigh on the budget today.

Which is not to say that the UK energy system is fragile. During the wargaming exercise that fed into the RenewableUK energy security paper, it became very clear that the UK energy system is very hard to break. Like a well-oiled machine, in the event of a crisis, clear roles and proven procedures kick in to ensure that natural gas supply is secured from global energy markets with oil and gas industry leadership playing important roles and working with National Gas and the UK government during these events. We see this today with Norway maximising its gas production capacity to support the UK and Europe. The UK government has been clear – the UK does not have a physical natural gas supply issue. The challenge is a price crisis. The UK can no longer afford this ‘one dimensional’ approach.

With Clean Power 2030, the UK is building a distributed electricity system that can be leveraged much more for energy (and national) security. In the war game exercise, it became clear that an attack on even the largest wind farm can be absorbed much more easily by the UK’s electricity system than one on gas infrastructure. Additionally, wind farms can be more resilient to attacks. The paper includes a telling quote from the Chief Sustainability Officer of Ukrainian electricity developer and utility DTEK: ‘You would need around 40 missiles to do the equivalent amount of capacity damage at a wind farm as you would with one missile at a thermal power plant.’ This is a key advantage to a distributed infrastructure – there are fewer single points of failure (such as the Strait of Hormuz).

But perhaps the most important message of the RenewableUK energy security paper is its call to action to the renewables and electricity infrastructure leadership to play a more active role in energy (and national) security.

I was a member of the US National Petroleum Council (NPC) when Russia invaded Ukraine. At the end of July 2022, then US Secretary of Energy Jennifer Granholm went to the NPC and asked the oil and gas industry for recommendations on how to decrease the prices at the pump caused by the Russian invasion (in 30 and 120-day timelines). The oil and gas industry mobilised and delivered. Born from decades of experience in energy crises, similar expertise was on hand from the oil and gas leadership in the room during the war game exercise which I witnessed that fed into this paper.

On the other hand, as the paper points out, we do not have clear emergency procedures for renewables assets and, possibly even more importantly, we have not explored with renewables and electricity infrastructure leadership how the system we are building can be used to improve energy security and resiliency. In times of system stress, how can renewable generators respond to support energy security?

The paper explains how DTEK has reconfigured its electricity system from one once reliant on thermal power to an electricity system where wind, solar and batteries are the workhorse. DTEK is a distribution network operator (DNO), like UK Power Networks, National Grid, SP Electricity North West, Northern Powergrid, SP Energy Networks, Scottish & Southern in the UK. Closest to the consumer during a crisis, the DNOs can also play a much bigger role in improving local resilience given the distributed and digital nature of wind, solar, batteries and microgrids. On that point, in the US, rural cooperatives (member-owned non-profit DNO equivalent in rural America) which have experienced being cut off from gas supply during cold winters and which are facing wildfire risks, are building microgrids to provide autonomous power to communities during extreme weather or disasters.

The RenewableUK energy security paper, New threats and new tools: reinventing energy security for an era of instability, clearly flags that we cannot afford our current approach and also highlights the opportunity we have if we lean into the distributed renewables system we are building, including practical suggestions being deployed in other markets. It’s an important call to action.  

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: ‘How Ukraine’s wartime experiences are being used to guide new strategies for energy resilience’. The resilience of Ukraine's energy sector in war provides a model for international energy security, according to a new report from the International Energy Agency.
• ‘The new energy trilemma – why national security is reshaping the global energy transition’. Discover how energy systems are no longer viewed simply as economic infrastructure but are increasingly understood as strategic national assets – critical to economic resilience, industrial competitiveness and national security.

This distinction is important. If the industry is to scale sustainably, it cannot rely on feedstocks that compete with food or drive additional land use change. The long-term solution must focus on carbon that already exists as residue or emission.

Cellulose is tough to break down, requiring a community of microbes or a number of process steps. The easiest product for it to break down into is methane (CH₄), as, thermodynamically, this is the most stable end point. Methane is also a non-toxic gas which does not inhibit the microbes involved in the process. This is biogas, and it is a great feedstock for converting into aviation fuel via gas-to-liquids. The biomethane in the biogas can be converted into carbon monoxide (CO) and hydrogen (H₂), using a process called steam methane reforming, with some of the byproduct CO2 added and also converted to increase the greenhouse gas (GHG) emissions saving.

Wastes higher in cellulose, such as food waste or agricultural waste, can therefore be digested into biogas, along with any sugars or starches present. The biomethane can then be reformed into syngas, with some of the byproduct CO2 added back in and converted to reduce the overall carbon intensity.

Biogas is already produced at scale in many regions, including China, Germany, the US, India and several other European countries. The opportunity is to redirect this feedstock away from heat and power applications, where it is often used today, and instead into liquid fuel production, where the decarbonisation challenge is harder.

Lignin and gasification
High-lignin waste feedstocks such as wood waste, sugar cane bagasse, corn stover and rice straw are much tougher to process. Here, the most likely route is to partially combust them via gasification to produce a mix of hydrogen, CO and CO2. Gasification is difficult to control and presents challenges such as tar formation. However, if the resulting syngas is properly cleaned, it can be used to make aviation fuel. In some cases, additional green hydrogen can be added to convert more of the carbon and improve the carbon intensity.

Waste-based fuels and chemicals derived from high lignin feedstocks are a key part of the mix. The technologies are complex and the feedstocks variable, but the carbon is available and abundant. In some cases, there are additional benefits, such as reducing air pollution from traditional rice straw burning. As demand for sustainable aviation fuel (SAF) grows, these routes will need to form part of the solution.

Gasification of plastic or municipal solid waste is another option, although it is more challenging due to the variability and complexity of the feedstock. As a result, total combustion is often preferred, as seen in energy-from-waste plants. While gasification of these waste streams can reduce landfill, if the carbon ultimately becomes fuel and is then released to the atmosphere when burned, it will not reduce emissions and could even increase them. A more sensible approach may be to use the CO2-rich syngas to produce plastic precursors such as naphtha, and from this manufacture ethylene and propylene before returning them to plastics, thereby encouraging circularity.

CO2 and power-to-liquids
Finally, there is CO2, which can be derived from fossil sources or biogenic sources. Biogenic sources are ideal, as circularity can be claimed. However, if fossil CO2 comes from hard-to-abate sectors that would have emitted anyway over the next few decades and cannot go underground, distinguishing between fossil and biogenic CO2 will make no difference to the atmosphere in that period.

Capturing CO2 directly from the air through direct air capture (DAC) is theoretically possible. However, it is likely to remain extremely expensive because of the vast volume of air that must be processed continuously. The amount of air that needs to be handled per unit of CO2 captured is fixed by thermodynamics, specifically by the entropy change involved in concentrating CO2 from around 420 parts per million to near pure (one million). In some locations, wind may be used through a chimney effect rather than mechanical fans. Even so, the material requirements, energy demand and land area involved mean that DAC will remain a significant technical and economic challenge.

For power-to-liquids (PtL), biogenic CO2 is likely to be the primary focus for now, with fossil CO2 from hard-to-abate sectors used where permitted. This CO2 is converted into fuel using large quantities of green hydrogen, which in turn requires substantial renewable electricity. The key advantage compared with biomass-based fuels is the lower land use requirement. However, production must be located in regions with abundant, low-cost renewable electricity, typically sunny or windy areas. In many of these regions, available CO2 is more likely to be fossil-derived due to limited biomass growth.

Regardless of the challenges, PtL (or e-fuels) is widely recognised as critical for the future of SAF due to the limits of the other feedstocks, and regulation is already underway to support this transition. For example, the EU requires 50% of the 2050 blending requirement under ReFuelEU to be met via PtL.

Enabling conversion across feedstock routes
The scale of demand means no single feedstock can deliver the required volumes. To meet the huge demand for sustainable aviation fuel, we will need them all.

OXCCU is developing an iron-based Fischer-Tropsch catalyst able to convert a wide range of syngas compositions, including CO2, CO and hydrogen, directly into liquid hydrocarbons in the aviation fuel range. Our feedstock, CO2-rich syngas, can be derived from biogas reforming, solid carbon waste gasification, or from CO2 and green hydrogen. This approach consolidates the traditional production process from a two-step reverse water gas shift and Fischer-Tropsch reaction into a single catalytic conversion. Fewer steps reduce energy input and improve overall yield.

In practical terms, the same catalytic platform can be applied whether the carbon originates from CO2, biogas or gasified solid carbon waste. In all cases, the objective remains consistent: reducing both cost and carbon intensity. If aviation is to decarbonise at scale, it cannot depend on a single carbon source. It must use waste carbon in all its forms. The focus now is on deploying technologies capable of converting that waste carbon efficiently and economically into aviation fuel.

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: ‘IATA SAF Registry goes live’. Discover more about the International Air Transport Association’s Sustainable Aviation Fuel Registry, designed to enable a global market for SAF that will accelerate the transition to net zero by 2050.
• ‘Heathrow ramps up SAF ambition as UK government moves to de-risk supply’. Heathrow Airport has unveiled an enhanced incentive scheme targeting 5.6% sustainable aviation fuel use in 2026, as the UK government advances plans for a contracts-for-difference-style revenue certainty mechanism (RCM). 
   

He also said that the impact on gas of the blockade amounts to a reduction of 140bn m3, twice that of the blockade of Russian exports after its invasion of Ukraine.

‘In the absence of a swift resolution, the impacts on energy markets and economies are set to become more and more severe’ Birol said at a 23 March event in Australia, according to Al Jazeera.

As a result, an IEA report published on 20 March offers nations ideas of how to reduce demand for oil and gas.

An IEA press statement about the report referred to the importance of reopening the Strait of Hormuz, as well as IEA plans to release 400mn barrels of strategic stocks. It then went on to say: ‘Supply-side measures alone cannot fully offset the scale of the disruption. Addressing demand is a critical and immediate tool to reduce pressure on consumers by improving affordability and supporting energy security.’

The report’s suggestions, which include increasing home working, reducing motorway speeds and avoiding air travel, focus primarily on road transport, which accounts for around 45% of global oil demand, but also cover aviation, cooking and industry.

About the report, Birol said it ‘provides a menu of immediate and concrete measures that can be taken on the demand side by governments, businesses and households to shelter consumers from the impacts of this crisis. It draws on the IEA’s decades of expertise in this field and highlights measures that have been proven to work in practice in different contexts.’

The report is titled Sheltering from oil shocks – https://www.iea.org/reports/sheltering-from-oil-shocks. The IEA has also published examples of national actions taken recently – https://iea.blob.core.windows.net/assets/2aa0c404-fed1-4ee1-80db-6ab5b6016266/Overview-Trackinggovernmentemergencymeasures2026.pdf

As New Energy World went to press, Iran issued a statement via its mission to the United Nations about passage through the Strait, which might indicate an easing of restrictions. It read: 'Non-hostile vessels, including those belonging to or associated with other States, may – provided that they neither participate in nor support acts of aggression against Iran and fully comply with the declared safety and security regulations – benefit from safe passage through the Strait of Hormuz in coordination with the competent Iranian authorities.'

The virtual experience navigates technical tasks required to maintain the 440 MW pumped storage hydro facility. This initiative aims to inspire interest in STEM careers by providing a realistic look at renewable energy operations located 1 km underground.

Lisa Marriott, Early Careers and Development Manager at Drax, said: ‘This new simulation gives young people the chance to experience what it is really like to work in the power sector, while building the skills and confidence that will support their future careers in sustainable energy.’

New green skills training facility to open in Wiltshire

Wiltshire College and University Centre is set to launch a new £3.5mn Green Skills Centre at its Trowbridge campus to train the next generation of low-carbon installers. Renewable energy company and services provider Good Energy has partnered. It said that the facility provides hands‑on training in the installation and maintenance of renewable technologies including solar PV, heat pumps, battery storage and smart home energy systems.

Iain Hatt, Principal and Chief Executive of Wiltshire College and University Centre, said: ‘Our Green Skills Innovation Centre is designed to help employers understand what is possible with today’s renewable technologies and to provide the skilled workforce required to deliver it.’

The college transformed a 100-year-old former home at Lackham into the Eco House to act as a showcase for renewable technologies.  

Hatt added that project was done with electrical utility Good Energy, which he said has been ‘invaluable in ensuring it reflects real industry needs. Together, we will help students and employers gain the confidence and capability to seize the opportunities of the green transition.’

Strategic partnership formed between ScottishPower and the University of Glasgow

To the north, ScottishPower has announced a new partnership between its distribution arm, Scottish Power Energy Networks, and the University of Glasgow, to establish a cyber defence laboratory with the aim to fund PhD and graduate apprenticeship programmes and develop data, cyber, digital and AI skills needed to deliver a resilient net zero electricity system.

Meanwhile, ScottishPower is receiving a record-breaking number of applications for its 2026 energy apprenticeship programme. The green energy company says it has received more than 6,000 applications for the 150 roles on offer across its businesses – including SP Energy Networks and SP Electricity North West – and that the level of interest is a 25% increase on 2025.

Centrica, X-energy and Hartlepool College target nuclear skills

Finally, utility Centrica, and nuclear reactor and fuel designer X-energy, are partnering with Hartlepool College of Further Education to establish a new Nuclear and Electrical Trades Academy. The Academy includes a specific focus on attracting a more diverse workforce into the nuclear industry. Centrica stated that the partnership will provide ‘young people with the skills, confidence and pathways to build their futures in a sector that will support Britain for decades to come’.  

Chris O'Shea, Group Chief Executive of Centrica, said: ‘We’ve got big ambitions for Hartlepool – not just to host new nuclear technology, but to become one of the UK’s leading centres for clean energy skills and training. That means real opportunities, real investment, and long‑term careers for local people as the town leads the next chapter of the UK’s energy story.’

From 2028, the mandate will extend to new roofs or material changes. Solar Energy UK has strongly welcomed the decision, noting that it brings Wales into alignment with similar standards recently proposed for England.

The mandate parallels England’s upcoming Future Homes Standard and Future Buildings Standard, which are expected to be finalised later this year. Currently, over 40% of new homes in England are already built with solar panels, according to Solar Energy UK.

‘This is tremendous news for Wales and I applaud the Welsh government for their wise decision,' said Chris Hewett, Chief Executive of Solar Energy UK. He noted that the industry has long lobbied for solar to be all but mandatory on new buildings to ensure future occupants benefit from lower energy bills.

Specific exemptions exist to prevent impractical or uneconomical installations. If a system cannot generate at least 720 kWh per year, the requirement will not apply to that specific building. A typical residential rooftop solar installation of nine 450 Watt solar panels generates about 3,500 kWh. Detailed guidance will be published later this year following a consultation to determine the feasibility of the mandate.

In a separate clean energy milestone, Great British Energy has now funded solar panel installations on 100 schools and colleges across England. Around 250 schools are expected to complete their installations by summer. This programme is estimated to save these educational institutions a combined £220mn over the lifetime of the panels.

Great British Energy and the government have noted their focus on schools clustered in areas of deprivation, including the North East and North West. At least 10 schools in every English region are receiving support through the £255mn investment, according to the Department for Energy Security and Net Zero and the Department for Education.

Minister for Education Josh MacAlister said: ‘Solar panels are not just good for the planet – they are an investment that keeps paying back into our schools and our children’s futures, and shows our children that they matter.’

Energy Secretary Ed Miliband said: ‘Our local power plan will build on this success so that by 2030, every community in the UK will have the opportunity to own and benefit from a local energy project.'

India claims title of biggest wind market outside mainland China for first time

Project developers brought 169 GW of wind turbines online across the world last year, 38% more than in 2024, marking a third straight year of record installations, according to BNEF’s latest sector analysis. Some 161 GW, or 95%, of global wind additions were onshore, while 8 GW was installed offshore. Mainland China’s onshore wind sector underpinned most of the growth in 2025, becoming the first market to add over 100 GW in a single year.  

Outside mainland China, new additions increased 17% year-on-year to 43 GW. ‘For the first time since wind power emerged as a major global force, India edged out the US and Germany to claim the title of biggest wind market outside mainland China,’ according to BNEF.  

‘India fully deserves its place as the second-largest wind market in the world [after China],’ said Siddharth Shetty, BNEF’s Lead Wind Analyst for India. ‘The sector is reaping the rewards of complex auctions, pioneered by India’s clean power auctioning agencies in 2018. And this momentum is not fading. We expect wind build to continue at similar levels through the end of this decade.’ India’s auctions typically require developers to integrate multiple renewable technologies or oversize projects beyond their contracted capacity, particularly in wind.

Meanwhile, Chinese brands dominated BNEF’s league table of the world’s main turbine suppliers, for the first time holding the top six places in its Global Wind Turbine Market Shares ranking (see Fig 1). Goldwind maintained its position as the world’s leading wind turbine supplier, installing 29.3 GW in 2025, 12% of which was installed outside mainland China. Envision retained second place with 20.9 GW, almost a quarter of which was outside mainland China. Mingyang (18.9 GW) and Windey (18.4 GW) followed, while Sany and Dongfang Electric rounded out the top six with around 13.5 GW each.

‘Thanks to stable long-term policy support, wind installations over the past decade have become increasingly concentrated in mainland China,’ commented Cristian Dinca, Wind Associate at BNEF and lead author of the report. ‘Chinese manufacturers consistently top the global rankings. They benefitted particularly in 2025 as companies and provinces rushed to commission projects ahead of power market reforms and to meet targets set out in the Five-Year-Plan.’

Chinese turbine makers continued to rely heavily on their home market, according to the report, with domestic installations accounting for 93% of all capacity added by these players in 2025. However, BNEF notes that this marked a ‘notable drop’ from 99% in 2024, ‘indicating the export push is starting to pay off’. Envision and Goldwind led on non-domestic commissioned capacity.

‘This moment marks the emergence of Chinese manufacturers as true global players, as their commissioned capacity abroad has increased eightfold over the last year,’ said Oliver Metcalfe, Head of Wind Research at BNEF. ‘Challenged by razor-thin margins at home, Chinese suppliers are leveraging lower-cost production and fast delivery to enter new markets and undercut established rivals across Latin America, the Middle East, Africa and Asia.’

Danish turbine manufacturer Vestas retained its position as the largest supplier of commissioned projects outside mainland China. However, it slipped to seventh overall in 2025 (10.6 GW) in BNEF’s survey, the first time Vestas has been out of the top five since BNEF began publishing its rankings in 2013. The firm had the widest exposure of any turbine maker last year, commissioning projects in 28 markets, according to BNEF.

The wind unit of Germany’s Siemens Energy topped the offshore market for the second year in a row, edging out Chinese turbine manufacturer Goldwind, with Mingyang in third place. India’s Adani secured 15th place in the ranking.

Fig 1: Top 15 global wind turbine manufacturers in 2025, in GW

Note: SEWPG = Shanghai Electric Wind Power Group

Source: BloombergNEF 

Wind turbine firsts for Envision in the Philippines

China’s Envision Energy has reported that the first 8 MW wind turbine for the 64 MW Alabat wind project being developed by Alternergy Wind Holdings has been installed on Alabat Island in the Philippines. It is Envision’s first wind power project in the country. With a 182-metre rotor diameter, 105-metre hub height and 90-metre blade length, it is also the largest wind turbine to delivered by the company in international markets to date, says Envision.

‘This project marks several technological breakthroughs for Envision, including the deployment of our anti-typhoon turbine design, segmented tower installation [the turbine tower was divided into smaller segments for transportation] and the first direct barge delivery of wind turbines from China to an international market,’ commented Chou De Loh, Country Manager, Philippines at Envision Energy.

The turbine features integrated backup power systems compliant with international typhoon design standards and reinforced components across the blades, pitch and yaw systems, bearings and other structural elements. It is also equipped with control algorithms capable of boosting power output during high-wind typhoon events, while maintaining operational safety, reports the company.

The project reflects the Philippines’ broader ambition to increase renewable energy’s share in the national power mix to 35% by 2030 and 50% by 2040.  

According to the Energy Institute’s Statistical Review of World Energy (2025), renewables had a 22% share of the 2024 power mix, making up 28.3 TWh of a total 129.9 TWh of power generation in the Philippines.  

Wind energy currently plays a relatively small role in the country’s energy mix, with wind contributing 1.3 TWh from 443 MW of installed wind turbine capacity in 2024, according to the Statistical Review, all of it onshore. However, the government is seeking to accelerate wind development, launching its first offshore wind auction programme earlier this month. The initial focus is on fixed-bottom offshore wind projects, with a target of deploying 3.3 GW of offshore capacity between 2028 and 2030.

UK government scraps tariffs on wind turbine components

Meanwhile, in the UK, the government has announced plans to remove or reduce import tariffs on 33 categories of goods used in the production of wind energy infrastructure from 1 April 2026.

The measure is intended to strengthen the UK’s offshore wind supply chain and lower costs for domestic manufacturers.

The tariff changes will operate through an authorised use system allowing companies ‘to pay reduced or zero customs duties on imported components, provided the goods are used for specific manufacturing purposes within a defined timeframe’.

Eligible items include materials and components used in the production of cables, rotors, rotor blades and auxiliary electrical systems used in wind turbines and substations.

Industry representatives welcomed the announcement as a practical step towards improving the economics of renewable energy projects.

‘This is a very positive move for the industry – it’s exactly the kind of practical policy change that will help to bring down the cost of clean energy projects while supporting domestic manufacturing,’ said Celestia Godbehere, Head of Offshore Wind at trade association RenewableUK.  

John Haw, CEO of Fidelity Energy, a power offtaker for large UK commercial and public sector customers, added: ‘Lower component costs do not compress power purchase agreement pricing in the short term. But they do improve the underlying economics of future build, which matters a great deal for the volumes of firm renewable capacity that need to come online over the next decade.’

The tariff changes follow a record-high 8.4 GW of offshore wind capacity secured earlier this year under the government’s latest Contracts for Difference (CfD) Allocation Round 7 (AR7).

The hydrogen produced is expected to be blended into the existing natural gas pipeline operated by Enagás. At a later stage, hydrogen from the site could also be injected into the planned H2Med hydrogen pipeline backbone, which is expected to pass through the region.

The initial phase will pair a 5 MW DWE electrolyser with 10 MWp of solar generation connected directly through a DC-to-DC configuration. Future phases could expand the project to as much as 80 MWp of solar capacity alongside the planned increase in electrolysis capacity.  

The project aims to tackle the persistently high levelised cost of green hydrogen generation. According to the developers, many conventional electrolysers were designed to operate under steady baseload power conditions rather than variable renewable generation. Running these systems on fluctuating power can lead to membrane degradation, gas crossover risks and reduced efficiency at partial loads. As a result, many projects rely on grid electricity or battery storage to stabilise operations, increasing overall costs.  

However, H2Pro’s DWE technology is designed to operate under variable power conditions and in off-grid environments. According to the company, the DWE system can be switched on and off repeatedly without the degradation penalties associated with conventional electrolysis technologies. It can also operate efficiently across a wider load range and ramp output quickly, allowing hydrogen production to follow the generation profile of renewable sources such as solar or wind.

Extremadura is among the regions with the highest solar irradiation levels in Europe, making it well suited for large-scale renewable energy and hydrogen production.

Across all three technologies, China continues to dominate, representing 93% of cumulative global deployment, driven by strong government policy support including provincial mandates and the Special Action Plan for Development of New Energy Storage (2025–2027).  

‘Despite impressive installation growth last year, LDES technologies are caught in a strategic squeeze,’ said Jiayue Zheng, Managing Consultant, Wood Mackenzie. ‘Lithium-ion batteries have captured the economically critical four to eight-hour storage market through superior cost and supply chain advantages, while the LDES lacks sufficient demand and pricing mechanisms to achieve commercial viability.’  

Under Wood Mackenzie’s net zero scenarios, the global average energy storage duration must increase from 2.5 hours to around 20 hours. As countries like Germany, Australia and Denmark push for variable renewable energy beyond 50% by 2030, wider deployment of LDES will be critical for grid reliability.  

However, LDES comprises only 6% of 2025 global energy storage installations. While lithium-ion battery projects typically provide an average of two hours of storage, VRFB and CAES average about four hours and thermal storage around eight hours.  

The report highlights that revenue certainty for proposed projects is strongest in the UK, Italy, the US and Australia, with technology-specific procurement also emerging in markets like Spain, Ireland and Germany. However, most markets lack capacity mechanisms, and multi-day arbitrage alone cannot justify LDES investment, say the report’s authors, referring to ways that electricity storage capacity is bought and sold.  

According to the report, global funding for LDES declined by 30% year-on-year in 2025, excluding the US Department of Energy’s $1.76bn loan guarantee to Hydrostor’s Willow Rock Energy Storage Center, a 500 MW CAES project in Rosamond, California. Venture capital investment fell even more sharply, dropping by 72% and placing increasing financial pressure on a growing number of LDES start-ups.  

Between 2021 and 2025, only three companies – Hydrostor, EOS Energy and Form Energy – raised over $1bn in funding each, collectively raising over $4bn. However, even well-funded companies continue to face significant financial challenges.  

The report attributes the difficult investment environment to several factors, including persistently high interest rates that make long-payback LDES projects less attractive, intensifying capital competition from rapidly expanding AI data centres and grid infrastructure investments, and declining lithium-ion battery prices that are reducing the  economic advantage of LDES technologies.  

In China, four-hour lithium-ion battery projects cost $107/kWh, while thermal energy storage and CAES, the least expensive LDES options, cost $190/kWh and $201/kWh respectively, representing cost premiums of 78% and 88%. These cost differentials limit LDES competitiveness in shorter-duration markets, the report found.

‘VRFB project costs are projected to fall by over 30% by 2034 but will still be about 240% higher than lithium iron phosphate battery projects for four-hour duration,’ said Priya Shrivastava, Research Manager, Wood Mackenzie. ‘The dramatic cost reductions lithium-ion achieved over the past decade will be difficult for emerging LDES technologies to replicate.’

Wood Mackenzie expects lithium-ion batteries to hold 85% market share through 2034, with VRFB and CAES capturing just 5% and 3% respectively. Meanwhile, the sector faces a critical challenge: lithium-ion manufacturers have expanded into long-duration products, effectively dominating the four to eight-hour storage market through superior cost competitiveness and established supply chain networks exceeding 1,000 GWh of capacity.  

Demand for the multi-day storage segment remains limited, as two to eight-hour systems already cover 90% of storage needs. Multi-day discharge events occurring fewer than 10 days per year in most regions, according to the report.

Most large-scale LDES projects from leading manufacturers are under development globally, including Highview’s 50 MW/300 MWh liquid air energy storage project in the UK, Energy Dome’s 20 MW/200 MWh CO₂ battery in Italy, and multiple GWh-scale CAES and thermal projects across China. But moving from demonstration to commercial scale deployment will remain challenging without key market design reforms, the report found.

Fig 1: Global annual installation capacity of LDES, 2022–2025

Note: Considering the general duration of existing projects, our installed capacity encompasses all emerging LDES technology projects with all duration while excluding lithium-ion battery and pumped hydro storage

Source: Wood Mackenzie 

The think-tank notes that China currently stands at a ‘critical juncture’, with emissions growth slowing as renewable energy increasingly meets new electricity demand. It adds that there is still a large pipeline of new coal power projects under development and progress in industrial decarbonisation has been ‘limited’.

Clean energy expansion remains central

Despite these concerns, the plan places heavy emphasis on clean energy as both a climate solution and a driver of economic growth, says CREA.

A new action plan aims to double the use of non-fossil energy over a 10-year period. If interpreted as doubling total non-fossil consumption between 2025 and 2035, the goal could prove more ambitious than China’s existing targets of 25% non-fossil energy by 2030 and 30% by 2035, suggests CREA.

The plan also reiterates the previous five-year plan’s goal of building a ‘new-type power system’ capable of integrating large volumes of variable wind and solar power. Key components include large-scale energy storage, smart grids, interprovincial electricity trading and expanded long-distance transmission.

Battery energy storage is expected to expand rapidly, alongside 100 GW of pumped-hydro storage capacity.

Beyond electricity generation, the plan identifies hydrogen and nuclear fusion as potential future growth sectors, reports CREA. Hydrogen development will focus on building infrastructure and integrating the fuel into industrial processes, transport and energy systems.

China also intends to continue developing large renewable-energy bases, including the desert mega-projects in the country’s north-west that have driven solar and wind growth over the past five years. The new plan also highlights projects in hydropower-rich south-western provinces that combine solar, wind and hydroelectric generation.

However, CREA notes that the plan provides limited detail on the scale of renewable expansion required in the near term. It notes that China has already surpassed its previous target of 1,200 GW of wind and solar capacity, reaching the milestone in 2024. A longer-term goal of 3,600 GW by 2035 implies average additions of about 200 GW/y, says the think-tank.

CREA adds that if electricity demand continues to grow rapidly – particularly due to electrification and expanding manufacturing – annual additions closer to 300 GW may be needed to maintain progress toward China’s climate goals.

Carbon intensity target raises questions

CREA suggests the new five-year plan sets a less strict carbon intensity target than for the previous five years, potentially allowing emissions to increase over the period 2026–2030. Instead, it says the plan focuses on accelerating the deployment of clean energy and related technologies, with the expectation that falling costs and expanding supply will eventually drive emissions downward rather than focusing on strong, measurable emission targets.  

CREA argues that the new 17% carbon intensity reduction target is weaker than what would be required to keep China on track with its international climate commitments of peaking carbon emissions before 2030 and achieving carbon neutrality by 2060. It is also slightly lower than the 18% reduction target set for the previous five-year plan covering 2021–2025.

According to CREA’s analysis of official statistics, China’s annual carbon-intensity improvements during 2021–2025 add up to a reduction of about 12.4%, leaving the country behind the trajectory needed to meet the pledge made by President Xi in 2021 to reduce carbon intensity to a figure which is 65% below the 2005 level by 2030.  

However, the new plan states that carbon intensity fell by 17.7% over the past five years. CREA says the difference appears to result from China’s revisions to historical data rather than a sudden improvement in emissions performance. The definition of carbon intensity has also been broadened under the new plan to include industrial emissions alongside energy-related emissions, which could make reductions appear larger, particularly as cement production declines alongside China’s struggling real-estate sector, suggests CREA.

The implications are significant. ‘The 12.4% carbon intensity drop reported in annual statistical communiques, combined with reported GDP growth, implies that CO2 emissions went up by 13% from 2020 to 2025. Whereas if carbon intensity fell 17.7%, then that implies that emissions only went up 6%,’ explains CREA.

According to the think-tank, the 17% carbon intensity reduction target could see China’s CO2 emissions increase by roughly 3–6% between 2026 and 2030 if economic growth averaged around 4.5–5% per year.

For 2026 alone, the plan’s 3.8% carbon-intensity reduction target could allow emissions to grow by roughly 0.5–1% under similar economic conditions, it notes.

CREA adds that the plan describes 2026 as the first year of China’s transition from controlling total energy consumption to controlling carbon emissions. However, the document includes only an intensity target and no cap on total emissions, leaving uncertainty over how the new system will work in practice, it says.

[Last year, as reported in New Energy World, China set new 2035 targets to reduce absolute, economy-wide greenhouse gas emissions by 7–10% from peak levels.]

Mixed signals on coal

Another area highlighted by CREA is the plan’s ambiguous language around coal. The draft calls for ‘promoting the peaking of coal and oil consumption’, which CREA says represents a step back from earlier statements by President Xi that suggested coal use would gradually decline.

Instead of committing to a reduction, the plan appears to target a plateau instead, reports CREA, ‘specifically leaving space for coal consumption in the power and chemical sectors to grow past the targeted peak of overall coal consumption’. It also says the plan did not confirm earlier suggestions by Chinese state media that coal consumption would peak by 2027 and oil by 2026.

The document also refers to ‘strengthening the clean and efficient utilisation of fossil energy’, wording that CREA says is often associated with continued development of the coal-to-chemicals industry, one of the more carbon-intensive parts of China’s industrial sector.

Furthermore, while the plan mentions replacing 30mn tonnes of coal consumption each year with cleaner alternatives, CREA notes that this figure is relatively small compared with China’s overall coal use, which is more than 100 times bigger at about 3.17bn tonnes in 2025.

The think-tank also highlights the absence of binding caps on coal use in the power sector or a clear timeline for phasing out older coal plants. Previous five-year plans included language calling for ‘reasonable control’ over coal power expansion, but that wording is missing from the new draft, it says.  

New push for industrial decarbonisation

The plan also introduces several initiatives aimed at reducing emissions in industry and transport.

One major proposal is the development of zero-carbon industrial parks, where factories would be powered directly by clean electricity and supplied with green hydrogen.

Another initiative is the creation of zero-carbon transport corridors along major freight and passenger routes. These would feature extensive fast-charging and battery-swapping infrastructure to support electrified vehicles.

CREA says these measures signal growing momentum in efforts to decarbonise sectors beyond power generation.

To read CREA’s analysis in full, go to https://energyandcleanair.org/chinas-15th-five-year-plan-implications-for-climate-and-energy-transition/ 

Based on my A-level subjects, Environmental and Natural Resource Management was the degree programme I was qualified to pursue locally, so I began there with the idea that I might eventually transition into the oil and gas sector. However, during my studies I found myself becoming increasingly interested in environmental sustainability and natural resource management, and I quickly realised that this was a field I was genuinely passionate about.

That search led me to energy management, which immediately caught my attention as a field that combined environmental thinking with practical energy use and efficiency.

After graduating, I briefly worked in the aviation industry as a flight attendant, but it quickly became clear that it wasn’t the career path I wanted to pursue.

At the time there were very few environmental roles available in Trinidad, so, like many of my classmates, I began looking at postgraduate options. While I was flying with Caribbean Airlines, I started an energy management MSc programme and realised that this was where my interests truly lay. Soon afterwards I joined Energy Dynamics in Trinidad.

My boss, Andre Escalante, was, and still is, a leading figure in energy efficiency work across the Caribbean. He played a major role in shaping my early career. He trained a small team of us – including two other female engineers – and that experience laid the foundation for everything that followed.

Some of my best early professional experiences were conducting energy audits in hotels across the Caribbean, particularly in Barbados. Those projects were incredibly hands-on and gave us the opportunity to learn quickly. One of my colleagues, an electrical engineer who has since become a close friend, taught me a great deal about the technical side of energy auditing as we worked through those projects together. That was the point where I knew I had found my place in the energy management field.

Q: How did you first hear about the Energy Institute (EI) and what motivated you to join?
I first learned about the Energy Institute while studying for my MSc in Energy Management. At the time, it was clear that the EI represented the leading professional body for energy professionals globally.

What motivated me to join was the opportunity to work toward Chartered Energy Manager status and to be part of a professional community that values technical knowledge, best practice and continuous development within the energy sector.

Early in my career I was focused on building both technical knowledge and credibility within the field. Energy management covers a wide range of disciplines, from engineering and data analysis to policy and carbon management, so professional recognition was important.

Q: Tell us about your current job and industry, and how your work is contributing towards a just transition to net zero? 
In 2015, after gaining several years of experience in the field (and following a second MSc degree, in environmental engineering), I achieved Chartered Energy Manager status and became an ESOS Lead Assessor through the Energy Institute. It was a significant milestone for me professionally and gave me confidence that I was progressing in the right direction within the industry.

With that, I started working in Scotland supporting organisations with ESOS compliance. I then moved into higher education, working at the University of Oxford and later at King’s College London, before transitioning into healthcare estates within the NHS. Experiencing energy use across such different sectors and regions has given me a broad perspective on how organisations approach energy management and the importance of tailoring solutions to each environment.

Becoming a Chartered Energy Manager and ESOS Lead Assessor through the Energy Institute significantly strengthened my professional credibility within the sector. Employers and organisations recognise the level of experience and knowledge required to achieve chartership.

I currently work as Energy Manager at Oxford University Hospitals NHS Foundation Trust, where I am responsible for managing energy performance and supporting the Trust’s journey toward net zero.

The NHS has ambitious net zero targets and hospitals are particularly complex, energy-intensive environments. My work focuses on improving energy performance across the estate through better data, monitoring and operational improvements.

One of the key areas I have been working on recently is strengthening the Trust’s energy management framework and preparing the organisation for a ISO 50001 certification pilot, focusing on a single site that is fully managed by the Trust and does not have PFI [private finance initiative] involvement. This allows us to establish the foundations of an energy management system in an environment where we have clearer operational control.

My work has focused on strengthening the key elements required for an effective energy management framework. This has included updating the Trust’s energy policy, improving governance and reporting structures, and strengthening how we monitor and analyse utility data across the estate. A major component of the work has been improving data visibility.

One piece of advice I would give aspiring energy managers is to keep track of the achievements and projects you contribute to throughout your career. There will be times when progress feels slow, but reflecting on those milestones can remind you how far you have come and help you stay motivated.

Q. Having acquired the Chartered Energy Manager qualification, you then went on to acquire the American Certified Energy Manager qualification. First, what attracted you? And what processes did you follow, and what value did you gain from each?
 

I actually first attempted the Certified Energy Manager qualification relatively early in my career. Looking back, it was probably a little too early, and it was certainly a humbling experience. The breadth and depth of technical knowledge required for the examination quickly showed me that I still had a great deal to learn.

That early experience stayed with me and became something of a professional goal. As my career progressed and I gained more practical experience, I returned to the qualification with a much stronger foundation. Passing the four-hour CEM examination later in my career was a challenge I was genuinely proud to overcome.

The Chartered Energy Manager route through the Energy Institute and the CEM certification through the Association of Energy Engineers take slightly different approaches. Chartered Energy Manager status focuses on demonstrating professional experience, competence and contributions to the profession through a detailed assessment of one’s career. The CEM certification, on the other hand, is heavily examination-based and tests a wide range of technical energy management knowledge.

Both qualifications are valuable in different ways. Chartered Energy Manager status is widely recognised within the UK energy sector and demonstrates professional maturity and experience. For me, the two together reflect both practical experience and technical knowledge developed over the course of my career.

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 Omega’s footsteps, click here to find more about how to become a Member of the Energy Institute (MEI). For more information about becoming a Chartered Energy Manager, click here.
 

Increasingly, governments are approaching energy policy through a broader lens in which national security becomes the overriding objective, supported by three key pillars: resilience, diversification and controllability. This emerging paradigm could be described as ‘the new energy trilemma’.

From energy policy to strategic security 
Recent global events have accelerated this shift in thinking. The weaponisation of energy supply during geopolitical conflicts, volatility in global fuel markets, and growing competition over critical minerals and energy technologies have highlighted the vulnerabilities embedded in modern energy systems. At the same time, the energy transition itself is creating new forms of dependency. Clean energy technologies – including batteries, solar modules, wind turbines and electrolysers – rely on supply chains that are often concentrated in a small number of countries. The materials required to produce these technologies, such as lithium, cobalt, nickel and rare earth elements, are also geographically concentrated.

The result is a paradox: while the transition to low-carbon energy promises long-term sustainability, it also introduces new strategic vulnerabilities. Governments are therefore beginning to rethink the design of their energy systems not only in terms of emissions reduction or cost efficiency, but also in terms of system resilience and strategic autonomy.

Resilience: designing energy systems that withstand disruption 
Resilience refers to an energy system’s capacity to withstand shocks, adapt to disruptions and recover quickly from unexpected events. These disruptions can take many forms – supply interruptions, infrastructure failures, cyber-attacks, extreme weather events or geopolitical conflict. Resilient energy systems are built with redundancy and flexibility. They avoid single points of failure and incorporate a diverse mix of infrastructure and technologies that keep systems functioning even when parts of the network are compromised.

Increasingly, resilience is being enhanced through distributed energy systems, battery storage, microgrids and digital monitoring technologies that allow operators to anticipate and respond to disruptions in real time. The shift toward decentralised and flexible energy architectures reflects a broader recognition that future energy systems must be capable of absorbing volatility rather than assuming stability.

Diversification: reducing strategic dependency 
Historically, diversification referred primarily to balancing different fuel sources – coal, oil, gas, nuclear and renewables. While this remains important, the concept today has evolved into something much broader. Diversification now encompasses technologies, supply chains, geographic sources of energy and infrastructure pathways. In an increasingly uncertain geopolitical environment, this broader approach is essential for reducing systemic risk. When energy systems depend heavily on a single supplier, fuel, technology or trade route, they become inherently vulnerable to disruption. By spreading risk across multiple sources and systems, countries can significantly strengthen their overall energy security.

This principle is already shaping energy policy. Governments are seeking to diversify sources of critical minerals, develop multiple supply routes for natural gas and electricity, and support a wider portfolio of low-carbon technologies rather than relying on a single technological pathway.

Diversification is therefore emerging as a form of strategic insurance, ensuring that disruption in one part of the energy system does not cascade across the wider economy.

Controllability: retaining sovereign influence over energy
Controllability includes the ability to manage supply reliability, maintain operational stability and exercise strategic oversight over key infrastructure, technologies and supply chains.

In an increasingly uncertain geopolitical environment, controllability is becoming a central consideration for governments. Energy systems underpin economic activity, industrial production and national resilience. Without sufficient control over these systems, countries risk becoming dependent on external actors whose political or economic interests may diverge from their own.

Over the past several decades, the global economy has become accustomed to relying heavily on internationally traded energy commodities. Looking ahead, the world may gradually evolve towards a more regionally diversified energy landscape, where local and regional energy systems play a greater role in meeting both societal and industrial demand.

Importantly, this perspective also highlights the need to draw much closer connections between energy systems, economic strategy and environmental objectives. Too often, discussions around climate action and economic development are treated as separate policy conversations. In reality, the transition now underway demands a far more integrated approach – one in which energy policy, industrial competitiveness, resource efficiency and environmental stewardship are addressed together within a coherent strategic framework.

In this context, controllability becomes not simply a question of infrastructure ownership or system management, but a broader capability: the ability of nations and regions to shape energy systems in ways that support long-term economic resilience, industrial development and environmental sustainability simultaneously.

Implications for the global energy transition 
The emergence of the new energy trilemma has profound implications for how energy systems are designed and financed. Energy policy is becoming more closely aligned with industrial strategy and national security planning. Governments are investing heavily in domestic infrastructure, encouraging local supply chains, and strengthening regional energy cooperation.

The shift is also influencing how new industrial zones and infrastructure projects are developed. Increasingly, major industrial clusters are being designed as integrated energy ecosystems, combining renewable power generation, storage, flexible demand, hydrogen production, carbon management and digital energy optimisation.

These ecosystems enhance resilience, diversify supply pathways and improve system controllability – making them attractive platforms for both industrial investment and national energy security.

The global energy transition is still fundamentally about decarbonisation. But it is increasingly also about strategic resilience. In a world characterised by geopolitical competition and supply chain uncertainty, energy systems can no longer be designed solely around cost and emissions. They must also be capable of supporting national stability, economic competitiveness and technological sovereignty. 
 

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 global logistics cannot afford to ignore Gulf instability.’ With the push for battery-electric road transport transition solutions, alternative sustainable and waste-based fuels are underestimated, despite their bridging and complementary advantages, argues Matthias Maedge, Vice President, Commercial Road Transport Decarbonisation, at mobility and payment solutions company Eurowag.
• ‘Tomorrow’s benefits and today’s problems: CEOs agree to disagree at International Energy Week’. Discover how senior leaders of oil and gas majors and utilities differ in their perspectives about the importance of the transition away from oil and gas, and the relationship between the transition and energy security.

On 10 March, at a meeting of G7 energy ministers, he said: ‘In oil markets, conditions have deteriorated in recent days. In addition to the challenges of transit through the Strait of Hormuz, a substantial amount of oil production has been curtailed. This is creating significant and growing risks for the market.’

IEA member countries currently hold over 1.2bn barrels of public emergency oil stocks, with a further 600mn barrels of industry stocks held under government obligation, he said on 10 March.
 

According to an IEA report, the war in the region that began on 28 February has impeded oil flows through the Strait of Hormuz between the Persian Gulf and the Gulf of Oman, with export volumes of crude and refined products currently at less than 10% of pre-conflict levels of 20mn b/d of crude oil and oil products. The Strait is the primary export route for oil and natural gas produced by Saudi Arabia, the United Arab Emirates (UAE), Kuwait, Qatar, Iraq, Bahrain and Iran.  

Its closure is forcing operators across the Gulf region to shut in or curtail a substantial amount of production. The region’s output of LNG has also been significantly impacted.

It said that oil and natural gas prices have spiked since the start of hostilities. Brent crude futures climbed by 35% through 9 March, and Dutch TTF, the European benchmark for natural gas, was up by 75%. Moreover, some markets for oil products have been particularly affected, including those for diesel and jet fuel.

While global oil inventories were high in 2025, natural gas supply was tight in early 2026. An extended loss of output from the Ras Laffan facility in Qatar could significantly exacerbate this market tightness, said the report. Production was shut down following an attack on the facilities on 2 March. In 2025, Ras Laffan produced 112bn m3 of LNG, as well as 300,000 b/d of liquefied petroleum gas (LPG) and 180,000 b/d of condensate, making it the largest LNG facility in the world by some distance.

About 93% of Qatar’s and 96% of the UAE’s LNG exports transited through the Strait, representing almost one-fifth of global LNG trade, according to the IEA.

An average of 20mn b/d of crude oil and oil products transited the Strait of Hormuz in 2025, or around 25% of the world’s seaborne oil trade. Oil and LNG markets would face significant supply disruptions if shipping through the Strait is interrupted for an extended period. Options for oil flows to bypass the Strait of Hormuz are limited, the IEA said.

And that’s not all. Fertiliser supply is particularly exposed. More than 30% of global trade of urea moves through the Strait, along with about 20% of trade of ammonia and phosphate. This creates risks for food prices and security.

UPDATED: Article was updated with new information on 11 March 2026.

Efficiency has already counterbalanced rising energy demand from driving. New fossil-fuelled vehicles sold today are around 25% more efficient than those sold 15 years ago.

However, the biggest efficiency opportunity lies in transitioning from fossil combustion to electric cars. Electrification can sustain rising mobility demand, while reducing dependence on imported fuels and lowering the lifetime cost of car ownership. Through electrification, travel demand can rise by 70% by 2050, as energy inputs fall by 80%.

Electrification delivers structural efficiency
Electric vehicles (EVs) are fundamentally more efficient than fossil combustion engines. Internal combustion engines (ICEs) convert only 20–30% of fuel inputs into motion; the rest escapes as heat. In contrast, an EV converts 75–90% of battery energy into movement and recovers some energy during braking.

Petrol and diesel cars can become marginally more efficient with lighter designs, speciality tyres and hybrid powertrains. In theory, these improvements could increase efficiency by up to 50%, the ETC estimates. But even hybrid cars retain much of the mechanical complexity and fuel dependence of combustion systems and are unlikely to match the efficiency or economics of battery-electric vehicles.

At scale, that difference transforms road transport energy demand. The ETC estimates a fully petrol and diesel passenger fleet in 2050 would require roughly 19,000 TWh of final energy (fuel inputs after conversion losses). A fully electric fleet would need less than a third of that to travel the same distance. Each kilowatt-hour saved compounds across millions of vehicles.

Further efficiency gains are achievable with EVs when electricity comes from low-carbon sources instead of fossil fuels. Thermodynamics limit the efficiency of coal and gas power plants; they lose around 40–65% of energy in conversion to electricity, while over 90% of solar and wind energy converts directly into electricity through photovoltaic (PV) panels and turbines. Electrification links the transport and power sectors closer than ever.

Transport electrification should be treated as core infrastructure planning by the energy sector. Renewable generation needs to expand in parallel with charging demand, alongside reinforcement of transmission and distribution networks in cities and freight corridors. Permitting for fast-charging infrastructure should be streamlined, with clear connection standards and predictable revenue frameworks. Managed well, electrification lowers total system costs; managed poorly, it simply relocates congestion from roads to substations. Improving vehicle efficiency shapes how large this electricity system needs to become, and the long-term costs of running the car.

China’s scale sets the benchmark
China has deliberately prioritised production of highly efficient EVs at scale. Scale, in turn, reinforced cost reductions and innovation. In China, EVs are cheaper upfront than ICEs, and as a result, over 50% of new passenger car sales are now electric, Ember reports.

China’s policies helped to shape industry development targets by rewarding energy performance with fuel economy standards and EV subsidies structured to favour lighter, lower-energy models. In 2019, China’s New Energy Vehicle subsidy qualified for EVs that met maximum energy consumption thresholds of 13–15 kWh per 100 km. This helped to drive fleet-average electricity consumption to 12.1 kWh per 100 km by 2021, against a government 2025 target of 12 kWh per 100 km – noting that the smaller, lighter electric vehicles in China deliver lower average efficiencies compared to the global average.

China has treated road transport electrification as a system transformation rather than a simple product substitution. Vehicle manufacturing, battery supply chains, charging infrastructure and power sector expansion have progressed in parallel. This recognises the role EVs can play in supporting electricity system efficiency, acting as distributed batteries – storing electricity when supply is abundant and feeding power back to the grid during peak demand. This flexibility can be achieved with coordinated time-of-use tariffs, automated demand response and vehicle-to-grid systems. Managing peak electricity demand reduces overall grid investment needs.

China’s rapid EV growth is shaping the pace of global adoption. Chinese manufacturers are already scaling production and expanding exports. While this expansion helps to lower EV costs globally and accelerate the shift away from fossil-fuel vehicles, some countries have concerns about the competitiveness of domestic industries and potential supply-chain dependence. Several countries have been placing restrictions on their imports despite the cost opportunity.

A balanced response to this duality should recognise two realities. First, rapid and affordable electrification can enhance energy security by reducing reliance on fossil fuel imports and building flexible electricity. Second, domestic automotive industries face legitimate competitiveness challenges. The pragmatic response is neither blanket protectionism nor passive openness. Governments can welcome Chinese investment in local manufacturing through joint ventures, local content rules, workforce training and R&D commitments, so that production, jobs and capability are built domestically. At the same time, clear trade rules, transparency on subsidies and resilience requirements for critical minerals and batteries can address concerns about concentration and market distortion. The objective should be to combine speed of electrification with industrial resilience.

China’s rapid EV growth is shaping the pace of global adoption.

Driving greater value, with less energy inputs
Demand for road transport will continue to grow, but energy demand does not need to grow with it. EVs offer a structural improvement in energy efficiency and emissions reductions. Cleaner grids, better vehicle design and faster fleet turnover determine how much of that potential is realised. For energy companies, transport electrification demands accelerated grid decarbonisation and building charging infrastructure. For automakers, competitive advantage will hinge on efficiency, affordability and scale. China has demonstrated the power of sustained policy and industrial coordination. And in the end, the winning economies will be those who move more people and goods while using far less energy.

Note: This opinion is based partly on the Energy Transition Commission’s 2025 report The road ahead: electrification, design and mobility for efficient transport.

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 launches new EV campaign’. The UK Department for Transport has launched a public opinion campaign to encourage the adoption of electric vehicles by highlighting financial incentives and operational savings.
• ‘Powering the future: the need for smarter grid connections for EV charging’. As the UK decarbonises its transport network, it shifts the source of energy for vehicle propulsion from fossil fuel supply chains to the electricity grid. Find out why stations with batteries and on-site power generation are needed at scale for rolling out electric vehicle charging. What opportunities and challenges lie ahead?
   

‘This is an industry in decline; an exodus of talent is a good thing,’ said Jeremy Leggett speaking at the Life After Oil launch event on 11 February 2026. (He left BP 36 years ago; he’s now CEO of Highlands Rewilding and winner of the Blue Planet Prize 2025).

Reading through the 24 career transition stories on our website, it’s clear that many of us felt our work wasn’t in line with our values. There is a heavy weight of cognitive dissonance related to working for an oil and gas company when the climate crisis is so urgent. For many of us, that feeling lifted when we decide to leave.

Of course, people leave jobs all the time and awareness of the urgency of the climate crisis is nothing new, but this moment feels different to me. I think we’re seeing a change in sentiment from industry insiders who’ve lost trust in the system and loyalty to their employers, and are increasingly speaking out. So, what changed?

Back in 2020, a lot of people, including myself, believed in ‘driving change from within’. I bought into the story that because the climate crisis is so urgent, that we need to use the scale and resources of big business to mitigate carbon emissions. We felt that we had some traction as we influenced CEOs to take more progressive, long-term outlooks. Talking to friends who’ve also seen themselves as internal ‘change-makers’, they say they were hopeful because they saw the global scale of positive impact that was possible. Even the employees who aren’t particularly motivated by climate concerns, were able to feel proud – rather than ashamed – of telling people who they worked for.

But since 2023, the context has changed enormously. The politically-motivated environmental, social, and governance (ESG) backlash paired with high oil prices has led to a ‘drill baby drill’ mentality, and aggressive activist investors have jolted oil companies back to profit maximising business as usual. Despite company leaders not talking openly about why this has happened, it has become clear that the industry is stuck in an ‘economic reality’ that requires them to maximise short-term profits, no matter how dire the human or planetary cost. That is what led me to the conclusion that, at least at the moment, no amount of internal change-making efforts could counter that force.

This experience of backlash has been profound for many industry insiders. Whilst business can return to the status quo, I’m not so sure that’s true of people. When oil company CEOs talk about climate change, a lot of people wake up to the issue in a way that cannot be reversed. The hangover, when the company goes back to business as usual, is cognitive dissonance.

When we’re still inside these companies, it’s common to persuade ourselves that it doesn’t matter if we stay or go: ‘I’m only a small cog in a big machine. If I leave, I’ll only be replaced, so it might as well be me in the job. At least I’m someone that cares about the planet’. It almost sounds like we’ve accepted we don’t matter.

Well, you do matter! And I believe the work that you decide to do matters too! Whilst I believe the company that you leave won’t change as a result, the potential for doing something with positive impact lies in what you decide to do after you go.

Building the new 
The ancient Greek philosopher Socrates said: ‘The secret of change is to focus all of your energy, not on fighting the old, but on building the new.’

The reality is, it’s very difficult to figure out how you want to ‘build the new’ from inside a corporate job, when the silent influence of corporate culture is all around you and there’s no let-up from the incessant occurrence of emails and meetings. Leaving was the important first step for me, firstly to recover my health and energy, and then to figure out where I wanted to put my energy and creativity next, as well as reconnect with my allies… because none of us can do this work alone.

The American cultural anthropologist Margaret Mead said: ‘Never doubt that a small group of thoughtful, committed citizens can change the world; indeed, it is the only thing that ever has.’

As well as building the new, it’s important we grow our confidence and courage to speak up about where the old is failing us. A group of five current and 19 former employees of Shell are doing just that, using their influence as shareholders to co-file a resolution at upcoming AGMs at Shell and BP. They cite concerns about the companies’ long-term viability in scenarios where oil and gas prices decline, providing an alternative voice to the short-term investor pressure.

The Life After Oil community is not a campaigning organisation, but those who are keen to use their voice can tap into the community for support. I’d love us to find a way to use our influence. Together we have a more powerful voice and, as former employees, we have an insider perspective that policy makers, investors and industry leaders take more seriously.

If you would like to join our community, or you’re simply curious to find out more, we’d love to hear from you!

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: ‘Shining a Spotlight on Energy People: John Burnett FEI CEng’. Now based in Manama, Bahrain, John Burnett has come a long way from Didcot Power Station in Oxfordshire, which he first visited in boyhood. The CEO of Al Ezzel Power Company and Al Dur Power & Water Company reflects on his career journey and the benefits he has received along the way from participating in the Energy Institute.
• ‘Transitioning into offshore wind’. The oil and gas industry can prove a fine base from which to enter the growing offshore wind sector, writes Alastair Dutton, Co-founder of the online course provider Offshore Wind Learning. 
   

The other project partners were Emerald AI (a portfolio company of National Grid Partners), the US Electric Power Research Institute (EPRI), Dutch technology company Nebius and US ‘Big Tech’ company Nvidia. Over a five-day period, Emerald AI’s software platform, Emerald Conductor, was used to manage a cluster of 95 Nvidia graphics processing units (GPUs) operating at Nebius’ new London facility.

Today, most large data centres operate with fixed ‘always on’ electricity demand. ‘As AI adoption grows and more facilities seek to connect to the grid, that fixed-demand model risks increasing network constraints and lengthening connection times,’ explained National Grid. ‘Demonstrating the ability of data centres to flex their power demand shows how they can ease constraints and unlock grid capacity, rather than be an extra source of inflexible demand.’

Using real-time signals from the electricity system, the platform adjusted power consumption without disrupting critical workloads.  

The London trial delivered significant demand reductions in testing scenarios. In several cases, electricity consumption was cut by more than one third in less than a minute, with reductions reaching up to 40%. Crucially, the computing workloads running on the GPUs continued uninterrupted during these adjustments.

The project also tested the system’s response to simulated grid emergencies. During scenarios designed to mimic lightning strikes or power plant failures, the AI platform was able to shed approximately 30% of load within 40 seconds, helping to stabilise the grid and reduce the risk of wider blackouts.

Another important capability demonstrated was peak smoothing. The software successfully responded to sudden spikes in electricity demand, such as those that occur during major televised events, by temporarily reducing data centre load to counterbalance the surge in consumer electricity use.

The system also maintained sustained load reductions for up to 10 hours, a feature that could support grid operation during prolonged periods of system stress such as extended low-wind conditions or extreme heat.

‘The success of the trial demonstrates that AI data centres can move from being a source of electricity constraint to a controllable grid asset,’ said National Grid. ‘By flexing demand in real time, they can help manage peaks, make better use of existing infrastructure, and support the connection of different sources of energy to the grid.’

With more than 6 GW of data centre capacity expected to be deployed in the UK by 2030, the project partners estimate that power-flexible facilities could potentially make more than 2 GW of capacity available back to the nation’s electricity system when needed.

The performance data from the London pilot will inform future rules for so-called ‘power-flexible’ data centre connections. Such frameworks could allow facilities that agree to adjust their demand on request to secure faster or larger grid connections, say the project partners.

The new power-flexible reference design, if adopted nationwide, ‘could unlock an estimated 100 GW of additional capacity on the existing US electricity system’, according to the project partners. This would be roughly equivalent to one fifth of the country’s annual electricity consumption.  

The trial also provides a potential operational blueprint for a much larger project already under development in the US. Project Aurora, a 96 MW ‘AI Factory’ operated by Nvidia in Virginia, aims to ‘establish a reference design and certification standard for power-flexible AI infrastructure’, according to company and its project partners Emerald AI, EPRI, Digital Realty and PJM.

‘The Middle East’s energy transition reflects a fundamental tension between climate ambitions and economic reality,’ said Jom Madan, Principal Analyst at Wood Mackenzie. ‘Oil and gas remain central to national economies, and the region supplied 40% of global energy exports in 2025. While power generation has advanced rapidly with utility-scale solar deployment, deeper economy-wide decarbonisation will depend on policy follow-through and credible demand signals from trade partners.’

The outlook reveals stark contrasts in how countries are approaching the transition, largely driven by their remaining hydrocarbon reserves and economic vulnerability to energy transition risks.

Among the key findings, Oman (which is forecast to have approximately 20 years of oil and gas resources at current production levels) is found to be ‘pursuing the region’s most aggressive decarbonisation strategy’, according to Wood Mackenzie. The country is reported to be on track to exceed its 30% renewables target by 2030 and reach 89% by 2050. ‘Facing challenging geology and higher production costs than its neighbours, Oman is positioning clean energy and industrial diversification as economic necessities, not just climate commitments’, notes the outlook.

Qatar, with gas reserves exceeding 2,000tn ft3 and over 100 years of supply at current production, is reported to face ‘minimal transition pressure in the near term’. The country is doubling down on its LNG leadership, aiming to expand export capacity from 77mn t/y to 142mn t/y by 2032, says Wood Mackenzie. It also notes that ‘Qatar’s strategy reflects confidence in resilient long-term gas demand across all climate scenarios’.

Meanwhile, Saudi Arabia, with roughly 50 years of oil resources at current production, is said to be balancing both strategies – ‘scaling renewables to divert domestic crude consumption towards more valuable exports while continuing upstream expansion’. The kingdom aims for 50% clean power by 2030 but is tracking toward 20% in Wood Mackenzie’s base case.

The United Arab Emirates (UAE) is rapidly expanding both fossil fuel production and clean energy infrastructure simultaneously, finds the outlook. The country is forecast to exceed its 30% clean power target by 2030, but may fall short of its 47% emissions reduction goal by 2035.

‘The ambition countries show in reducing emissions depends on two factors: their reliance on hydrocarbon revenue and how their resources compare with other producers,’ noted Madan. ‘Producers with large, low-cost reserves face little pressure to transition quickly, while those with declining reserves see the shift as a strategic necessity.’

Power sector advances rapidly, while solar manufacturing emerges as major opportunity

Progress is most visible in electricity generation, where utility-scale solar is being deployed at a rapid pace, notes Wood Mackenzie. Regional installed solar capacity is projected to surge from 30 GW in 2025 to 97 GW by 2030, reaching 580 GW by 2050.

‘This domestic demand surge is attracting significant manufacturing investment, with solar production capacity expected to reach around 44 GW by 2028, positioning the Middle East as a global solar supply chain hub rivalling Southeast Asian centres,’ it adds. Key drivers are reported to include tariff advantages when exporting to major markets, domestic content requirements and abundant low-cost energy.

Battery storage is increasingly paired with renewables to manage peak demand, particularly as cooling and desalination needs rise with population and income growth, according to the outlook. While solar and wind generation are expected to meet most incremental demand, with their combined share of regional power supply rising from 14% in 2025 to approximately 67% by 2050.

Hydrogen emerges as strategic export opportunity

Beyond the power sector, hydrogen is increasingly being viewed as a cornerstone of the region’s long-term energy transition strategy.

According to Wood Mackenzie, the Middle East has significant potential to become a major exporter of low-carbon hydrogen and hydrogen-derived fuels such as ammonia, leveraging its abundant solar resources, existing energy infrastructure and proximity to key import markets in Europe and Asia.

Several countries in the region are already positioning themselves to capture a share of the emerging market. Saudi Arabia, the UAE and Oman are developing large-scale hydrogen projects aimed at supplying international demand, particularly for hard-to-abate sectors such as steel, chemicals, shipping and aviation.

However, the outlook cautions that hydrogen’s role remains highly uncertain. Production costs remain significantly higher than conventional fuels, and large-scale deployment will depend heavily on the pace of policy development, international demand and infrastructure investment in importing regions.

As a result, while hydrogen could eventually become an important pillar of economic diversification for hydrocarbon exporters, large-scale export markets may take longer to materialise than some current national strategies assume.

Oil and gas investment resurging despite climate targets

Meanwhile, despite ambitious climate commitments, oil and gas investment across the region is rising as supply security increasingly shapes national policy worldwide. National oil companies are expanding capacity and attracting international capital, positioning Middle Eastern exporters to maintain or increase global market share through 2050.

State-run oil companies continue to expand upstream capacity and LNG infrastructure, betting on resilient long-term demand and positioning natural gas as both a transition fuel and petrochemical feedstock. This reflects confidence that oil and gas will remain economically viable for decades, even as clean energy expands.  

Regional power demand to double by 2060

Power demand across the Middle East is projected to grow from approximately 1,450 TWh in 2025 to 1,650 TWh by 2030 (up 12%) and nearly 2,400 TWh by 2060.  

Growth will be driven by rising incomes and population, increased cooling requirements due to extreme heat, growing desalination needs to address water stress, industrial expansion in energy-intensive sectors, and emerging demand from data centres seeking low-cost, reliable power, says Wood Mackenzie.

Gas-fired generation will remain significant throughout the period, providing flexible capacity to balance variable renewable output and supporting emerging hydrogen production pathways, concludes the market analyst.  

To download the Executive Summary from Wood Mackenzie’s Middle East energy transition outlook, go to https://www.woodmac.com/market-insights/topics/energy-transition-outlook/eto-middle-east/

‘The UK is making undeniable progress in transforming its energy system, continuing to cement its place as a world leader in decarbonisation, but the pace is not yet aligned with climate ambitions,’ said Hari Vamadevan, Senior Vice President and Regional Director, UK & Ireland, Energy Systems, DNV. Vamadevan noted that the forecast now shows the UK running on ‘clean electrons by 2060’.  

Wood Mackenzie similarly highlights that while the UK has successfully halved energy-related emissions since 1990, the country has now reached ‘crunch time’, when nearly all 2030 transition targets are slipping out of reach.

Fossil fuels will represent 15% of the primary energy supply by 2060, a reduction from 75% today. Today, natural gas is 40% of primary energy supply – by 2060, this will reduce to about 8%, and 15% of that will be biomethane. DNV’s report also estimates that 14bn boe will still be required between now and 2060. Wood Mackenzie further notes that a ban on North Sea exploration has locked in a structural dependence on imports – by 2035, domestic production is expected to meet only 47% of oil demand and 21% of gas demand.

According to DNV, the 2030 Clean Power target will likely be missed as the UK continues to rely on unabated gas. While the country is expected to reach 107 GW of variable renewable capacity by 2030, the report estimates that the UK will still rely on unabated gas-fired generation for 15% of its electricity needs (reduced from 41% in 2023).  

Wood Mackenzie’s findings echo these predictions, projecting that gas will still generate 22% of the UK’s electricity in 2030 and 10% in 2035. It also expects that offshore wind capacity will increase from 17 GW today to more than 90 GW by 2060. Onshore wind installed capacity could increase nearly six-fold to 95 GW in 2060. However, Wood Mackenzie cautions that offshore wind deployment currently lags 20% behind government targets due to project delays and commercial constraints.

DNV states that the country requires ‘whole system thinking’ to address these gaps. ‘It is not a case of renewables versus oil and gas, it is not supply versus demand, and it is not generation versus transmission – it is all these facets combined to drive a cleaner energy future,’ stated Vamadevan. He cautioned that focusing narrowly on individual elements rather than the whole system risks stalling progress.

In the DNV report, buildings and transport are identified as the primary sectors blocking rapid decarbonisation. By 2035, two-thirds of UK homes are predicted to still use gas boilers. Furthermore, more than half of the cars on the road are expected to remain fossil-fuelled by that same year.  

Wood Mackenzie confirms this slow evolution, noting that transport still accounts for 72% of oil demand, while residential and agricultural sectors represent over half of gas demand.

Electricity demand from data centres is forecast to rise from 8 TWh today to 70 TWh by 2060. Total electricity generation demand is expected to grow by 15% by 2030, rising from 320 TWh/y to 370 TWh/y.  

DNV’s report highlights that by 2060, the UK will operate a fundamentally different energy system: renewables supported by nuclear will provide the vast majority of electricity, meeting 60% of final energy demand, and energy imports will reduce to just 15% of the total demand.

Sarah Kimpton, DNV’s Energy Transition Director and report co-author, said: ‘Addressing the energy trilemma and balancing the energy system demands integrated solutions that span technology, infrastructure, policy and behaviour.’ She added that Allocation Round 7 (AR7) demonstrated the ‘art of the possible’ when policy and business objectives align – a total of 14.7 GW was awarded across all renewable projects in this round. Kimpton noted that this success was due to ‘connected government policy and business objectives’.

Despite its prediction that the UK will miss its targets, DNV notes the UK remains a global leader in decarbonisation and in addition is moving faster than most other major economies. ‘If you compare the results to our global report, you will find the UK is much further ahead,’ Vamadevan said, with Kimpton adding, ‘we’ve had a 50% reduction in emissions already since 1990, so it’s not all bad’.

Regarding the impact of the conflict in the Middle East on these energy goals, Vamadevan acknowledged that ‘there will be very significant short-term consequences on the energy system’ and that ‘there will be shocks to the price of oil and gas’.  

The Wood Mackenzie report also said that geopolitical tensions and a ‘new world order’ are shifting focus towards domestic resilience and national security. ‘Defence spending and cost-of-living concerns are pulling resources away from climate initiatives and the climate-motivated energy transition is losing urgency. Yet domestic low-carbon energy has become central to UK autonomy and global influence, creating a strategic imperative that extends beyond emissions targets.’

DNV’s Vamadevan added: ‘I've been working in the energy sector for over 35 years and volatility of energy prices is not new.’ He agreed that the Middle East crisis could fundamentally shift the focus of the transition toward domestic resilience, noting that the war in the Middle East will bring resilience and security into sharp focus. However, he and Kimpton both suggested that such geopolitical events typically do not derail long-term decarbonisation, with Kimpton observing that ‘it is massive locally... but in terms of a global perspective, and in terms of our forecast, it really didn’t make a significant difference, because we’re looking in the long term’.  

Read the full reports: DNV's Energy Transition Outlook UK 2026, published March 2026, and Wood Mackenzie’s United Kingdom Energy Transition Outlook 2025.

The consortium behind the project is led by J-Power, which holds a 40% stake, alongside Kyuden Mirai Energy with 30%. The remaining shares are held by Hokutaku, Saibu Gas and Kraftia – formerly Kyudenko – with 10% each.

Kitakyushu Hibikinada surpasses the 112 MW Ishikari Bay New Port wind farm, which entered operation in January 2024 and had previously been Japan’s largest offshore wind installation.

Earlier this year (January 2026) Japan commissioned its first commercial offshore floating wind project, the 16.8 MW Goto City project in nearby Nagasaki Prefecture. Comprising eight Hitachi 2.1 MW turbines, Goto City employs a hybrid spar-type floater featuring a steel upper section and a concrete lower section.  

According to consortium partner Toda Corporation, the project is the world’s first commercial application of such hybrid spar-type floater technology. It also reports that Goto City is the first operational project to be developed under the government’s Act on Promoting the Utilization of Sea Areas for the Development of Marine Renewable Energy.

Other consortium members are Eneos Renewable Energy, Osaka Gas, Inpex, Kansai Electric Power and Chubu Electric Power.  

Call for strengthened government support  

While these projects highlight progress, industry groups say much stronger policy support will be needed if Japan is to realise its offshore wind ambitions. The Global Wind Energy Council (GWEC), Asia Clean Energy Coalition (ACEC) and the Climate Group RE100 initiative, have jointly urged the Japanese government to strengthen support mechanisms for upcoming offshore wind auctions.

In a letter to policymakers, the organisations have called for clearer and more predictable market frameworks, including appropriate ceiling and floor prices, indexation mechanisms covering the full operational period of projects, and a long-term decarbonisation auction system for offshore wind.

They argue that although Japan has set ambitious renewable energy targets, offshore wind deployment has so far struggled to scale. 

According to the government’s Seventh Strategic Energy Plan, released in February 2025, Japan aims to install 10 GW of offshore wind capacity by 2030 and 30–45 GW by 2040, including floating offshore wind farms. The Plan, which targets renewables providing 40–50% of electricity generation by 2040, sees wind expected to account for between 4% and 8% of power generation.

According to the Energy Institute’s 2025 Statistical Review of World Energy, Japan had 5.83 GW of total wind capacity in 2024.

Corporate demand for renewable electricity is also rising rapidly. According to RE100, more than 90 Japanese companies are now members of the initiative, yet only 36% of their electricity consumption currently comes from renewable sources, compared with a global RE100 average of 53%.

The letter warns that demand for clean electricity in Japan is already outpacing supply and suggests that large-scale offshore wind could provide one of the most effective ways to close that gap.

‘History is clear: no successful offshore wind market has emerged without early government support,’ says GWEC. ‘But once the first several GW of projects are underway, costs fall sharply; just as they have in mature markets across Europe, Asia and North America. Japan can follow the same path.’ 

The figures are published as the European Commission releases its Industrial Accelerator Act, which aims to strengthen clean technology manufacturing in Europe, including the production of heat pumps. Under the Act, hydronic heat pumps (where water is the heat carrier) will be required to originate in the European Union three years after the legislation enters into force.

Europe currently has the capacity to produce around eight million heat pumps per year, compared with about 2.5 million today. Commenting on the data, Paul Kenny, Director General, EHPA, said Europe’s 300 factories ‘could produce over three times more heat pumps if the demand was there’. He added that governments should remove taxes from electricity bills and introduce clear support measures for heat pump consumers, both of which are ‘crucial for spurring demand’.

European heat pump sales rise 10% in 2025

Heat pump sales across 16 European countries (Austria, Belgium, Czech Republic, Switzerland, Denmark, Spain, Finland, France, Italy, Netherlands, Norway, Poland, Portugal, Sweden, Switzerland and the UK) increased by an average of 11% in 2025, according to preliminary data from the EHPA. Around 2.62 million residential heat pumps were sold, up from 2.38 million in 2024, bringing the total number installed across Europe to approximately 28 million.

Twelve of the 16 countries – including the UK – installed more heat pumps in 2025 than in the previous year. According to the EHPA, this growth reflects governments stabilising subsidy schemes and implementing measures such as reducing tax on power bills. Such policies improve the competitiveness of heat pumps, which consume less energy than fossil fuel boilers.

For example, in Belgium, a combination of new restrictions on fossil fuel heating and a VAT reduction for heat pumps in new buildings contributed to a 7% increase in sales, reaching 111,000 units.  

In the UK, continued policy support through the Boiler Upgrade Scheme and the government’s Warm Homes Plan helped sales rise by 27% to 125,000 units.  

In Germany, heat pumps accounted for almost half of all heat generators sold last year. The EHPA attributes this to growing consumer confidence in the technology and increasing awareness of the role heat pumps can play in strengthening energy security.  

By contrast, sales declined in Poland and France in 2025. The EHPA cited the spread of disinformation about heat pumps in Poland and uncertainty around government budgets and support schemes in France as key factors.

Measured against population size, the biggest markets remain Norway, Finland and Sweden, each recording more than 30 heat pumps sold per 1,000 households. By that measure, Poland and the UK remain among the smallest markets, with fewer than five per 1,000 households.  

The EHPA is also collecting data on large heat pump sales – early indications suggest the market is growing, with increasing numbers of industrial facilities and district heating systems across Europe installing large-scale heat pumps.