The US and Israel’s war on Iran has caused oil and gas prices to soar, with the world now preparing for the possibility of another energy crisis.
The conflict, which has seen Iran respond with missile strikes across the region, has killed more than 1,000 people so far and sent global markets into disarray.
With shipping through the critical Strait of Hormuz paralysed and direct attacks by both sides on fossil-fuel infrastructure, some of the world’s biggest oil and gas facilities have paused production.
On 9 March, oil prices soared above $100 per barrel for the first time since Russia’s invasion of Ukraine in 2022, amid fears of long-term disruption to global energy supplies.
While US president Donald Trump has said that rising oil prices are a “very small price to pay” for “safety and peace”, the conflict is already pushing import-dependent countries to invoke emergency measures to protect consumers.
In this Q&A, Carbon Brief looks at how the war has disrupted energy supplies, the impact on oil and gas prices, which parts of the world are being hit hardest and what it could mean for efforts by some to transition away from fossil fuels.
- How has the Iran war disrupted energy supplies?
- How has the Iran war impacted oil and gas prices?
- Which parts of the world have been most affected by the crisis?
- What does the Iran war mean for efforts to transition away from fossil fuels?
How has the Iran war disrupted energy supplies?
On 28 February, the US and Israel launched a large-scale military attack on Iran, which has responded with counterattacks across the region.
On 2 March, Iran said that it would attack any vessel travelling through the Strait of Hormuz, a narrow waterway used to transport around a quarter of global seaborne oil trade and a fifth of the world’s liquified natural gas (LNG) supply.
According to the UK’s maritime security agency, UKMTO, around 10 vessels have been attacked in or near the Strait of Hormuz since Iran’s threat.
Ship traffic through the Strait of Hormuz has since come to a “virtual standstill”.
While Saudi Arabia and the UAE can reroute some of their crude oil production via pipelines to avoid the strait, Kuwait, Qatar and Bahrain have no alternatives, according to Bloomberg.
As a result of the effective closure, oil storage facilities in the region are filling up. Saudi Arabia has started to reduce oil production, as there is limited storage and limited export options due to the strait remaining closed to shipping, reported Bloomberg.
Other energy infrastructure has also been caught in the crosshairs of the conflict, leading to site closures at a number of oil and gas facilities.
For example, Iranian drones targeted the giant Ras Laffan gas facility in Qatar, which is responsible for about a fifth of global LNG supply. The QatarEnergy facility subsequently paused production and “will take weeks to restart”, reported Reuters.
Additionally, Saudi Aramco paused work at one of its refineries due to a fire caused by debris from an intercepted drone attack. One of the largest oil storage terminals in the UAE halted operations and a range of other energy sites across the Middle East have ceased operations.
The combination of the effective closure of the Strait of Hormuz and disruption to energy infrastructure in the region has led to oil and gas prices surging to their highest levels in several years.
How has the Iran war impacted oil and gas prices?
Global oil and gas prices have been rising since the first US and Israel attacks on Iran in late February.
On 2 March, the Guardian reported that Brent crude – the global oil price benchmark – had risen by up to 13%, standing at a “14-month high” of $82 (£61) a barrel.
Experts at that stage warned that a prolonged closure of the Strait of Hormuz could continue to push up prices and lead to a “1970s-style energy shock”, according to CNBC.
By Monday 9 March, oil prices had soared above $100 (£74) per barrel for the first time since Russia’s invasion of Ukraine in 2022.
Prices hit $119 (£88) a barrel at one point on Monday, as shown in the chart below, amid fears of long-lasting disruption to global energy supplies.
US president Donald Trump called rising oil prices a “very small price to pay” for “safety and peace”, reported the Independent.
By Tuesday 10 March, the Guardian reported that the price of a barrel of oil had “tumbled” to around $91.70 (£68), after Trump suggested the war could end “very soon”.
(The Islamic Revolutionary Guards Corps said it would “determine the end of the war”, not “American forces”, reported France24.)
The price of gas has also risen across Europe and Asia.
Prices “soar[ed”, reported Al Jazeera, after LNG production was halted by Qatar’s state-run energy company. (See: How has the war disrupted energy supplies?)
This led to gas price jumps “amid concerns about supplies”, said the New York Times.
Subsequently, the price of gas in Europe rose by up to 45% to around €46 (£40) per megawatt hour (MWh) on 2 March.
European gas price futures increased by as much as 30% on 9 March, according to Bloomberg. Prices stood at around €60/MWh (£52/MWh) compared to a past peak in 2022 of above €300/MWh (£260/MWh), said the outlet.
Bloomberg noted that “prices are still well below the records reached” after Russia’s invasion of Ukraine in 2022, as highlighted in the chart below.
Gas prices in Asia have more than doubled since 28 February, with some countries “struggling to find prompt” supplies.
In the UK, the price of gas has doubled since the start of the current conflict, although it has subsequently fallen back to around 75% above pre-crisis levels.
While domestic consumers are currently protected by the price cap for gas and electricity, some forecasts suggest bills could hit £2,500 a year – a rise of 50% – when the cap is updated in July. (There is currently no cap for consumers of heating oil.)
In the US, gas prices have only risen by 11% since the end of February, according to the Wall Street Journal. The US gas market is relatively insulated from global price spikes because it has limited export capacity. (The Wall Street Journal attributed this instead to “record” domestic production “cushioning” the country from the price jumps in other parts of the world.)
Meanwhile, the price of petrol (or “gas”, as it is known colloquially) in the US has increased by 19%, noted the New York Times. Even though the US is a net oil exporter, it is still affected by international price spikes, as the market for oil is globally interconnected.
The crisis has also raised the price of electricity, heating fuel, fertilisers, food and other products in many parts of the world.
Which parts of the world have been most affected by the crisis?
The impact of the Iran war has been felt around the world, in particular in areas reliant on oil and gas imports.
Below, Carbon Brief looks at how different regions have responded to the conflict so far.
Asia
Asia’s biggest economies are “highly dependent” on oil and gas imports that transit through the Strait of Hormuz, reported the Financial Times, adding that they are now “racing to secure new sources”. About 80% of all oil volumes through the strait go to Asia, according to the International Energy Agency (IEA).
East Asian nations, such as South Korea and Thailand, “have been hit especially hard” and have already announced measures such as capping petrol prices, according to BBC News. It said Vietnam plans to temporarily remove taxes on fuel imports and the Philippines has announced plans for a four-day working week for most public offices.
Reuters noted that Bangladesh “relies on imports for 95% of its energy needs” and has announced the early closure of all universities as part of emergency measures to conserve energy. The newswire says the country also halted operations at nearly all its state-run fertiliser factories, redirecting gas to power plants.
Myanmar, meanwhile, has announced a “sweeping fuel rationing system for private vehicles”, said another Reuters article.
On 9 March, China announced its “biggest retail fuel price cap increase in four years” for retail petrol and diesel, said Reuters. Additionally, diplomatic sources cited by Reuters said that China is “in talks with Iran to allow crude oil and Qatari liquefied natural gas vessels safe passage” through the Strait of Hormuz.
China is the main buyer of Iranian oil and has funded gas facilities in Qatar, meaning “billions of dollars are at risk from a widening war”, according to the New York Times.
However, India could be the “most vulnerable” to the war’s energy supply shock, according to the Hindustan Times.
On 3 March, India’s petroleum and natural gas minister Hardeep Singh Puri was quoted by the Economic Times saying that “India has sufficient reserves of crude oil and petroleum products to manage short-term disruptions”.
Three days later, the Hindustan Times reported that the US announced a “temporary 30-day waiver to Indian refineries” to continue to purchase Russian oil “already stranded at sea”. However, the Financial Times reported that analysts said that the crude oil freed up by this is a “drop in the ocean”, equivalent to only four days’ of Indian demand. (The New York Times said that the “dramatic change in energy markets could not have come at a better time for President Vladimir Putin of Russia”.)
India has invoked emergency measures to redirect supplies of liquefied petroleum gas “away from industrial users to households”, reported Bloomberg. Cooking gas supply and fertiliser plants have been given top priority, said the Times of India.
Middle East
Beyond the impact on energy, air and drone strikes in the Middle East have damaged key infrastructure, including water desalination plants.
The region is dependent on desalination plants for much of its drinking water. The Associated Press reported that, “in Kuwait, about 90% of drinking water comes from desalination, along with roughly 86% in Oman and about 70% in Saudi Arabia”.
It adds that “hundreds of desalination plants sit along the Persian Gulf coast, putting individual systems that supply water to millions [of people] within range of Iranian missile or drone strikes”.
The Financial Times noted that climate change is exacerbating water security concerns in the Gulf, where temperatures can exceed 50C in summer and there are “no permanent rivers”. It adds that climate change is “driving erratic rainfall patterns and contributing to low water storage” in the region.
The Middle East is also one of the world’s largest producers of fertilisers. Around 35% of the world’s exports of urea – a nitrogen fertiliser that “underpins around half of global food production” – passes through the Strait of Hormuz, according to the Financial Times.
As a result, the newspaper said that “granular urea prices in the Middle East have risen by about $130 to around $575-650 a tonne”.
The spike in the price of gas – a key element in fertiliser production – is also affecting fertiliser prices.
Europe
The disruption to global oil and gas supplies is driving up energy prices across Europe.
“The EU imports more than 90% of its oil and around 80% of its gas, making European countries highly exposed to fluctuations in global oil and gas prices,” according to Reuters. Europe’s gas market is particularly vulnerable at the moment, because it is emerging from winter with storage tanks depleted.
Bruegel said that Europe is “far less dependent on Gulf oil and LNG than China, India, Japan or South Korea”. However, it said that it is “not insulated”. It added:
“Oil and LNG are global markets: any blockage of the Strait of Hormuz could trigger immediate price spikes that would hit Europe regardless of its limited physical imports.”
The Financial Times reported that “European electricity prices are swinging wildly from daytime to evening as the Iran war’s disruption to gas supplies accentuates growing volatility in Europe’s power markets amid the rise of renewables”.
Petrol prices are also surging. UK average diesel costs have hit a 16-month high and the French government is asking a watchdog to check that petrol stations are not unfairly raising prices to profit from a rush for fuel.
Euronews reported EU leaders are “considering reviewing taxes, electricity network charges and carbon costs tied to energy prices as a quick fix for struggling industries”.
Meanwhile, EU economy and finance ministers gathered in Brussels to discuss how to respond to surging energy prices. According to Euronews, ministers have discussed the possibility of releasing oil reserves, but say that it is “not yet the right time”.
Other regions
Africa
In Africa, oil-producing Nigeria, Angola and Ghana are well-positioned to benefit from surging global prices, although the gains may not be evenly distributed. However, importing countries, such as South Africa, Kenya and the Democratic Republic of Congo, are at risk.
Every “$20 a barrel jump in Brent” could cause “a knock” of about 1% and 3% on South Africa and DRC’s GDP, respectively, according to Bloomberg analysis. Trade bottlenecks and the lack of refinery capacity in these countries could also lead to fuel shortages, it said.
While oil exporters could see windfall gains, “most African households will have to grapple with higher costs of living” since “most food and goods” are transported by road across the continent, noted the Associated Press.
The crisis, however, “may reinforce calls for African nations to diversify their energy systems and reduce dependence on imported fuels” through “long-term investments in renewable energy”, said Dr Kennedy Mbeva, research associate at Cambridge’s Centre for the Study of Existential Risk, as quoted in the story.
Australia
While Australia is a key gas and coal exporter, its dependence on petrol and diesel imports could leave it vulnerable, especially its agricultural and mining sectors.
The Australian Financial Review reported that Australia’s biggest gas producers – Santos and Woodside Energy – are “cashing in on the conflict…with deals struck at more than double recent market rates”.
Latin America
Major Latin American economies are “cautiously watching” the war’s impact on energy prices on their economies, reported El País.
The newspaper cited experts saying that for Venezuela – whose “modest but strategic share” of oil production is now under “direct scrutiny from the White House” – the crisis might result in additional revenues, to the tune of “around $2.4bn”.
It also quoted Mexico’s president, Claudia Sheinbaum, reassuring citizens that “compensation mechanisms [are] in place to prevent price increases from impacting” them.
While Brazil’s state-owned Petrobras “could benefit” from the crisis, said Reuters, the conflict “may spark grain contract cancellations and fertiliser shortages”.
Finally, a comment in Colombia One argued that the country’s “energy importance” could translate into “fiscal breathing room” and that oil gains could “financ[e] renewable energy without undermining fiscal stability”.
What does the Iran war mean for efforts to transition away from fossil fuels?
The rise in global fossil-fuel prices as a result of the war has prompted some leaders to recommit to boosting their energy sovereignty through the deployment of renewables.
Yet, the conflict has also been taken as an opportunity by supporters of fossil fuels to argue for more domestic oil-and-gas production, as a way to boost energy security.
In response to the crisis, Teresa Ribera, the executive vice-president of the European Commission who oversees the “clean, just and competitive transition”, said in a statement that the “answer is not new dependencies, but faster electrification, renewables and efficiency”, adding:
“The real risk is not moving too fast on clean energy, but too slowly. The clean transition is Europe’s shield against volatility.”
According to the South Korean newspaper Chosun Daily, the country’s president Lee Jae Myung said the crisis presented a “good opportunity to swiftly and extensively transition to renewable energy”.
In the UK, where there has been mounting pressure to relax government restrictions on the expansion of fossil-fuel extraction in the North Sea, prime minister Keir Starmer used a speech responding to the conflict in the Middle East to say:
“We…have the right plan for our energy supplies. Building up clean British energy like never before, decreasing our dependence on volatile international markets and creating the energy security and independence we need.”
Simon Stiell, the UN climate chief, said the crisis “shows yet again that fossil fuel dependence leaves economies, businesses, markets and people at the mercy of each new conflict or trade policy lurch”.
According to the Guardian, he added:
“There is a clear solution to this fossil-fuel cost chaos – renewables are now cheaper, safer and faster-to-market, making them the obvious pathway to energy security and sovereignty.”
UN secretary-general António Guterres said in a statement that renewable energy offers countries an “exit ramp” away from fossil-fuel dependence. He added:
“Homegrown renewable energy has never been cheaper, more accessible or more scalable. The resources of the clean-energy era cannot be blockaded or weaponised. There are no price spikes for sunlight and no embargoes on the wind.
“The fastest path to energy security, economic security and national security is clear: speed up a just transition away from fossil fuels and toward renewable energy.”
Dr Markus Krebber, chief executive at the German energy giant RWE, wrote on LinkedIn that the crisis raised the importance of “fixing the grids”, electrifying “everything that makes sense” and “relentlessly scaling renewables”. He said:
“The imperative of our time: The more we electrify, the less we import fossil fuels. The less we import, the more resilient we become.”
BusinessGreen reported on how the disruption to energy supplies is “pushing up petrol prices – and boosting the case for electric vehicles”, citing analysis of potential costs for UK drivers by the Energy and Climate Intelligence Unit (ECIU).
News outlets have cited Nepal and Ethiopia as examples of countries that rely on fossil-fuel imports, which have taken steps to accelerate the electrification of their road transport.
Some commentators noted that the rhetoric around boosting energy sovereignty through renewables matched narratives seen following Russia’s invasion of Ukraine.
While European countries have cut their dependence on pipeline gas from Russia, much of that dependence has instead moved to imports of LNG from the US. Prof Jan Rosenow, energy programme lead at the University of Oxford, told a recent briefing for journalists:
“There’s a lot more LNG in the mix. But when you look at the dependency rate of Europe on oil and gas, it hasn’t really gone down. We have diversified, but we haven’t really managed to scale the alternatives fast enough and I think now we pay the price for that.”
Despite this ongoing reliance on fossil fuels, there has been growth in wind and solar capacity both in Europe and elsewhere in recent years. There has also been rapid growth in some developing countries.
Some analysis has pointed to the example of Pakistan, which massively increased its use of solar power amid a surge in LNG prices linked to the war in Ukraine, as a possible model for other countries. This could be particularly appealing for other countries that rely heavily on fossil-fuel imports – and are, therefore, exposed to price spikes.
Isaac Levi, an analyst at the Centre for Research on Energy and Clean Air (CREA), told Heatmap News:
“This is the first oil and gas crisis-slash-pricing scare in which clean alternatives to oil and gas are fully price-competitive…Looking at the solar booms, we can expect this to boost clean-energy deployment in a major way, and that will be the more significant and durable impact.”
The solar panels driving such “booms” are cheap imports from China. Some experts have noted how China is well-placed to navigate a new energy crisis. Prof Jason Bordoff and Dr Erica Downs, both from the Center on Global Energy Policy at Columbia University, wrote in Foreign Policy that the Iran war “could consolidate China’s energy dominance”. They wrote:
“Rapidly expanding grids or deploying large volumes of solar, wind and storage is exceedingly difficult without deepening reliance on Chinese firms and materials.”
Tom Ellison, deputy director of the Center for Climate and Security and a former member of the US intelligence community, wrote in Sustainable Views that reliance on the “autonomous electricity production” of wind and solar would be preferable to fossil fuels:
“They do not rely on continuously operating pipelines, ports or shipping lanes that can be switched off, blockaded or hit by a hurricane. There is no Strait of Hormuz or Nord Stream II for clean energy.
“That is not to say clean energy is risk-free. No system is. But the challenges of clean energy, including China’s dominance of key material and mineral supply chains, are more manageable than those of fossil fuels.”
King’s College London researchers writing in the Conversation considered the geopolitics of a similar conflict in a world “powered by renewables, not fossil fuels”. They noted that renewable construction depends on critical minerals, adding:
“While mineral supply chains remain uneven…they do not converge on a single chokepoint.”
Some analysts noted that increases in fossil-fuel prices and the benefits of a cleaner energy system would not necessarily guarantee a surge in low-carbon investment.
Bloomberg cited David Hostert, global head of economics and modeling at BloombergNEF, who explained that higher energy prices could spark inflation, leading to higher interest rates and, therefore, higher costs to deploy clean energy.
According to Morningstar equity analyst Tancrède Fulop, this was part of the reason why the last energy crisis did not lead to a universal surge in renewable capacity. “Renewable companies materially under-performed because of those high interest rates,” he told Climate Home News.
The post Q&A: What does the Iran war mean for the energy transition and climate action? appeared first on Carbon Brief.
Q&A: What does the Iran war mean for the energy transition and climate action?
The UK is pioneering the use of “super batteries” that can store energy for long periods, smoothing the output from wind and solar power as the country moves towards net-zero.
It is aiming to build “long-duration energy storage” (LDES) that fills up when supplies are plentiful, to help cover the gaps when the wind does not blow and the sun does not shine.
These periods can last for days or even weeks – sometimes referred to as “dunkelflaute”, a German word meaning “dark doldrums” – whereas the current batteries on the electricity system only last a matter of hours.
The nation’s energy regulator Ofgem has now identified 16 LDES projects that it is “minded to” support under a new “cap-and-floor scheme”.
The technologies selected can be used to store energy for long periods in the form of gravity, chemical processes or electrical charge.
These include pumped hydro, which has dominated long-term storage in the past, through to large lithium-ion batteries, “flow batteries” with novel chemistry and compressed-air storage.
The use of these technologies is expected to cut energy system costs in the UK by more than £24bn between 2030 and 2050.
This Q&A looks at what LDES means and where it can come from, why it is needed and what the UK and others are doing to support its use.
What is LDES?
LDES is a broad category of technologies, with some variation in definition.
The UK government defines it as technologies that can store energy for anywhere from four hours up to years. Ofgem uses a slightly different threshold of eight hours and upwards.
Sir Chris Llewellyn Smith, emeritus professor of physics at the University of Oxford and lead author of a Royal Society report on large-scale electricity storage, tells Carbon Brief:
“[The Department of Energy Storage and Net-Zero] (DESNZ) seems to describe it as including things which we would regard as some short duration or medium duration [storage]. It’s a big confusion…For us, long duration is stuff that can last not just into seasons, but into years and into decades.”
LDES can be used to support several different aspects of the electricity system, including the integration of variable renewable energy.
Currently in the UK, there is 2.8 gigawatts (GW) of LDES, made up of four pumped-hydro energy storage assets in Scotland and Wales.
(This article refers to the UK throughout, but strictly relates to the island of Great Britain made up of England, Scotland and Wales. Northern Ireland is part of the separate all-Ireland electricity system.)
The largest of these existing sites is the Dinorwig power station in North Wales, sometimes referred to as the “electric mountain”. This is a 1,728 megawatt (MW) station opened in the 1980s, which is used to manage short-term surges in electricity demand.
For example, during England’s football World Cup match against the Democratic Republic of Congo on 1 July 2026, electricity demand rose by around 1.2GW at half-time and 1.7GW at full-time. This is equivalent to the total electricity demand for the cities of Glasgow and Leeds, combined.
Pumped storage, alongside batteries, has been used to keep the electricity system balanced during such moments by providing enough electricity to keep the system secure very quickly.
As the UK’s electricity system becomes increasingly dominated by variable renewables, however, the need for LDES to manage peaks and troughs of generation is growing.
George Martin, principal for power system modelling at analytics company LCP Delta, tells Carbon Brief that wind power creates a particular need for LDES. He says:
“[LDES is] really important for the system, particularly in a wind-driven system. You get more peaks and troughs in your renewable output and, [while] short duration [storage] can obviously help with that, with things like ‘dunkelflaute’, long-duration storage is what is needed.”
As such, the UK is working to expand the capacity and duration of storage available through LDES, as well as the range of technologies this system is based on.
For example, in May 2026 the UK’s largest vanadium “flow battery” site opened, co-located with a 3MW solar farm in Uckfield, East Sussex. (A flow battery stores energy in liquid chemical mixtures that are pumped between tanks, via an electrochemical cell.)
The Uckfield site consists of 90 vanadium flow batteries, which can be used to store 21 megawatt-hours (MWh) of electricity. This is equivalent to seven hours of peak output from the attached solar farm and is roughly enough electricity to power 3,000 homes for a day.
The batteries can be used to store surplus daytime solar generation, which can then be used in the evening and overnight.
Other LDES technologies with a longer storage capacity could be used to similarly help manage power supply and demand, but over weeks, months or seasons. This could include compressed-air energy storage, hydrogen storage and others.
The diversity of LDES technologies reflects the range of roles it is expected to play in the electricity system in the UK. This could be meeting short-term surges, helping to utilise surplus renewable energy generation or providing longer-term flexibility.
What types of LDES are available?
There are numerous types of energy storage technology, although most fall into four main categories: mechanical; thermal; chemical; and electrochemical.
For example, a pumped-hydro project uses surplus energy to pump water uphill to a reservoir. The mechanical energy is released when the water flows down through a turbine.
Thermal storage could be a tank of gravel that is heated up, then later used to warm up water. Electrochemical storage is familiar in the form of batteries.
Finally, chemical storage relates to energy stored in molecular bonds, for example, making hydrogen from water. (Similarly, the energy in fossil fuels, which is ultimately derived from the sun, is a form of chemical storage.)
A key consideration for each LDES technology is the amount of energy it can store, measured in watt-hours (Wh). For example, a 1MW battery with four hours of storage contains 4MWh of electricity. It can therefore be used to deliver 1MW continuously for up to four hours.
Another consideration is whether the energy can be stored for long periods before use – and whether it is economic to do so.
In recent years in the UK, battery energy storage – predominantly lithium-ion batteries with a duration of one to four hours – has dominated the storage sector. The lithium battery sector in the UK has grown from almost nothing in 2015 to more than 6GW today.
However, as lithium-ion batteries have only tended to hold a few hours of storage, they cannot help support the grid during longer periods of low renewable energy generation.
Technologies such as vanadium-redox flow batteries, compressed-air energy storage or hydrogen salt-cavern storage could potentially help manage supply and demand over days, weeks or even years.
A range of LDES technology options are shown in the table below.
| Technology | Type | Duration | How does it work? |
| Gravity storage | Mechanical | Hours | A heavy object is lifted, storing kinetic energy that can be turned back into electrical energy by a generator. |
| Lithium-ion batteries | Electrochemical | Hours | Lithium ions move between a negative anode and a positive cathode through an electrolyte within the battery. |
| Liquid air | Mechanical | Hours to days | Air is compressed and cooled until it becomes a liquid. When the air becomes a gas again, it drives a turbine. |
| Vanadium flow | Electrochemical | Hours to days | Liquid chemical mixtures are pumped between tanks, via an electrochemical cell. |
| Compressed air | Mechanical | Hours to days | Air is compressed to a high pressure and stored in underground geological formations, such as salt caverns or disused oil and gas wells. |
| Pumped hydro | Mechanical | Hours to days | Water is pumped up a hill to a reservoir and then released to drive a turbine. |
| Hydrogen salt cavern storage | Chemical | Seasons | Surplus energy is used to make hydrogen from water. The hydrogen is then stored in underground salt caverns, before being burned as fuel. |
| Thermal energy storage | Thermal | Seasons | A material such as gravel is heated with surplus energy and kept in an insulated store, before being used to warm water. |
Each option has specific advantages and disadvantages; for example, while pumped hydro storage has a high upfront cost, it has a long lifespan of over 50 years. As such, its capital cost per kilowatt hour (kWh) is lower than many other storage options over time.
(Pumped hydro is the most established LDES technology in the world, but no new projects have been built in the UK since the 1980s.)
While it has historically been a short-duration form of storage, some lithium-ion batteries can now store power for much longer chunks of time.
Lithium-based grid batteries now often offer 8-12 hours of storage and – as shown in the table above – even longer durations are possible
As Ed Porter, director for Europe at data company Modo Energy, quipped on LinkedIn following the cap-and-floor scheme results:
“Lithium [is] going far beyond 8 hours; that debate must surely be dead now.”
While even 12 hours is of limited use for gaps in generation of days, weeks or seasons, there are numerous benefits to lithium-ion batteries in comparison to other LDES technologies. For example, the cost of these batteries has fallen by an average of 20% per year over the last decade.
Given the variation in technologies – including scale, lifespan, commercial readiness and aspects such as necessary geography – comparing the costs of each technology is challenging.
However, utilising a diverse set of storage technologies is expected to be particularly beneficial for electricity systems, according to experts.
Julia Souder, CEO of industry group the LDES Council, tells Carbon Brief:
“The UK is leading the charge on technology diversity. We’re witnessing matching different LDES solutions to the real differences in market structure and country needs.
“But make no mistake: a handful of LDES technologies will do the heavy lifting over the next decade. We’re seeing that play out in which technologies are winning through the UK government’s new cap-and-floor mechanism for long duration storage.”
How much LDES will the UK need?
LDES is expected to be a key component of the UK’s electricity system in the future, particularly as it moves away from easily stored and dispatched fossil fuels such as gas.
The government has set a target of “clean power by 2030”, in the lead-up to the wider net-zero by 2050 goal.
In 2024, the Labour administration set out an “action plan” for reaching the 2030 target, which included substantial increases to electricity generation technologies.
This included setting widely discussed targets to double offshore wind, triple onshore wind and quadruple solar capacity by 2030, alongside rebuilding the UK’s nuclear fleet.
But the action plan also set a less well-known target for 4-6GW of LDES, to help balance this renewables-dominated electricity mix. This is in addition to 23-27GW of short-duration battery energy storage, new interconnectors and a big push to develop consumer-led flexibility.
There is also a major expansion of LDES to 3.8-5.3GW by 2030 in the most recent “future energy scenarios” report from the National Electricity System Operator (Neso), as shown in the chart below.
Neso’s pathways show LDES rising to between 16.6GW and 13.2GW by 2050, mainly dependent on how hydrogen is used in the electricity system.
The Neso report notes that few LDES schemes are likely to come online before 2030, due to the long project development and planning times, as well as high capital expenditures.
Which types of LDES is the UK planning to use?
While the UK is pursuing a diverse range of LDES, certain technologies are likely to make up the bulk of LDES in the next decade or so.
This is evident in the technologies that have bid successfully into the UK government’s new “cap-and-floor” mechanism for LDES.
The scheme was first announced in 2024 and is designed to guarantee a minimum level of revenue for energy storage operators – the “floor” – as well as to put a limit on profits via the “cap”.
(The mechanism will be funded through electricity bills. However, Ofgem expects it to be broadly cost-neutral over time.)
Similar mechanisms have been used to support the development of other technologies in the UK, in particular those with high upfront costs, such as interconnectors. Ultimately, it minimises the risk for developers by guaranteeing a certain level of future revenue.
In 2025, 171 LDES projects with a total capacity of 52.6GW applied to enter the cap and floor scheme, which is administered by Ofgem. Of these, 77 projects (28.7GW) were deemed eligible to enter a second “assessment” phase.
These were made up of nine different technologies, as shown in the figure below. However, lithium-ion batteries dominated the process, making up more than 20GW of the 29GW total.
No pure vanadium-flow batteries, liquid-air energy storage, iron-air batteries, sodium-sulphur batteries or hydrogen batteries were deemed eligible for the second phase.
(Conventional hydrogen storage was not eligible to bid into the process either, but could be supported through other means. The government is expected to release an updated hydrogen strategy later in 2026.)
Ultimately, Ofgem announced in June 2026 that it was “minded to” support 7.6GW of LDES capacity, spread across 16 projects. Of this total, 4GW is expected to be online by the end of the decade, at the bottom end of the range said to be required for the clean power 2030 target.
The 16 projects are listed in the table below. They comprise four technologies: pumped storage hydro (3.9GW); lithium batteries (3.6GW); one vanadium-zinc flow battery (65MW); and one compressed- air energy storage site (50MW).
| Name | Technology | Region | Capacity (MW) | Duration (hours) | Storage capacity (MWh) |
| Earba PSH | Pumped storage hydro | North Scotland | 1,800 | 15 | 27,000 |
| Coire Glas | Pumped storage hydro | North Scotland | 1,440 | 32 | 46,100 |
| Loch Kemp Storage | Pumped storage hydro | North Scotland | 660 | 22 | 14,500 |
| East Claydon Storage | Lithium battery | East England | 500 | 12 | 6,000 |
| Sundon Storage | Lithium battery | East England | 500 | 8 | 4,000 |
| Field Netherton | Lithium battery | North Scotland | 400 | 16 | 6,400 |
| Field New Deer | Lithium battery | North Scotland | 400 | 18 | 7,200 |
| Field Lond Stratton | Lithium battery | East England | 400 | 16 | 6,400 |
| Springwell | Lithium battery | East Midlands | 400 | 11 | 4,400 |
| Drakelow (Innova) | Lithium battery | West Midlands | 385 | 9 | 3,500 |
| Field Rigifa | Lithium battery | North Scotland | 200 | 18 | 3,600 |
| Field Fyrish | Lithium battery | North Scotland | 200 | 17 | 3,400 |
| Ocker Hill BESS | Lithium battery | West Midlands | 145 | 8 | 1,200 |
| Thornton BESS 2 | Lithium battery | East Midlands | 100 | 11 | 1,100 |
| Frontier Legacy | Vanadium-zinc flow battery | North Wales | 65 | 8 | 500 |
| TeesCAES | Compressed air | North-east England | 50 | 30 | 1,500 |
Welcoming Ofgem’s initial decision on the cap-and-floor mechanism, energy minister Michael Shanks said in a statement:
“Forty years after the country’s last pumped storage facility, this government is getting Britain building again…
“We are [going] further and faster in delivering the clean-power mission by rolling out a new generation of pumped-hydro storage and state-of-the-art batteries – making more of the clean, homegrown power we already produce, cutting waste, lowering bills and strengthening our energy security.”
Collectively, the provisionally successful projects can provide between eight and 32 hours’ worth of electricity storage. The top ten projects in terms of duration that applied for the mechanism – those with at least 12 hours’ worth of storage – all moved forward.
Following Ofgem’s “minded-to” decision, the regulator launched a consultation that ended on 7 August 2026. It will now make a final decision on the projects that will be supported through the “cap and floor” mechanism.
Martin tells Carbon Brief that “it’s not over” yet, with Ofgem likely to face scrutiny over the methodology it used to determine these final results. He adds:
“There’s going to be a lot of activity and a lot of responses to that consultation. I don’t expect the overall amount of capacity that’s been awarded to change, although they could increase it – it could only go up, probably.
“But there might be some change in what projects end up getting approved as a result, or maybe they end up making some changes for the next window [of applications for LDES support].”
Alongside the cap-and-floor process being run by Ofgem, the government introduced legislation via the Planning and Infrastructure Act to support the introduction of the scheme.
Additionally, in August 2026, Innovate UK – the UK’s national innovation agency – announced new funding for “ultra-long” duration battery energy storage.
Up to £3m will be invested in demonstration projects as part of the first phase of the funding, with £10m available in the sector to support the development of technologies capable of storing and discharging at least 100 continuous hours of electricity.
In a statement responding to the new funding, Dr Jamie Speirs of the University of Strathclyde and co-director of the UK Energy Research Centre, said achieving the UK’s low-carbon ambitions will rely on “unlocking” LDES to support a highly renewable system. He added:
“By providing flexibility across hours, days and even seasons, LDES could enable a resilient, low-carbon electricity system – reducing curtailment, strengthening security of supply and ensuring that intermittent renewables can maximise their contribution to the grid in all conditions.
“Investing in innovation opportunities such as this call to support market deployment of LDES technologies is a key way to support these technologies to market, giving us the best chance to meet our net zero targets.”
Phase one of the funding is open for applications until 30 September, with grants of between £350,000 and £700,000 available for the successful projects.
Seamus Garvey, professor of dynamics at the University of Nottingham, welcomes the new funding. However, he cautions that more needs to be done to ensure the future markets for medium- and long- duration storage are not compromised by early commitments to storage at shorter timescales. He tells Carbon Brief:
“Energy storage will be required over many timescales and as we decarbonise further and further, the requirements for longer durations grow and grow.
“One key problem in my opinion is that because we are tending to buy into lots of short-duration stores now, we are actually removing pieces of market that could be accessible by longer duration stores and that is making the (already-difficult) problem of financing these stores ever more difficult.”
How could LDES impact energy bills?
The rollout of LDES technologies is widely expected to help reduce energy bills as the UK transitions to a clean-energy system.
There is still a significant amount of uncertainty over the development of LDES, due to the wide range of options, nascent stages of development and lack of market maturity. Nevertheless, most research agrees that it will cut electricity system costs by the middle of the century, relative to a world where LDES is not used.
For example, adding 20GW of LDES could reduce electricity system costs by £16-51bn between 2030 and 2050, compared with a scenario that has limited flexible capacity, according to analysis for the Department for Energy Security and Net Zero (DESNZ), by thinktank Regen and LCP Delta. The analysis, published in 2023, found that 20GW of LDES could reduce costs by around £26bn.
Analysis by LCP Delta in 2025 found that building 20GW of established medium-sized LDES technologies – pumped hydro with a capacity of 8-12 hours – by 2050 would have a system benefit of more than £10bn.
LDES could reduce total UK electricity system costs by £7-13bn annually by 2040-2050, according to a report from the Transition Finance Council – a public-private body launched by the City of London Corporation and the UK government – citing a range of other studies.
The council says this would predominantly be by avoiding “curtailment”, where some generators are paid to switch off because the electricity grid cannot accommodate their output. It says that LDES would defer the need for additional grid investment and would reduce balancing costs, including curtailment.
(In the financial year 2024-25, balancing costs reached £2.7bn, adding around £40 to the average household electricity bill. Some £1.9bn of this – £28 per household – related to constraints, where wind is “curtailed” and gas plants are switched on elsewhere.)
Curtailment is a particular issue in Scotland, where much of the UK’s wind capacity sits behind congested sections of the national electricity network. Porter notes on LinkedIn that this helps explain why 79% of the LDES projects by storage capacity are located in northern Scotland.
Martin says LDES will allow the UK to “use our renewable fleet more efficiently”. He adds:
“[LDES] is able to increase renewable energy and then decrease gas generation during high-demand periods, and that brings all sorts of benefits to the system.
“It reduces emissions, it reduces the overall cost of the system, it can help reduce bills for consumers. So those are the types of benefits that we’ll see as a result of [more] LDES being [on the system].”
The Transition Finance Council report adds that despite the upfront cost, LDES quickly pays for itself. It estimates that each gigawatt of long-duration flexibility on the system requires around £2-2.5bn in investment, but yields annual system savings of £0.5-1bn once operational.
As such, even accounting for the upfront cost of developing LDES, the technologies would provide £30-60bn of electricity system savings over 25 years, the council says. It adds that this means LDES “will repay itself several times over”.
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The post Q&A: What is ‘long-duration energy storage’ – and why does the UK need it? appeared first on Carbon Brief.
Q&A: What is ‘long-duration energy storage’ – and why does the UK need it?
Claver Gatete is Executive Secretary of the UN Economic Commission for Africa. Jason Veysey is Energy Modeling Program Director and Senior Scientist at the Stockholm Environment Institute. Lisa Sachs is Director of the Columbia Center on Sustainable Investment at Columbia University.
The case for global energy transition has rarely been clearer. The closure of the Strait of Hormuz earlier this year exposed the cost of unplanned, fossil-dependent systems, while the falling cost of renewables, the rising penetration of electric vehicles, and the growing value of demand flexibility have made the direction of travel obvious. The benefits of a clean, secure, integrated system are no longer in dispute. What remains unclear is how to build it.
Countries around the world have called for faster renewable energy deployment and alternative energy arrangements. A secure, affordable, resilient, decarbonised system requires specific investments in specific places in a specific sequence, optimised across sectors and borders. But very few governments have the analytical foundation to translate those imperatives into investment.
The two instruments that are supposed to determine investment priorities for decarbonisation – Nationally Determined Contributions (NDCs) and country platforms – cannot answer the most basic question facing any country undertaking an energy transition: what should the energy system look like?
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To close this gap, every country needs a bankable, economy-wide optimisation model for its energy system. A model is not a plan, but it can help answer the critical question of what the future energy system should look like. It shows how optimal scenarios vary as assumptions and policies are adjusted, calculates investment requirements and sequencing, and quantifies how system costs are affected by assumptions, policies, and exogenous variables like trade policy and financing terms.
Tool for efficient investment
Optimisation is a simplified way of simulating an energy system, but it can be an extremely powerful tool for moving energy planning from reactive (how do we manage the disparate actions in the energy system?) to intentional (what energy system underpins our national objectives?). A model can show how optimal scenarios vary as assumptions and policies are adjusted, and how investment requirements are quantified and sequenced.
Optimisation models can treat the energy system and the sectors it serves as an integrated whole, optimising across sectors and projects in ways that can be mutually reinforcing. If considered independently, growth in industrial demand, transport electrification, and digital infrastructure can add stress to the energy system. But an optimised plan can arrange these and other changes in an efficient, synergistic way.
Two to tango: How governments can unlock private investment for national climate goals
New load can be added where low-cost power is available; industrial customers can ensure the viability of investments in energy supply; electric vehicle charging policy can smooth load curves and reduce costs for all consumers.
Additionally, optimisation modeling can also change the financeability of investments. Taken alone, each project faces uncertainty about the rest of the system, which raises the cost of capital and causes projects to stall or unwind after contracts are signed. A coherent, optimised plan makes visible the coordination that private capital would otherwise have to bet on: identified offtake, sequenced and committed transmission, contracted power supply, and so on.
What COP31 and COP32 should do
The upcoming COPs in Turkey and Ethiopia can shift the center of gravity of international climate cooperation from fragmented commitments to planning. Three moves are urgently needed.
First, optimised, economy-wide, long-term energy system planning must be the foundation on which any meaningful NDC, country platform, or finance commitment rests. NDCs are typically drafted by environment or single-line ministries, with limited cross-sectoral input from ministries of energy, finance, and planning. They contain targets, derived from sectoral strategies or national commitments, not from an analytically grounded picture of what the energy system should look like and what investments would make it work. Country platforms are generally a portfolio of investments assembled from existing project pipelines, rather than derived from a system-level analysis of what an optimised, decarbonised energy system would require.
Second, recognise regions as a key planning unit. Modern integrated energy systems are inherently regional. Renewable endowments are unevenly distributed; balancing variable supply across borders lowers aggregate cost, reduces redundant backup capacity, and unlocks economies of scale no individual nation can achieve. Many energy investments in Southeast Asia, East Africa, Southern Africa and Central Asia may only be financeable in a regional context. Assessing domestic infrastructure without regional optimisation perpetuates the perception that decarbonisation is more expensive than it is.
COP31 leaders unveil global targets, with spotlight on electrification
Third, finance the planning capacity. A coordinated commitment by multilateral development banks, bilateral donors, and philanthropic partners to help every region and its constituent countries develop and maintain their own modelling capability, with open-source tools and regional analytical hubs, would close the most consequential gap in the current architecture. The cost is small relative to current spending on country platforms, failed project preparation, and misallocated infrastructure investment.
This includes supporting regional institutions such as the ASEAN Centre for Energy, the African Energy Commission, regional power pools, and the Latin American and Caribbean Energy Organization to determine what optimised regional systems require. Country-by-country pledging, repeated at every COP, will not deliver what meaningfully integrated systems can.
The 2026 energy crisis made the cost of unplanned, fossil-dependent systems newly visible. That window of clarity will close. The international community should seize the moment to build the planning foundation that has been missing for thirty years, rather than commissioning another round of NDCs or pledges, striving for outcomes neither was designed to deliver.
The post Every country needs a model to help optimise its energy transition appeared first on Climate Home News.
Every country needs a model to help optimise its energy transition
The world is currently experiencing what is expected to become the strongest El Niño on record – dubbed a “super El Niño” by many.
El Niño is the warm phase of a recurring climate pattern in the tropical Pacific that releases heat from the ocean into the atmosphere.
This temporarily raises global temperatures and reshapes rainfall and extreme weather around the world – impacting the lives of billions of people.
The current El Niño event began in June and is expected to last into 2027.
El Niño is part of a wider climate pattern called the El Niño-Southern Oscillation (ENSO) cycle.
The ENSO cycle also has a cool phase, known as La Niña, as well as a “neutral” phase. El Niño and La Niña events typically last between nine and 12 months, but can go on longer.
Below, Carbon Brief explains how the ENSO cycle works, its impacts on extreme weather and global temperatures and why this El Niño event is projected to be the most intense since records began.
The post Explainer: How the ‘super El Niño’ will reshape the world’s weather appeared first on Carbon Brief.
https://interactive.carbonbrief.org/el-nino-explainer/index.html
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