Heatwaves are becoming more likely and more intense due to climate change, impacting sources of power generation around the world as they work to meet increased demand.

When temperatures soared past 40C in parts of Europe in June and July 2026, nuclear reactors shuttered, gas plants’ efficiency fell, wind speeds dropped and electricity networks sagged.

Yet, while all types of electricity generation are affected variously by extreme heat, some commentators are quick to point the finger at “intermittent” wind and solar, while downplaying the impact on sources such as gas or nuclear power.

Extreme heat also drives up electricity demand, as people turn on air conditioning and fridges work harder.

For example, in France, daily electricity demand rose by almost 20% during a two-week heatwave in June 2026.

This often leads to an increase in power prices, as generation strains and demand rises, putting a premium on electricity.

Below, Carbon Brief – amid a slew of misleading claims – explains how key power sources cope with extreme heat.

Nuclear

The impact of heatwaves on nuclear power generation is well documented, with a plethora of headlines often accompanying record temperatures in nations that rely on the technology.

For example, around 70% of electricity is generated by nuclear power in France, leaving it vulnerable to the impacts of heatwaves.

During the July 2026 heatwave, three of France’s 57 nuclear reactors had to shut down. Generation was reduced at another seven, causing an almost 9% dip in power production.

(This is a well-known phenomenon – France has seen reductions in nuclear generation due to heatwaves in 2003, 2006, 2015, 2018, 2019, 2022 and 2025.)

A similar story is true across various countries in Europe. Low river levels on the Danube have hit nuclear reactors in Romania, Hungary and Serbia this summer, while a Swiss nuclear reactor shuttered due to high river temperatures.

It is nuclear plants using river water to cool their reactors that are most significantly affected by heatwaves and droughts. These make up 14% of the global fleet. Around 60 of the world’s 440 river-cooled reactors are located in France, with a further seven across Europe.

Nuclear power plants use fission to generate heat, which is used to create steam. This steam spins the blades of a turbine that is connected to a generator to create electricity.

Following this process, the water is cooled to allow it to be recycled back through the system as steam again. Nuclear power plants generally use water from rivers or the sea to help cool and condense this steam.

As such, when water temperatures rise due to a heatwave, their cooling capacity is reduced and the overall efficiency of the nuclear power station is affected. Similarly, if there is less water available due to drought, they cannot be cooled as effectively.

Michael Tadrous, a researcher at McMaster University’s DeGroote School of Business in Canada, tells Carbon Brief that the “impact [of heatwaves] is real, but it is far smaller than many headlines suggest” and that the “effect [of heat] is gradual”. He adds:

“Warmer intake water makes a reactor slightly less efficient. [But] even an extreme 15C rise in cooling-water temperature would cost a large reactor only about 6% of its output.

“The real pressure point during a heatwave is usually legal rather than technical. Plants return their cooling water to the river a few degrees warmer than they drew it and the law limits how warm that water may be in order to protect aquatic life.”

Henry Preston, a spokesperson for the industry body the World Nuclear Association, adds that reactor shutdowns due to high river temperatures are “typically an automatic response to comply with regulations to protect local ecosystems, rather than a technological fault”.

He notes that in some extreme heatwaves, these regulations are waived given the “essential need for electricity and taking a proportional approach to climate risks”.

While nuclear power plants can generally return to standard operation quickly if they have been affected by high water temperatures, drought can cause a more significant impact.

Preston tells Carbon Brief:

“In contrast to high river temperatures, which can quickly return to acceptable levels once a heatwave passes, low river levels can persist for much longer, if drought conditions continue. As a result, low water levels may have a more prolonged impact on plant operations than elevated water temperatures.”

This is set to be the case in the current European drought, where multiple reactors in Hungary and Romania have shut down or reduced their output due to low water levels.

The Danube is not expected to return to normal water levels for “days or even weeks as no significant rainfall is forecast”, reported the Associated Press on 3 August 2026. It said this was “push[ing] some countries in eastern Europe to the brink of energy emergency”.

While heatwaves and drought can produce significant short-term effects, their impact on the availability of nuclear power across a full year is generally minimal.

On average, heatwaves cut annual nuclear generation by 0.6% between 2003 and 2022, according to a recent study that Tadrous co-authored.

He adds that, across the whole period studied, the only time a national nuclear fleet lost more than 1% of its nuclear power over a year to heat- and drought-related curtailments was France in 2003, which lost 1.3%.

According to an article in Forbes, for every additional degree Celsius in temperature, a nuclear power plant loses around 0.6-1% in cycle efficiency.

To minimise the impact on both energy security and costs, governments and nuclear companies are looking at a range of solutions to adapt to heatwaves.

For example, French nuclear-plant operator EDF is looking at additional cooling towers for its sites that are the most exposed to the impacts of a warming climate, reported Bloomberg recently.

Tadrous says the nuclear power industry is already adapting to heatwaves that are “more frequent and more intense”, adding:

“France’s river-cooled fleet lost 5.5 terawatt hours (TWh) of output to the 2003 heatwave. By 2022, one of the most severe heat-and-drought summers on record, losses had fallen to 0.5TWh, a reduction of roughly 90%, as utilities upgraded cooling systems, refined operating practices and scheduled maintenance around periods of extreme heat.”

There remain challenges for adapting nuclear power – and the wider electricity systems in which it sits – to heatwaves. However, Tadrous notes that this is less about “technical feasibility than of economic prioritisation and timely implementation”.

Gas

Gas power plants have a reputation for being reliable and able to switch on at any moment, sometimes referred to as “firm, dispatchable” capacity.

Yet, as a type of thermal generation, they are subject to many of the same stresses during heatwaves as nuclear power.

An article by the science advocacy organisation Union of Concerned Scientists (UCS) notes that the “purported ability of gas plants to be available at all times to generate electricity, particularly when the grid needs it most, is increasingly under scrutiny” due to heatwaves.

As a matter of physics, the efficiency of gas power plants drops as temperatures rise. At 40C, a gas-fired power station can expect its capacity to be reduced by 13% and its efficiency by 7% compared to when running at 20C, according to Electric Insights.

Dr Iain Staffell, associate professor in sustainable energy at Imperial College London, tells Carbon Brief:

“Simple gas turbines (the kind which turn on rapidly to meet peak demand) are hit harder [than solar, for example], with their power output falling by about 10% per 10C.”

(He adds that the transmission system struggles more than electricity generation during high temperature. Power line capacity can fall by up to 16% for a 10C rise in temperature, according to a report for the UK government.)

Several types of gas power plants require cooling as part of their process, including gas steam and combined cycle turbines (CCGTs). They usually rely on nearby bodies of water for this.

Additionally, as the UCS article notes, hot air has a lower density than cool air. As gas CCGTs rely on burning a mix of gas and air, this lower density means air takes up more space, leaving less room for gas.

Ultimately, this means that when the air is hot, gas power plants cannot generate as much electricity as normal.

These effects are not just theoretical. For example, across two nights in August 2020, there were rolling blackouts in California, US, as demand exceeded supply amid a heatwave.

While a number of factors contributed to the blackouts, gas plants made up around 79% of the capacity that dropped off the system on 14 August and a similar share the following day.

Amid record-breaking heat in summer 2026, gas power plants have also seen their capacity cut in the UK, France and other countries.

Dr Staffell adds that gas power stations are thought of as “reliable, because of the way we use them” in the UK.

Whereas wind and solar are usually used to the maximum extent possible, he says that on average, only around 40% of the gas fleet is in use at any one time. As such, even if the efficiency of one gas power plant is affected by high temperatures, “we have a lot of slack to call on more of them to run”. He adds:

“The issue is less that they can’t deliver, but we have to pay through the nose to persuade more to turn on at critical times, adding to sky-high energy bills.”

Wind

The impact of heatwaves on wind generation is less direct than for other technologies.

However, wind speeds often drop during heatwaves, which tend to build during periods of sustained high pressure into extreme events such as “heat domes”.

Dr Staffell, explains to Carbon Brief:

“The very hottest days tend to create heat domes with very low wind speeds, which directly reduces the output that windfarms can produce. Air is also less dense the hotter it is, so it carries less energy within it, so there is a double impact on wind turbines.”

High temperatures are linked to low wind speeds across three-quarters of the globe, according to one recent study, looking at data from 1980 to 2023.

The study found that, as a result, across Australia, northern Asia and Europe, wind power decreased by an average of 30-50% during heatwaves.

This is inconsistent globally, however, with the Amazon, the Great Plains in North America and central Africa actually seeing a slight increase in wind during high temperatures.

As such, while the effect of heatwaves on wind generation is less direct than other generation technologies, it can have a significant impact.

In the UK in June 2026, wind generation fell to around 15% of the electricity mix due to low wind speeds, from an average for the month of about 30%, according to Octopus.

Low wind generation during this period was a key feature of the strain on the grid experienced during this time – in particular, as demand rose amid record-high temperatures.

On Wednesday 24 June, for example, the National Electricity System Operator (Neso) had to pay high prices to balance supply and demand. This included paying as much as £1,400 a megawatt-hour to secure around 1.7 gigawatts (GW) of imported power, nearly 20 times the average price for electricity in June 2025.

A Neso spokesperson said in a statement: “This is due to the impact of extremely high temperatures affecting Great Britain and the continent, and low wind.”

While reduced wind generation is common during a heatwave, it is not generally viewed as a concern for energy system operators. This is due to wind following well-established seasonal patterns – it generates less power in summer than in winter – as well as being complementary to other renewable technologies, such as solar.

Dr Chris Rosslowe, senior energy analyst for Europe at Ember, tells Carbon Brief:

“Power systems are less reliant on wind power in the summer months and its lower-than-average output is already expected and planned for. Heatwaves often bring still, but clear conditions, highlighting the benefit of wind and solar as a duo – poor conditions for one often mean good conditions for the other.”

As such, wind power remains one of very few technologies considered “resilient” to heatwaves by the UK government.

However, this did not stop the anti-renewables Daily Mail from attempting to blame the technology for strain on the UK grid on 24 June 2026, despite its own article acknowledging that gas plants had also been forced to cut their output by 2.5GW on the day.

Solar

Another common claim seen in the media is that solar “struggles” during heatwaves, with high temperatures pushing down the technology’s efficiency.

Yet heatwaves tend to coincide with long, cloudless days, when solar generation is reliably above average – despite the impact of high temperatures.

While hot weather does reduce the efficiency of solar cells, the effect is relatively modest – and widely understood. Each 1C of temperature rise reduces output by around 0.4-0.5%, according to a recent study.

This is in line with an evidence review for the UK government, which suggests the performance of solar panels falls by 0.2-0.5% for every degree of heat above 25C.

Generally, however, this effect is easily outweighed by high sunlight hours during hot spells. For example, across a four-day heatwave in the UK in June 2026, solar generated 484 gigawatt-hours (GWh) of electricity – a 46% increase over the same period a week earlier.

Similar generation highs were seen across Europe, amid record temperatures and dangerous heat that was pushing people towards the use of air conditioning.

Solar generated a record 52TWh across the EU in June 2026, beating the high set just the month before of 47TWh.

In fact, solar – especially when combined with battery storage – is a complementary technology to air conditioning, given their similar seasonal patterns. Over the course of the day, demand from air conditioning and generation from solar also marry up well.

Dr Rosslowe says:

“Solar, battery storage and air conditioning are a highly complementary trio of technologies during heatwaves. There’s a high overlap between solar output and demand from AC.”

For example, on the hottest day of the year so far in Great Britain (the island grid serving England, Wales and Scotland), on 26 June 2026, solar surged to 13.9GW in the middle of the afternoon, as demand also hit its highest point, as shown in the chart below.

Across June 2026, homes with solar panels generated the equivalent of five hours of “free” self-supplied air conditioning, according to recent analysis.

Despite the impact of heat on solar efficiency, the technology is, therefore, well placed to bolster energy systems during heatwaves.

Indeed, as Dr Rosslowe tells Carbon Brief, solar suppresses power prices during daylight hours. But, even though it is predictable, there are still challenges around managing the dip in solar generation as the evening sets in. This is often compounded because it coincides with the usual evening increase in demand.

Dr Rosslowe explains:

“Problems arise when the sun goes down, but demand for cooling remains high. In the early evening hours, when gas power typically ramps up to replace solar, we have seen prices spike to extreme levels, made worse by high international gas prices.”

Storage

Energy storage systems are increasingly key to managing the impact of heatwaves on electricity systems.

The category of technologies is dominated by batteries, with more than 108GW of battery storage added in 2025 alone, according to the International Energy Agency.

Already, batteries have been used to take advantage of surges in solar generation during the daytime, amid high summer temperatures.

This is particularly useful to meet evening peaks in electricity demand, as well as the need for air conditioning overnight when temperatures do not fall.

In a statement, Pawel Czyzak , Europe programme director at Ember, said:

“Heatwaves will not go away – they will only get more severe in the future. Solutions that can help mitigate their impacts, such as battery storage, interconnection, demand flexibility and dynamic tariffs, should become a key part of grid planning and power market design.”

However, batteries are not without their challenges during heatwaves. Battery performance also decreases as temperatures exceed their optimal level.

Additionally, high temperatures can accelerate the degradation of components in lithium-ion batteries, which dominate the sector.

Analysis for the UK government found that prolonged operation at very high temperatures could – at least in theory – “overwhelm” the cooling systems built into batteries, “posing risks such as thermal runaway and explosions”. However, it noted that in practice, these cooling systems are “routinely” designed to handle temperatures of up to 45C.

(The analysis added that “developers and manufacturers have a strong understanding of risk to [battery storage systems] from high temperature and mitigate risks through regular maintenance, design improvements, and passive cooling strategies”.)

Other storage technologies also face challenges during heatwaves. For example, pumped hydro storage can be significantly impacted by drought.

Australia – which now has 4.3GW of large-scale battery storage capacity – saw its fleet of batteries and pumped hydro storage tested at the beginning of 2026, amid the most severe heatwave in years.

Temperatures above 40C posed “challenges” to storage technologies, reported Energy Storage News, which explained that their output and operating times were reduced by the increased need for their cooling systems to operate.

Despite these challenges, the use of battery storage is helping to spread the ability of renewables to meet electricity demand during heatwaves. For example, a combination of solar and battery energy storage “kept the lights on” in California amid a heatwave in 2024.

By storing abundant power during the day, it can be discharged during evening peaks, helping to minimise generation constraints and thereby keep power prices down.

Dr Rosslowe says:

“The extreme price spikes that we witness during heatwaves are a blaring signal for more power system flexibility. That could come from battery storage, demand response, or increased interconnection between countries or regions.”

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The post Factcheck: How nuclear, gas, wind and solar power are affected during heatwaves appeared first on Carbon Brief.

Factcheck: How nuclear, gas, wind and solar power are affected during heatwaves

As governments at the UN seek ways to prevent the US from unilaterally mining the deep ocean floor for critical minerals, the latest UN seabed talks launched “long” processes that would seek to challenge Washington’s approach.

The International Seabed Authority (ISA), the UN body regulating the deep ocean floor, held annual three-week talks ending on Friday. The discussions come as the US – which is not a member country – moved forward in its unilateral deep-sea mining push, and as mining companies applying for American permits fought back a UN inquiry into their behaviour.

The Trump administration and mining frontrunners, among them Canadian firm The Metals Company (TMC), want to mine a huge area of the Pacific Ocean known as the Clarion-Clipperton Zone. Although it holds deposits of mangenese, nickel and rare earths – key for military use and clean energy components – it is also an unexplored ecosystem with thousands of unnamed species.

The meeting, held at ISA headquarters in Jamaica’s capital Kingston, ended with no immediate breakthroughs. Instead, it started long processes that seeks to hold mining firms and the US accountable, according to ocean governance expert Pradeep Singh, from the Oceano Azul Foundation.

“It shows some level of maturity as well as understanding from member states that this is a long process that requires policy discussions that might not be resolved by acting right away without considerate thought” he said.

Countries have begun consultations on whether to request an advisory opinion from the International Tribunal for the Law of the Sea (ITLOS), which would seek to clarify the legality of the US-issued permits in the Clarion-Clipperton Zone and whether other states should recognise them.

The ISA will also move forward with an inquiry into its contractors, including The Metals Company (TMC). The company tried to prevent this inquiry by suing the ISA at the ITLOS for allegedly acting in bad faith, an argument that the world’s top maritime court rejected.

ISA secretary-general Letícia Carvalho said in her closing remarks that the past year “presented both significant challenges and noteworthy achievements”. Earlier in the talks, she said the agency’s role is “more important than ever” and that resources in the deep seabed are “the common heritage of humankind”.

Advisory opinion on legality of US mining push

Towards the end of the ISA assembly, Carvalho submitted a draft text to countries proposing they request an advisory opinion from the ITLOS, clarifying the legality of the US deep-sea mining push.

The initiative proposed questions to the court, including whether international law backs the principle that the deep seafloor cannot be appropriated by any single country, and whether other governments should avoid recognising any similar effort.

Several nations including the African group, New Zealand, Norway, France, Singapore, Jamaica and Canada argued that while they could back such a proposal, it required careful legal consideration. Some regretted that the note was not sent earlier in the talks.

Russia and China backed the request for an advisory opinion. The Chinese delegation suggested asking whether unilateral actions by non-member states – such as the US – would break international law, and what the consequences of such actions would be.

Egypt seeks to unlock renewable potential to power regional clean energy hub

By the end of the talks there was no consensus on this proposal. The assembly decided instead to hold consultations led by Malta, and decide on whether to request an advisory opinion by next year’s meeting.

“They are not rushing into this,” Singh explained. “It also seems that they are not feeling immediately threatened at this stage, and that there are still some things that could be done to find a way forward and perhaps persuading the US from acting unilaterally.”

Growing call for deep-sea mining moratorium

Activists were also critical of the ISA deciding to renew one of TMC’s exploration licenses in the Clarion-Clipperton Zone, which expired last month. Haldis Helle, ocean campaigner at Greenpeace, said this was a “reward” for TMC despite “their clear disregard for international law”.

But Singh argued that the renewal was “not an endorsement to act unilaterally” but an effort from countries to make the “whole decision-making including the inquiry process robust”, without showing signs of any bias.

Instead, campaigners highlighted a growing call for a moratorium on deep-sea mining, which seeks to halt all activity until enough scientific evidence can show that it is not harmful for marine wildlife. The initiative is now backed by 46 governments, with Mauritius, Mozamboque and the Republic of Congo becoming the latest supporters.

“The lesson from the past three weeks is clear: only a pause on exploitation, now backed by over a quarter of ISA member states, can deliver the legal certainty this moment demands and rein in a situation being driven out of control by a handful of reckless companies“, said Sofia Tsenikli, global campaign director at the Deep-Sea Conservation Coalition (DSCC).

The post Governments weigh response to US going alone on deep-sea mining appeared first on Climate Home News.

Governments weigh response to US going alone on deep-sea mining

When carbon dioxide (CO2) is released from a factory or power plant, the gas can be captured and permanently stored underground, preventing it from driving climate change.

This is the idea underpinning carbon capture and storage (CCS), a technology that is at the heart of many nations’ net-zero plans.

Influential organisations, including the Intergovernmental Panel on Climate Change (IPCC), describe CCS as “critical” for cutting emissions from key sectors – and for helping to avoid dangerous global warming.

In particular, capturing CO2 is seen as one of the only viable options for decarbonising some of the world’s highest-emitting industries, such as cement production.

The UK, for example, has committed to investing as much as £21.7bn over the coming decades in its nascent CCS industry, as part of the nation’s net-zero strategy.

Yet, in the UK and elsewhere, there has been a backlash against plans for CCS.

Citing high costs, ties to the fossil-fuel industry and a “history of poor performance”, critics describe CCS as a “dangerous distraction” or a “false climate solution”.

Time and again, the outlook for the roll-out of CCS has been scaled back, as the technology has failed to deliver as quickly as expected – and as policy support has wavered.

Furthermore, critics state that the technology remains “unproven” on the scale required to make a meaningful impact on global emissions.

In this Q&A, Carbon Brief explores the role CCS is expected to play in achieving net-zero, its record to date and the reasons it has been criticised, using the UK as an example.

What is CCS?

CCS involves capturing CO2 emissions released from a large source, such as a gas power plant or a cement factory.

The CO2 is separated from the facility’s exhaust stream, generally using a chemical solvent, before being compressed into a liquid and transported via pipeline or vehicle. The CO2 is then stored by injecting it into underground reservoirs, such as depleted oil fields or saline aquifers.

The term “CCUS” is sometimes also used, referring to the “utilisation” of CO2 to make products, including fertilisers, fuels or building materials. Such uses do not necessarily lead to permanent emissions cuts, as the CO2 can end up later being released back into the atmosphere.

(“CCS” is used in this Q&A, unless quoting another organisation that specifically refers to “CCUS”.)

The infographic below shows the stages of capturing CO2 and transporting it to be either stored or used in other applications.

Carbon capture technology was originally rolled out at US and Canadian oil wells in the early 1970s as a way to achieve “enhanced oil recovery”. This involves injecting captured CO2 into depleted wells – a process that stores CO2, but also helps to extract more oil.

This remains, by far, the most significant end use for captured CO2 worldwide, with around three-quarters of it used for this purpose.

Moreover, most of the CO2 currently captured is a by-product of gas purification – the process by which fossil fuels such as methane are separated from other, unwanted substances. Selling this CO2 can make such gas projects more economically viable.

Therefore, as shown in the chart below, which is based on International Energy Agency (IEA) data, the majority of CO2 that is both captured and used today helps the fossil-fuel industry to extract and sell more oil and gas.

CCS was first proposed as a way to deal with CO2 emissions in a 1976 academic article, which imagined injecting the captured gas into the ocean.

It is only since the early 2000s that CCS has gained traction as a proposed climate solution, with a 2005 “special report” by the IPCC exploring the topic. At that time, the authors note there were just three small-scale projects trying to capture and permanently store CO2.

Installing CCS at factories or power plants and permanently storing the CO2 would mean that, in theory, such facilities could continue using fossil fuels without contributing to climate change.

Such applications are often mentioned alongside two related technologies, both of which could be used to “suck” CO2 out of the atmosphere and, thus, deliver “negative emissions”.

One is bioenergy with carbon capture and storage (BECCS). Crops absorb CO2 as they grow and BECCS involves a power plant burning these crops, then storing the resulting CO2.

The other technology is direct air carbon capture and storage (DACCS).

These technologies are classed as “CO2 removal”, as they involve absorbing CO2 from the atmosphere using plants or machines and then storing it permanently.

By contrast, CCS installed at a factory is considered a way to avoid CO2 emitted by that specific facility from entering the atmosphere. This Q&A focuses on such applications, which account for the vast majority of existing and planned CCS.

How much CCS capacity has been built so far?

As of February 2026, there were a total of 75 operational CCS projects around the world. As noted above, almost all of them are at fossil-fuel extraction and processing sites, according to the IEA’s database.

Together, these projects capture 62.5m tonnes of CO2 (MtCO2) each year. This is equivalent to the annual greenhouse gas emissions of Ecuador.

(This compares with the 22 CCS projects, promising to capture 40MtCO2 annually, that were operational or under construction as of 2014.)

As the chart below shows, the amount of CO2 currently being captured and stored is a tiny fraction of the total emissions from fossil-fuel use.

In a 2020 report, the IEA explained that the “story of CCUS has largely been one of unmet expectations: its potential to mitigate climate change has been recognised for decades, but deployment has been slow”.

A wave of interest in CCS in the 2000s, largely from countries in Europe and North America, focused on enabling coal power plants to continue operating with lower emissions.

This interest largely petered out, as plummeting renewable energy costs weakened the case for coal plants with CCS. Today, there are only seven operating CCS-coal plants worldwide – five in China, one in the US and one in Canada.

Yet the Paris Agreement in 2015 – and the national net-zero targets that followed – highlighted the need for deep emissions cuts in sectors that previously expected to continue emitting for decades. This, once again, has fuelled interest in the use of CCS.

In recent years, there has also been growing interest in producing low-carbon “blue” hydrogen from gas with CCS.

Hydrogen is widely seen as key for decarbonising certain sectors – particularly in industry – but analyses suggest that it may be difficult to make sufficient “green” hydrogen using renewable power on the timescales required.

As the map below shows, most CCS capacity is based in the US and Canada, with other major fossil-fuel producers such as Norway, Brazil and the Gulf states also contributing.

A surge of projects have entered the global CCS pipeline in recent years. According to the IEA, 93.7MtCO2 of capture or storage capacity is under construction as of February 2026 and another 1,279.6MtCO2 is in the “planning” stages.

“Planned” projects include any initiative at early concept, feasibility or engineering study stages and the industry has a long history of projects being cancelled or delayed.

Nevertheless, this pipeline of projects could lead to a large expansion of facilities dedicated to permanent CO2 storage that does not involve extracting more oil.

The planned projects – if they are realised – would also include significant growth in sectors where CCS is virtually non-existent, such as steel, hydrogen and cement production, as shown in the chart below.

What role is CCS expected to play in reaching net-zero?

It will be impossible to stop dangerous climate change unless the world reaches net-zero emissions, according to the IPCC. The amount of global warming – and whether the Paris Agreement temperature target can be met – depends on when net-zero is reached.

Many global pathways that have been set out for achieving net-zero, including a majority of the IPCC-assessed pathways where global warming is limited to 1.5C, rely on the use of CCS at fossil-fuel plants and industrial sites.

“These models have been quite instrumental in bringing CCS back onto the agenda,” Lina Lefstad, an ecological economist at Lund University, tells Carbon Brief.

Influential organisations relying on CCS in their net-zero scenarios range from the International Renewable Energy Agency (IRENA) through to the oil company Shell. The IEA has stated that net-zero would be “virtually impossible” without CCS.

These scenarios often include 10s to 100s of times more CCS capacity being built in the coming decades. The IEA includes 1.7GtCO2 being captured by 2035 in its net-zero scenario – nearly 30 times more than is captured today.

(Some of the much higher numbers in scenarios assessed by the IPCC have been dismissed by experts as implausible, especially given the slow rollout of CCS to date.)

When considering CCS for both emissions cuts and removals, Dr Jennifer Roberts, a researcher at the University of Strathclyde and deputy director at the UK Carbon Capture and Storage Research Centre (UKCCSRC), tells Carbon Brief the situation is clear:

“From an IPCC climate modelling perspective…reaching net-zero without CCS is far more expensive, disruptive and potentially out of reach.”

This does not mean that it would be impossible to reach net-zero without using CCS. However, net-zero scenarios that use little or no CCS rely on dramatic changes elsewhere, such as much lower global energy demand.

Net-zero scenarios often include a crucial role for CCS in “hard-to-abate” sectors, referring to activities that lack available, low-cost options to fully decarbonise. In particular, CCS is widely seen as vital for decarbonising parts of heavy industry.

The IPCC sixth assessment report (AR6) summary for policymakers calls CCS a “critical mitigation option” for some sectors, including cement and chemicals. The technical summary of the AR6 Working Group III report says that “CCS will be required to mitigate remaining CO2” in industrial sectors.

The IEA describes CCS as “virtually the only technology” that can significantly cut cement emissions, which account for around 7% of the global total. (Much of this CO2 comes from chemical processes, meaning it would still be released if the industry was electrified.)

Yet, the understanding of “hard-to-abate” emissions is changing, as alternatives to CCS become cheaper and increasingly available. As a result, CCS has become a less attractive option in some sectors, as well as being seen as less vital in some others.

Carbon Brief analysis shows that the IEA has reduced its outlook for CCS in the power sector by a third, compared to its expectations in 2021, as the chart below shows.

This reflects both slow progress in deploying CCS and rapid cost reductions in renewables, which make running gas or coal power plants less attractive.

(Even prior to this adjustment, the IEA’s net-zero scenario was already at the lower end of CCS use, compared to those assessed by the IPCC.)

This declining role for CCS in the power sector would mean its use is more concentrated in industry.

Industrial sectors – particularly cement, steel and chemicals – account for 60% of the CO2 captured in 2050 under the IEA’s net-zero scenario, as shown in the figure below. The remaining 40% is roughly split between electricity generation and blue hydrogen production.

Climate NGOs Bellona and E3G have stressed that with “limited public funding, infrastructure constraints and political attention, prioritisation is essential” for CCS. Their “CCS ladder” places CCS in cement and lime production at the top – with the highest “climate value” – while power CCS has “low and decreasing value”.

Despite this, the focus of the CCS sector so far has not been in heavy industry, which represents less than 10% of announced capacity.

Another key consideration is the role governments are assigning to CCS in their national net-zero strategies.

One study found that 33 of the 67 long-term net-zero strategies submitted to the UN by governments, with a further 10 indicating some potential use.

It concluded that high-income countries that produce a lot of oil and gas, such as Canada and Norway, showed the “firmest commitment” to capturing and storing CO2.

Nations have agreed at UN climate talks to “phase down” coal power that is “unabated”. This is generally understood to mean coal power without CCS – leaving space to develop “abated” coal plants. This could allow China, for example, to continue using its sizable coal fleet with CCS to reduce emissions.

Why is CCS controversial?

Despite its role in many net-zero scenarios, CCS remains a highly contested technology.

It has long been framed in some circles as a “false solution” to climate change, that is backed and lobbied for by fossil-fuel companies to “delay” the clean-energy transition.

Critics argue that CCS is expensive – especially compared to increasingly cheap wind and solar power – in part because it significantly increases the energy requirements of a facility.

A University of Oxford working paper published in 2023 concluded that a “low-CCS” pathway to net-zero emissions would cost around $1tn less a year compared to a “high-CCS” pathway. The researchers stated that “no evidence is found for technological learning or associated cost reductions” in the development of CCS to date.

(They added that CCS is “still likely necessary” for cement and chemical production.)

Pointing to the limited progress in scaling up the technology so far, some question whether CCS can play the role envisaged in many net-zero scenarios.

Responding to the IPCC’s most recent report, for example, the Centre for International Environmental Law stated that “abated fossil fuels only exist in models”.

Proponents of CCS contest the notion that CCS is “untested” or “unreliable”, pointing to some projects that have been operating for many years. Moreover, most of the component parts that make up a working CCS project are in wide use for other purposes.

Yet, another key criticism levelled at CCS projects is that they simply do not capture enough CO2, diminishing their role as a climate solution.

There is a widespread view that CCS projects should aim to capture at least 90% of the CO2 being emitted. UK guidelines are among those targeting a higher capture rate of 95%.

The Institute for Energy Economics and Financial Analysis (IEEFA) has assessed the performance of existing projects. Its 2023 analysis is shown in the chart below.

The thinktank concluded that, in reality, most existing CCS projects are far below such capture rates, meaning they continue to emit significant amounts of CO2. (Capture is the most expensive part of the CCS process.)

Once the CO2 is captured, it must be stored. The IPCC says there is ample global geological storage available for CO2. It also says that, as long as sites are “appropriately selected and managed”, CO2 “can be permanently isolated from the atmosphere”.

Nevertheless, critics have noted that even relatively low rates of leakage along the transportation and storage chain could have a big climate impact when deployed at scale.

The continued use of gas in gas-CCS or blue hydrogen projects also brings risks of upstream emissions more broadly, such as methane leaks. (See: What are the UK’s plans for scaling up CCS?)

Considering these factors, in 2023 Climate Analytics assessed a “high CCS pathway” from the IPCC database. It concluded that if CO2 was captured at rates seen in existing facilities – around 50% – and upstream emissions remain high, CCS use could see an extra 86GtCO2e emitted by 2050.

The report found that even the IEA’s net-zero scenario, which relies on “more limited fossil CCS use”, could result in an additional 16GtCO2e due to “underperforming fossil CCS”.

All of this calls into question many uses of CCS, according to Andrew Reid, energy finance analyst at IEEFA: “Is there really any point in trying to decarbonise fossil fuels, which comes with significant technical, timing and additional cost risk?” Reid tells Carbon Brief:

“As for cement and chemicals, again, there are alternatives, but these are nascent and expensive. CCS may be a solution here and if investment is going to be made in any area, it most likely should be these.”

On the other hand, CCS advocates argue that gas, for example, is likely to be an important, “dispatchable” part of many electricity systems as nations transition to clean energy.

Prof Stuart Haszeldine, a CCS researcher at the University of Edinburgh, explains this position to Carbon Brief:

“If we’re going to burn gas, then we should be fitting CCS on that…Otherwise we’re just going to say it’s OK for us to burn lots of gas and carry on emitting.”

There is also a line of argument referred to – sometimes pejoratively – as “techno-optimism”, which often stresses CCS as a core climate solution. This was exemplified by a controversial report on climate action in 2025 by the Tony Blair Institute for Global Change (TBI), in which the former UK prime minister wrote that CCS should be “at the centre of the battle”.

This diverges from the IPCC’s conclusion that, while CCS will likely have a role in achieving net-zero emissions, its contribution will be dwarfed by that of renewables.

CCS also attracts criticism due to its connection to the fossil-fuel industry. Dr Jen Roberts at the UKCCSRC tells Carbon Brief that she agrees these links make for complicated messaging:

“CCS is critical for net-zero, but is intrinsically tied with an industry sector that is climate polluting and historically anti-climate lobbying.”

Roberts says careful policymaking, including the development of business models and standards, can support CCS in hard-to-abate sectors where it is most needed.

Some experts suggest that governments should require companies to capture and store their emissions under the “polluter pays” principle.

Roberts also notes that fossil-fuel companies have the experience and the workforce needed to scale up CCS. “Oil and gas companies can evidence a track record in multi-million or billion-dollar subsurface engineering projects,” Roberts adds.

Despite the fossil-fuel industry’s apparent support for CCS, one 2021 study co-authored by Haszeldine noted that they had, in fact, invested relatively small amounts in the technology, compared to renewables and nature-based solutions.

Lina Lefstad at Lund University questions whether the fossil-fuel industry stands to benefit financially through the deployment of CCS as much as some critics imply:

“People seem really worried that the fossil-fuel industry is going to come out the winner again, but if that was the case I think we would have large-scale CCS by now.”

What are the UK’s plans for scaling up CCS?

The UK government has committed “up to” £21.7bn of funding over 25 years to support the nation’s first five CCS projects and to make the nation an “early leader” in the sector.

This package, supported by both the former Conservative and current Labour governments, is intended to help create “clusters” of connected facilities across industrial areas of the UK.

Some have suggested that this represents a large pot of government spending, which could be raided to support more pressing priorities. Indeed, media coverage often points to CCS funding as a potential target for government cuts, or as a way to boost, say, military spending.

This is in spite of the fact that three quarters of the funding is expected to come from levies on consumers, rather than government budgets.

The first two CCS clusters, which are currently set to be deployed in the late-2020s, are the East Coast Cluster in north-east England and HyNet in north-west England and north Wales. The second two, scheduled for around 2030, are Acorn in north-east Scotland and Viking in the Humber.

The projects are expected to include blue-hydrogen production, gas power with CCS and industrial uses. The CO2 captured would be pumped into offshore saline aquifers and depleted gas fields.

Former UK energy secretary Ed Miliband has stated that CCS will “unlock” hard-to-abate sectors and play an “important role” in achieving clean power by 2030.

This position is supported by the UK government’s climate advisors at the Climate Change Committee (CCC), who have consistently stressed that CCS is “essential” for net-zero.

In the CCC’s most recent net-zero pathway, released as part of its seventh carbon budget advice, CCS contributes 2% of emissions cuts in 2030 and 8% in 2050, as shown in the chart below. (If CO2 removals using BECCS are included, this increases to 15% in 2050.)

The CCC maintains that it “cannot see a route to net-zero that does not include CCS”. Nevertheless, the committee has downgraded its expectations for CCS in recent years.

Between the CCC’s sixth and seventh carbon budget advice, its recommendations for power and industry CCS capacity dropped from 46MtCO2 to 41MtCO2.

Dr Jamie Tarlton, the committee’s CCS lead, addressed this at a conference in March 2025, stating that it was “partly because we see more opportunities for decarbonising the other sectors and reducing those residual emissions than we saw five years ago”.

More recently, the UK government also scaled back its expectations for industrial CCS in its latest carbon budget delivery plan for 2035, bringing it more in line with the CCC’s net-zero pathway. It still describes CCS as “part of the most cost-effective route to net-zero”.

The UK’s CCS plans have drawn criticism. A September 2024 letter to Miliband signed by 22 scientists and activists expressed concern about “locking the UK into a fossil-fuel based pathway”.

They note that the gas-CCS power plants and blue hydrogen facilities initially backed by the government would leave the UK reliant on gas imports, as North Sea production declines. This could be expensive and result in “upstream” emissions due to methane leaks.

(At the end of 2025, BP withdrew its involvement in one of the blue hydrogen facilities at the Teesside site. A data centre is planned for the site instead.)

Net Zero Teesside, a gas-CCS power plant in the East Coast Cluster run by BP and Equinor, has been unsuccessfully challenged in court over its emissions savings. The challenge was based on the idea that potential upstream emissions could significantly exceed any emissions cuts from CCS use.

According to a report by Carbon Tracker, the lifecycle emissions of Net Zero Teesside gas-CCS power plant would depend heavily on where it sources its fuel.

The project could cut emissions by around three-quarters, relative to an unabated gas plant, says the report. But it adds that if the plant relies on imported gas with high upstream emissions, then it might only cut emissions by a quarter.

(Most of the upstream emissions from imported gas would be released overseas, meaning they would not be counted in the UK’s official emissions inventory.)

Besides driving “gas dependence” in the UK, the government’s approach has drawn criticism for failing to ensure that CCS is prioritised in the industries that are hardest to decarbonise.

A report by the Public Accounts Committee in early 2025 took aim at the government’s cluster-based approach. It said this “does not ensure that financial support for CCUS is directed at the sectors which will need it most” – highlighting cement production.

(Of the CO2 captured in the CCC’s net-zero pathway in 2050, around 40% is in the industrial and waste sectors, while the remaining 60% is from gas power plants and the production of fuels such as hydrogen.)

Dr Andrew Boswell, the energy analyst who challenged Net Zero Teesside in court, says he is “more nuanced” when it comes to applications of CCS that do not involve gas. “There may be a case for cement, lime and waste…However, the case is unproven,” he tells Carbon Brief.

The Public Accounts Committee report also criticised the “high-risk” approach of using public funds for CCS projects, as well as slow progress in developing the technology.

Enrique Cornejo, head of energy policy at fossil-fuel trade body Offshore Energies UK, tells Carbon Brief that the UK needs to maintain momentum and deploy CCS in order to “achieve economies of scale” and to reduce the cost of the technology more broadly:

“It is indeed necessary to streamline the cluster sequencing process to ensure that emitters in sectors such as cement have a clear route to the CCS market.”

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Q&A: Does the world need ‘carbon capture and storage’ to reach net-zero?