Tag: decarbonisation

Britain’s power system has never been closer to being fossil-free

Drax EI header

Electricity generation is decarbonising faster in Britain than anywhere else in the world.[1] Changes to the way we produce power over the last six years have reduced carbon emissions by 100 million tonnes per year.[2]

The carbon savings made in Britain’s power sector are equivalent to having taken every single car and van off our roads.[3]

This puts Britain at the forefront of the wider trend towards clean electricity. Coal generation is collapsing in Germany, having fallen 20% in the last year due to rising carbon prices. Renewables have beaten fossil fuels as the largest source of generation in Europe. A third of America’s coal power stations have retired over the last decade as they switch to cleaner natural gas.

Britain’s coal power stations made international headlines in May for sitting completely idle for two full weeks. But coal is only part of the story.

The second quarter of 2019 saw three major milestones that signal Britain’s progress towards a clean power system:

  1. The carbon content of electricity hit an all-time low, falling below 100 g/kWh across a whole day for the first time;
  2. Renewables hit an all-time high, supplying more than half of Britain’s electricity over a full day; and
  3. For the first time ever, less than a tenth of electricity was produced from fossil fuels.

Going below 100 grams

100 grams of CO2 per kWh is an important number. Two years ago the Committee on Climate Change recommended it as the target for 2030 that would mean our electricity system is in line with the national commitment to decarbonise.

Britain’s electricity has dipped below 100 grams for single hours at a time, but until now it had never done so for a full day.

June 30th was a sunny Sunday with a good breeze that brought a 33°C heatwave to an end. Electricity demand was among the lowest seen all year while wind output was at a three-month high.   The carbon intensity of electricity sat below 100 g/kWh for half of the day, falling to a minimum of just 73 g/kWh in the mid-afternoon. Carbon emissions averaged over the day were 97 g/kWh, beating the previous record of 104 g/kWh set a year ago.

Fig 1 – Britain’s generation mix during June 30th that delivered electricity for less than 100g of carbon per kWh. Click to view/download.

Going above 50% renewables

June 30th was a record-breaker in a second way. Wind, solar, biomass and hydro supplied 55% of electricity demand over the day – smashing the previous daily record of 49% set last summer.

For the first day in the national grid’s history, more electricity came from renewables than any other source.

That day, Britain’s wind farms produced twice as much electricity as all fossil fuels combined. A quarter of the country’s electricity demand was met by onshore wind farms, and 15% from offshore.[4]

Despite several reactors being offline for maintenance, nuclear power provided nearly a fifth of electricity; again, more than was supplied by all fossil fuels.

Heading towards fossil-free electricity

The rise of renewable energy has been a major factor in decarbonising Britain’s electricity, complemented by the incredible fall in coal generation.

Every single coal plant in Britain has sat idle for at least two days a week since the start of spring.

It has been three years since Britain’s first zero-coal hour. A year later came the first full day, and earlier this year we saw the longest coal-free run in history, lasting 18 days. This summer could see the first full month of no coal output if this trend continues.

Fig 2 – Number of hours per week with zero generation from Britain’s coal power stations. Click to view/download.

Attention must now shift from ‘zero coal’ to ‘fossil free’.

Unabated natural gas (without carbon capture and storage) needs to be removed from the grid mix by 2050 to tackle the climate crisis and ensure the UK hits net-zero emissions across the whole economy.

At the start of this decade, Britain’s power system had never operated with less than half of electricity coming from fossil fuels.

As renewables were rolled out across the country the share of fossil fuels has fallen dramatically. By 2014, the grid was able to operate with less than one-third from fossil fuels, and by 2016 it had gone below one-fifth.

On May 26th, the share of fossil fuels in Britain’s electricity fell below 10% for the first time ever.

Fig 3 – The record minimum share of fossil fuels in Britain’s electricity mix over the last decade, with projections of the current trend to 2025. Click to view/download.

This record could have gone further though. During the afternoon, 600 MW of wind power was shed – enough to power half a million homes.

National Grid had to turn off a tenth of Scotland’s wind farms to keep the system stable and secure.

This wind power had to be replaced by gas, biomass and hydro plants elsewhere in the country, as these were located closer to demand centres, and could be fully controlled at short notice. This turn-down coincides with ten straight hours where power prices were zero or negative, going down to a minimum of –£71/MWh in the afternoon. National Grid’s bill for balancing the system that day alone came to £6.6m.

If the power system could have coped with all the renewable energy being generated, fossil fuels would have been pushed down to just 8% of the generation mix.

This highlights the challenges that National Grid face in their ambition to run a zero carbon power system by 2025 – and the tangible benefits that could already be realised today. If the trend of the last decade continues, Britain could be on course for its first ‘fossil-free’ hour as early as 2023. This will only be possible if the technical issues around voltage and inertia at times of high wind output can be tackled with new low-carbon technologies.

Other countries are grappling with questions about whether renewables can be relied on to replace coal and gas. Britain is proof that renewables can achieve things that weren’t imaginable just a decade ago.

Zero carbon electricity is “the job that can’t wait”. Britain only has a few more years to wait before the first “fossil-free” hours become a reality.


[1] Over the last decade, the carbon intensity of electricity generation in Britain has fallen faster than in any other major economy. Source: Energy Revolution: Global Outlook.

[2] In the 12 months to July 2019 carbon dioxide emissions from electricity generation totalled 60.5 million tonnes. In the 12 months to July 2013 these emissions were 160.2 million tonnes. Both figures include emissions from imported electricity, and from producing and transporting biomass. See Electric Insights and our peer-reviewed methodology paper for details of the calculation.

[3] In 2017 the UK’s cars emitted 70 million tonnes of CO2 and light-duty vehicles emitted 19 million tonnes. Source: BEIS Final greenhouse gas emissions statistics.

[4] Electric Insights now provides data on the split between onshore and offshore wind farms. Typically, around 2/3 of the country’s wind power comes from its onshore wind farms.

Laying down the pathway to carbon capture in a net zero UK

Humber bridge

The starting gun has fired and the challenge is underway. The government has officially set 2050 as the target year in which the UK will achieve carbon neutrality.

There’s no denying this economy-wide transformation will need a great deal of investment. Reaching net zero carbon emissions will require an evolutionary overhaul of not just Great Britain’s electricity system but the UK economy as a whole. And indeed, the way we live our lives and go about our business.

But that doesn’t mean it’s out of reach. Instead it will fall to technologies such as carbon capture usage and storage (CCUS), as well as bioenergy with carbon capture and storage (BECCS), to make it economical and possible.

The secret to making decarbonisation affordable

The UK’s Committee on Climate Change (CCC) estimates the price of decarbonisation will cost as little as 1% of forecast GDP per annum in 2050.

However, the Business, Energy and Industrial Strategy (BEIS) Select Committee inquiry found that failure to deploy CCUS and BECCS technology could double the cost to 2%. There are a number of reasons for this, such as the cost to jobs, productivity and living standards of shutting down industrial emitters. CCUS’s ability to contribute to a hydrogen economy can help avoid this.

Moreover, the CCC claims even with industries striving to decarbonise rapidly, as much as 100 megatonnes of hard-to-abate carbon dioxide (CO2) is expected to remain in the UK economy by 2050.

This makes carbon negative techniques and technologies, such as BECCS – which uses woody biomass that has absorbed carbon in its lifetime as forests – alongside direct air capture (DAC), the boosting of ocean plant productivity, much greater tree planting and better sequestration of carbon in soil, essential if the UK is to attain true carbon neutrality.

The importance of BECCS and CCUS in the zero carbon future is clear. Now is the time for rapid development. Not in 2030, not in 2040, but today in 2019 and into the 2020s.

But doing this requires the government to move beyond its historic policies that have failed to support the technology in the past. Progress needs long-term frameworks that provide private sector investors with the certainty they need to kick-start the commercial-scale deployment of CCUS technologies.

Laying down the tracks to negative emissions  

For carbon capture to become an integrated part of the energy system it must deliver value well beyond the energy sector. Establishing markets for products developed from captured carbon will play a role here, but to set the wheels in motion, financial frameworks are needed that can allow BECCS and CCUS to thrive.

One device that can allow the market to develop CCUS is the creation of contracts for difference (CfDs) for carbon capture. These currently exist in the low-carbon generation space, between generators and the government-owned Low Carbon Contracts Company (LCCC). Through these contracts, power generators are paid the difference between their cost of generating low carbon electricity (known as a strike price) and the price of electricity in Great Britain’s wholesale power market. If the power price in the market is higher than the strike price generators pay the difference back to the LCCC, meaning consumers are protected from price spikes too.

It means that the generator is protected from market volatility or big drops in the wholesale price of power, offering the security to invest in new technology. More than this, CfDs last many years meaning they transcend political cycles and the cost per megawatt can be reduced with a longer contract. Creating a market for carbon capture or negative emissions generation could offer the same security to generators to invest in the technology.

A CfD for BECCS should not only incentivise the building of infrastructure to capture carbon, but we must also recognise the valuable role that negative emissions can play. By compensating BECCS producers for their negative emissions, it should provide a lower cost alternative to reducing all other CO2 emissions to zero, while still ensuring that the UK can get to net zero.

Beyond installing carbon capture at existing generation sites, one of the major financial barriers to the wider deployment of CCUS and BECCS is the cost and liability associated with transporting and storing captured carbon.

A Regulated Asset Base (RAB) funding model, would encourage investment by gradually recovering the costs of transport and storage via a regulated return. This approach is currently under consideration as a means of financing other major infrastructure projects.

A RAB allows businesses, including investment and pension funds, to invest in projects under the oversight of a government regulator. In exchange for their commitment, investors can collect a fee through regular consumer and non-domestic bills.

Led by industry; guided by government

Ultimately, the current carbon trading system is based around charging polluters. But as we approach a post-coal UK and in order to achieve net zero, it’s necessary for this to evolve – from economically disincentivising emissions to incentivising carbon-negative power generation.

However, with the cost of carbon capture and negative emissions differing between types of industries and technologies, there’s a requirement to consider differentiated carbon prices to guide industry through long-term strategy. But the need for carbon capture development is too pressing for us as an industry to wait.

At Drax Power Station our BECCS pilot is just the beginning of our wider ambitions to become the first negative emissions power station. Our use of biomass already makes Drax Power Station the largest generator of renewable electricity in Great Britain. The responsibly-managed working forests our suppliers source from absorbed carbon from the atmosphere as they grew so adding carbon capture at scale to this supply chain can turn our operation from low carbon, to carbon-neutral and eventually carbon negative.

And we have bigger plans still to create a net zero carbon industrial cluster in the Humber region, in partnership with Equinor and National Grid. The cluster would deliver carbon capture at the scale needed to not just decarbonise the most carbon-intensive industrial region in the UK, but to put the country at the forefront of the decarbonisation of industry and manufacturing.

Government action is needed to make CCUS and BECCS economically sustainable at scale as an integrated part of our energy system. However, the onus is on us, the energy industry to lead development and act as trusted partners that can deliver the decarbonisation needed to reach net zero carbon by 2050.

Learn more about carbon capture, usage and storage in our series:

What is LNG and how is it cutting global shipping emissions?

Oil tanker, Gas tanker operation at oil and gas terminal.

Shipping is widely considered the most efficient form of cargo transport. As a result, it’s the transportation of choice for around 90% of world trade. But even as the most efficient, it still accounts for roughly 3% of global carbon dioxide (CO2) emissions.

This may not sound like much, but it amounts to 1 billion tonnes of COand other greenhouse gases per year – more than the UK’s total emissions output. In fact, if shipping were a country, it would be the sixth largest producer of greenhouse gas (GHG) emissions. And unless there are drastic changes, emissions related to shipping could increase from between 50% and 250% by 2050.

As well as emitting GHGs that directly contribute towards the climate emergency, big ships powered by fossil fuels such as bunker fuel (also known as heavy fuel oil) release other emissions. These include two that can have indirect impacts – sulphur dioxide (SO2) and nitrogen oxides (NOx). Both impact air quality and can have human health and environmental impacts.

As a result, the International Maritime Organization (IMO) is introducing measures that will actively look to force shipping companies to reduce their emissions. In January 2020 it will bring in new rules that dictate all vessels will need to use fuels with a sulphur content of below 0.5%.

One approach ship owners are taking to meet these targets is to fit ‘scrubbers’– devices which wash exhausts with seawater, turning the sulphur oxides emitted from burning fossil fuel oils into harmless calcium sulphate. But these will only tackle the sulphur problem, and still mean that ships emit CO2.

Another approach is switching to cleaner energy alternatives such as biofuels, batteries or even sails, but the most promising of these based on existing technology is liquefied natural gas, or LNG.

What is LNG?

In its liquid form, natural gas can be used as a fuel to power ships, replacing heavy fuel oil, which is more typically used, emissions-heavy and cheaper. But first it needs to be turned into a liquid.

To do this, raw natural gas is purified to separate out all impurities and liquids. This leaves a mixture of mostly methane and some ethane, which is passed through giant refrigerators that cool it to -162oC, in turn shrinking its volume by 600 times.

The end product is a colourless, transparent, non-toxic liquid that’s much easier to store and transport, and can be used to power specially constructed LNG-ready ships, or by ships retrofitted to run on LNG. As well as being versatile, it has the potential to reduce sulphur oxides and nitrogen oxides by 90 to 95%, while emitting 10 to 20% less COthan heavier fuel alternatives.

The cost of operating a vessel on LNG is around half that of ultra-low sulphur marine diesel (an alternative fuel option for ships aiming to lower their sulphur output), and it’s also future-proofed in a way that other low-sulphur options are not. As emissions standards become stricter in the coming years, vessels using natural gas would still fall below any threshold.

The industry is starting to take notice. Last year 78 vessels were fitted to run on LNG, the highest annual number to date.

One company that has already embraced the switch to LNG is Estonia’s Graanul Invest. Europe’s largest wood pellet producer and a supplier to Drax Power Station, Graanul is preparing to introduce custom-built vessels that run on LNG by 2020.

The new ships will have the capacity to transport around 9,000 tonnes of compressed wood pellets and Graanul estimates that switching to LNG has the potential to lower its COemissions by 25%, to cut NOx emissions by 85%, and to almost completely eliminate SOand particulate matter pollution.  

Is LNG shipping’s only viable option?

LNG might be leading the charge towards cleaner shipping, but it’s not the only solution on the table. Another potential is using advanced sail technology to harness wind, which helps power large cargo ships. More than just an innovative way to upscale a centuries-old method of navigating the seas, it is one that could potentially be retrofitted to cargo ships and significantly reduce emissions.

Drax is currently taking part in a study with the Smart Green Shipping Alliance, Danish dry bulk cargo transporter Ultrabulk and Humphreys Yacht Design, to assess the possibility of retrofitting innovative sail technology onto one of its ships for importing biomass.

Manufacturers are also looking at battery power as a route to lowering emissions. Last year, boats using battery-fitted technology similar to that used by plug-in cars were developed for use in Norway, Belgium and the Netherlands, while Dutch company Port-Liner are currently building two giant all-electric barges – dubbed ‘Tesla ships’ – that will be powered by battery packs and can carry up to 280 containers.

Then there are projects exploring the use of ammonia (which can be produced from air and water using renewable electricity), and hydrogen fuel cell technology. In short, there are many options on the table, but few that can be implemented quickly, and at scale – two things which are needed by the industry. Judged by these criteria, LNG remains the frontrunner.

There are currently just 125 ships worldwide using LNG, but these numbers are expected to increase by between 400 and 600 by 2020. Given that the world fleet boasts more than 60,000 commercial ships, this remains a drop in the ocean, but with the right support it could be the start of a large scale move towards cleaner waterways.

What is a fuel cell and how will they help power the future?

A model fuel cell car

NASA Museum, Houston, Texas

How do you get a drink in space? That was one of the challenges for NASA in the 1960s and 70s when its Gemini and Apollo programmes were first preparing to take humans into space.

The answer, it turned out, surprisingly lay in the electricity source of the capsules’ control modules. Primitive by today’s standard, these panels were powered by what are known as fuel cells, which combined hydrogen and oxygen to generate electricity. The by-product of this reaction is heat but also water – pure enough for astronauts to drink.

Fuel cells offered NASA a much better option than the clunky batteries and inefficient solar arrays of the 1960s, and today they still remain on the forefront of energy technology, presenting the opportunity to clean up roads, power buildings and even help to reduce and carbon dioxide (CO2) emissions from power stations.

Power through reaction

At its most basic, a fuel cell is a device that uses a fuel source to generate electricity through a series of chemical reactions.

All fuel cells consist of three segments, two catalytic electrodes – a negatively charged anode on one side and a positively charged cathode on the other, and an electrolyte separating them. In a simple fuel cell, hydrogen, the most abundant element in the universe, is pumped to one electrode and oxygen to the other. Two different reactions then occur at the interfaces between the segments which generates electricity and water.

What allows this reaction to generate electricity is the electrolyte, which selectively transports charged particles from one electrode to the other. These charged molecules link the two reactions at the cathode and anode together and allow the overall reaction to occur. When the chemicals fed into the cell react at the electrodes, it creates an electrical current that can be harnessed as a power source.

Many different kinds of chemicals can be used in a fuel cell, such as natural gas or propane instead of hydrogen. A fuel cell is usually named based on the electrolyte used. Different electrolytes selectively transport different molecules across. The catalysts at either side are specialised to ensure that the correct reactions can occur at a fast enough rate.

For the Apollo missions, for example, NASA used alkaline fuel cells with potassium hydroxide electrolytes, but other types such as phosphoric acids, molten carbonates, or even solid ceramic electrolytes also exist.

The by-products to come out of a fuel cell all depend on what goes into it, however, their ability to generate electricity while creating few emissions, means they could have a key role to play in decarbonisation.

Fuel cells as a battery alternative

Fuel cells, like batteries, can store potential energy (in the form of chemicals), and then quickly produce an electrical current when needed. Their key difference, however, is that while batteries will eventually run out of power and need to be recharged, fuel cells will continue to function and produce electricity so long as there is fuel being fed in.

One of the most promising uses for fuel cells as an alternative to batteries is in electric vehicles.

Rachel Grima, a Research and Innovation Engineer at Drax, explains:

“Because it’s so light, hydrogen has a lot of potential when it comes to larger vehicles, like trucks and boats. Whereas battery-powered trucks are more difficult to design because they’re so heavy.”

These vehicles can pull in oxygen from the surrounding air to react with the stored hydrogen, producing only heat and water vapour as waste products. Which – coupled with an expanding network of hydrogen fuelling stations around the UK, Europe and US – makes them a transport fuel with a potentially big future.

Fuel cells, in conjunction with electrolysers, can also operate as large-scale storage option. Electrolysers operate in reverse to fuel cells, using excess electricity from the grid to produce hydrogen from water and storing it until it’s needed. When there is demand for electricity, the hydrogen is released and electricity generation begins in the fuel cell.

A project on the islands of Orkney is using the excess electricity generated by local, community-owned wind turbines to power a electrolyser and store hydrogen, that can be transported to fuel cells around the archipelago.

Fuel cells’ ability to take chemicals and generate electricity is also leading to experiments at Drax for one of the most important areas in energy today: carbon capture.

Turning COto power

Drax is already piloting bioenergy carbon capture and storage technologies, but fuel cells offer the unique ability to capture and use carbon while also adding another form of electricity generation to Drax Power Station.

“We’re looking at using a molten carbonate fuel cell that operates on natural gas, oxygen and CO2,” says Grima. “It’s basic chemistry that we can exploit to do carbon capture.”

The molten carbonate, a 600 degrees Celsius liquid made up of either lithium potassium or lithiumsodium carbonate sits in a ceramic matrix and functions as the electrolyte in the fuel cell. Natural gas and steam enter on one side and pass through a reformer that converts them into hydrogen and CO2.

On the other side, flue gas – the emissions (including biogenic CO2) which normally enter the atmosphere from Drax’s biomass units – is captured and fed into the cell alongside air from the atmosphere. The CO2and oxygen (O2) pass over the electrode where they form carbonate (CO32-) which is transported across the electrolyte to then react with the hydrogen (H2), creating an electrical charge.

“It’s like combining an open cycle gas turbine (OCGT) with carbon capture,” says Grima. “It has the electrical efficiency of an OCGT. But the difference is it captures COfrom our biomass units as well as its own CO2.”

Along with capturing and using CO2, the fuel cell also reduces nitrogen oxides (NOx) emissions from the flue gas, some of which are destroyed when the O2and CO2 react at the electrode.

From the side of the cell where flue gas enters a CO2-depleted gas is released. On the other side of the cell the by-products are water and CO2.

During a government-supported front end engineering and design (FEED) study starting this spring, this COwill also be captured, then fed through a pipeline running from Drax Power Station into the greenhouse of a nearby salad grower. Here it will act to accelerate the growth of tomatoes.

The partnership between Drax, FuelCell Energy, P3P Partners and the Department of Business, Energy and Industrial Strategy could provide an additional opportunity for the UK’s biggest renewable power generator to deploy bioenergy carbon capture usage and storage (BECCUS) at scale in the mid 2020s.

From powering space ships in the 70s to offering greenhouse-gas free transport, fuel cells continue to advance. As low-carbon electricity sources become more important they’re set to play a bigger role yet.

Learn more about carbon capture, usage and storage in our series:

How the market decides where Great Britain gets its electricity from

Set of vintage glowing light bulbs on black background

The make-up of Great Britain’s power system changes constantly. Demand is always changing; in winter it may peak at 50 gigawatts (GW) but overnight in summer it will be less than 20 GW. Some days wind is the biggest source of the country’s electricity generation, other days it’s gas. Then there are days when, for a few hours, solar takes the top spot in the middle of the day and nuclear during the night.

In the past, Great Britain’s electricity came almost entirely from big coal and nuclear power stations. But as the need for decarbonisation has grown, so has the number of sources feeding electricity to the grid, creating an ever more complex and varied system made up of technologies that behave in very different ways. For example, some sources are weather dependent and can’t generate all day every day others stop and start flexibly to smooth out changes in demand or intermittent generation.

But in the event all sources are available, what dictates which sources actually generate, and when? The overriding influence is economics – the costs of starting up and running a turbine, the price of fuel or taxes on carbon emissions.

In Great Britain, electricity’s wholesale price is not set in stone by an entity such as a regulator. Instead it’s negotiated via trading over the course of a day between generators (power stations, storage and wind turbines) and suppliers, who transmit that electricity to consumers.

As a result, the price of electricity fluctuates every half hour, responding to factors such as demand, cost of fuels, availability of resources (such as sun and wind), and carbon taxes.

For an example of the scale at which it fluctuates, we can look at the period 1-4 June this year, when the index price of electricity ranged from over £55/MWh down to around £5/MWh (see chart, above).

But while these figures speak to the overall price of a megawatt on the system, they don’t reflect all the individual sources, nor their individual costs. Each of the multiple sources on the grid have their own operating costs fluctuating on a similar basis.

These changing prices give rise to what is known as the merit order, a fluid, theoretical ranking of generation sources. This is not set by any regulator, economist or even by traders. Rather it is a naturally occurring, financial occurrence that explains what sources of electricity generation are feeding power onto the grid day-to-day.

What is the merit order?

The merit order dictates which sources of generation will deliver power to the grid by ranking them in ascending order of price together with the amount of electricity generated. This then determines the order in which power sources are brought onto the system. Ultimately, suppliers want the right amount of electricity for the best possible price, so in a system made up of many sources, it is the lowest cost, highest yield option that is brought online first, which in theory helps keep overall electricity prices down.

North Sea Wind Farm, Redcar

This means it is often sources such as wind and solar, which have no fuel costs, that sit at the top of the merit order. Nuclear may come next as it continually generates a large amount of power for a low cost, while taking a long time to turn down or off. At the opposite end of the merit order are sources like coal and oil, which have high fuel and carbon dioxide (CO2) emission costs (such as carbon taxes and the European Emission Trading scheme).

However, the merit order isn’t a set of hard and fast rules. “It’s an assumption used by traders or market commentators to guide what is likely to run and thereby the likely market price,” says Ian Foy, Drax Head of Ancillary Services. “There is no published merit order. It is like Santa Claus – it doesn’t exist, but it makes explaining Christmas easier.”

 The intricacies of being in and out of merit

If a generating unit is required to meet demand then it’s described as ‘in merit’, if it is not required at any particular point in time then it’s ‘out of merit’ – there’s no point in suppliers paying for another power station, for example, to start generating if demand is already being met.

“If the market is efficient, we generate from the lowest cost source at all times,” says Foy. “Costs are not simple, for example, you have to take into account the cost of starting or shutting down generating units. However, costs are not publicly shared so there’s no single view of the merit order. Each party has its own perspective on it.”

It means the merit order changes from season-to-season, day-to-day and hour-to-hour, as rates of supply and demand, and the availability of resources change.

Dungeness Nuclear Power Station in Kent

“An obvious example is gas tends to be cheaper in summer than winter, when it’s not being used for heating. Coal and gas also switch as global prices change,” says Foy. “Availability also changes over the year. There’s more solar in summer, but none in the morning and evening peaks of winter.”

There are also practical issues, such as repairs being made on wind and hydro turbines or planned maintenance outages on thermal and nuclear power stations, putting those generators out of action and knocking them out of merit.

And because the merit order is not an implemented working scheme, it can be deliberately manipulated by outside forces. One of the ways this is most clearly seen is in carbon pricing.

Merit in a changing system

The Carbon Price Support tax paid by coal and gas generators in Great Britain, alongside the European Emissions Trading System have increased the cost of fossil fuel generation: gas, oil and coal. Levied as £/tonne of CO2 emitted this has the effect of pushing fossil generation down the merit order. With coal emitting double the CO2 per unit of electricity compared to gas, we can see how the merit order can be influenced to achieve environmental outcomes.

This has helped steer Great Britain towards record breaking coal-free periods and stimulated the building of low carbon generation sources.

Other sources, such as interconnection with Europe and power storage facilities, also slot into the merit order. Their position often shifts due to highly variable prices dependent on power generation in neighbouring countries or the amount of electricity that can be stored at a low cost, respectively.

The grid is ever-changing. Over the last two decades we’ve seen huge shifts in how power is generated and delivered. This is unlikely to slow down in the near future, but the merit order will remain. Like the grid, it is in a constant state of change, adapting to the many moving parts of the electricity system. As long as Great Britain maintains its open electricity trading market, the merit order will continue to dictate where the country’s power comes from.

How close is Great Britain’s electricity to zero-carbon emissions?

Renewable energy mix, light bulb visual

Demand for electricity might have been 6% lower in the first three months of 2019 than in last year’s first quarter but the demand for lower carbon power is only growing and there’s more pressure than ever for global industries to decarbonise more rapidly.

Aided by a significantly milder winter than last year, Great Britain’s electricity sector continued to make further progress in reducing carbon emissions in the first quarter (Q1) of 2019.

The carbon intensity of Great Britain’s electricity was almost 20% lower in Q1 2019 than in the same period last year. This was driven by a significant decrease in coal usage, with 581 coal-free hours in total over the period – eight times more than in Q1 2018. This trend has only increased, with May seeing the country’s first coal-free week in modern times.

The findings come from Electric Insights, a report commissioned by Drax and written independently by researchers from Imperial College London, that analyses Great Britain’s electricity consumption and looks at what the future might hold.

As public, commercial and political demand for lower carbon emissions mounts, the question for the power system is: can it truly reach zero-emissions?

Keeping a zero-carbon system stable

Quarter after quarter, the carbon intensity of Great Britain’s electricity system has declined. From 545 grams of carbon dioxide (CO2) per kilowatt hour (g/kWh) in Q1 2012, to just over 200 g/kWh last quarter. For a single hour, carbon emissions have fallen as low as just 56 g/kWh. But how soon can that figure reach all the way down to net-zero carbon emissions?

The National Grid’s Electricity System Operator (ESO), believes it could be as soon as 2025. But some serious changes are needed to make it possible for the system to operate safely and efficiently, when you have fewer sources offering balancing services like reserve power, inertia, frequency response and voltage control.

The National Grid ESO believes an approach that establishes a marketplace for trading services holds the solution. The hope is that competition will breed new innovation and bring new technologies such as grid-scale storage and AI into the commercial energy markets, offering reserve power and more accurate forecasting for solar and wind power.

For the meantime, weather-dependent technologies are a key source of renewable electricity in Great Britain, with wind making up more than 20% of all generation in Q1 2019. However, with wind capacity only expected to increase, how should the system react when it’s not an option?

Read the full article, co-authored by Julian Leslie, Head of National Control, National Grid ESO: How low can we go?

We cannot control the weather – but we can harness its power

Today there are around 20 gigawatts (GW) of wind capacity installed around Great Britain, and this is forecast to double to 40 GW in the next seven years. However, average wind output can fluctuate between 2 GW one day and 12 GW the next – as happened twice in January. It highlights the ongoing needs for flexibility and diversity of sources in the electricity system even as it decarbonises.

There are a number of ways to make up for shortfalls in wind generation. The most obvious of which is through other existing sources. There is more solar installed around the county than any source of generation (except gas), at 12.9 GW and sun power helped meet demand during a wind drought last summer. Solar averaged 1.3 GW over the last 12 months, this is more than coal which accounted for 1.1 GW.

However, storage will also be important in delivering low or zero-carbon sources of electricity when there is neither wind nor sufficient sunlight. At present this includes pumped storage and some battery technologies, but in future will include greater use of grid-scale lithium-ion batteries, as well as vehicle-to-grid systems that can take advantage of power stored in idle electric cars.

New fuels, particularly hydrogen, also have the potential to meet demand and help create a wider lower-carbon economy for heating, as well as vehicle fuel, with water as the only emission.

Hydrogen can be produced from natural gas or using excess electricity from renewable sources, or through carbon capture from industrial emissions. It can then be stored for a long time and at scale, before being used to generate electricity rapidly when needed.

Another increasingly important source of Great Britain’s electricity is interconnectors. However, they are not yet being used in a way that can support gaps in the electricity system, with Northern European countries normally all experiencing the same weather – and wind levels – at the same time.

Read the full article: What to do when the wind doesn’t blow?

A bigger future for interconnection

Great Britain added a new power source to its electricity system in Q1 2019, in the form of Belgium. The opening of the £600 million NEMO link between Kent and Zeebrugge added another 1 GW of interconnection capacity.

It joins connections to France, the Netherlands, Northern Ireland and the Republic of Ireland to bring Great Britain’s total interconnection capacity to 5 GW. These links accounted for 7.9% of the 78 terawatt hours (TWh) of electricity consumed over the quarter.

Electricity from imports also set new records for a daily average of 4.3 GW on 24 February, accounting for 12.9% of total consumption, and a monthly average in March when it made up 10.6% of consumption. These records represent the first time Great Britain fell below 90% for electricity self-sufficiency.

With 3.4 GW of new interconnectors under construction coming online by 2022 and 9.1 GW more planned to be completed over the next five years, Great Britain’s neighbours are set to play a growing role in the country’s electricity mix.

However, while interconnectors offer an often cost-effective way for Great Britain to ensure electricity supply meets demand, the carbon intensity of neighbouring countries’ electricity should also be considered.

Read the full article: 10% of electricity now generated abroad

The need for cross-border decarbonisation

The new link to Belgium has imported, rather than exported, electricity every day since it began operations, as Belgium has the lowest natural gas prices in Europe and its power stations pay £16 per tonne less for carbon emissions than their British counterparts. This makes it cheaper to import, and less carbon intense, than electricity from the more coal-dependant Netherlands and Ireland.

Planned links to Germany and Denmark could allow Great Britain to import more renewable power. However, if there is a wind drought across Northern Europe these countries often turn to their emissions-heavy coal or even dirtier lignite sources.

France is currently Great Britain’s cleanest source of imports, mostly using nuclear and renewable generation. However, when the North Sea Link opens in 2021, it will give Great Britain access to Norway’s abundance of hydro-power to plug gaps in renewable generation.

Considering the carbon intensity of Great Britain’s imports is important because the decarbonisation needed to address the global climate change emergency can’t be solved by one country alone. For electricity emissions to go as low as they can it takes collaboration that goes across borders.

Read the full article: Where do Britain’s imports come from?

Explore the quarter’s data in detail by visiting ElectricInsights.co.uk. Read the full report.

Commissioned by Drax, Electric Insights is produced, independently, by a team of academics from Imperial College London, led by Dr Iain Staffell and facilitated by the College’s consultancy company – Imperial Consultants.

Capturing carbon emissions from the atmosphere could transform these industries

Countries, companies and industries around the world are racing to find ways to reduce their emissions. But looking slightly further down the line there is in fact a grander aim: negative emissions.

Negative emissions technologies (NETs) can actually absorb more carbon dioxide (CO2) from the atmosphere than they emit, and they’re vitally important for avoiding catastrophic, man-made climate change. Without NETs it could be impossible to achieve the Intergovernmental Panel on Climate Change’s ambition of keeping temperatures under 1.5 degrees Celsius above pre-industrial levels.

One example already being implemented is bioenergy with carbon capture and storage (BECCS). It is what its name suggests. Using technologies to capture and store the CO2 generated during the process of energy generation from biomass or organic materials rather than releasing it into the atmosphere.

BECCS holds vast potential in the electricity generation industry. Drax Power Station is currently piloting one form of this technology on one of its biomass units to capture as much as a tonne of CO2 a day. But if it were deployed across all its biomass units, BECCS technology could make it the world’s first negative emissions power station.

Beyond the power industry, however, there’s scope for growth across other industries once the biomass is sourced sustainably. There are already five sites around the world where BECCS is being trialled and implemented at scale, laying the road to negative emissions.

Storing CO2 from ethanol production in the Illinois Basin

The ethanol production industry is already seeing significant deployment of BECCS, including the largest installation of the technology operating in the world. The Illinois Industrial Carbon Capture and Storage project is part of a corn-to-ethanol plant in the US that has the capacity to capture 1 million tonnes of CO2 every year.

Here, corn is used to create ethanol by fermenting it in an oxygen-deprived environment. This process creates CO2 as a by-product, which is captured and stored permanently in pores within the sandstone of the Illinois Basin under the facility.

Researchers believe with further development the site could capture as much as 250 million tonnes each year.

Norway’s cement challenge  

Concrete is one of the world’s most versatile building materials. As a result it is the second most-consumed material in the world behind water – more than 10 billion tonnes of it is produced every year. However, its key ingredient – cement, which acts as concrete’s binding agent – is made using a hugely carbon-intensive manufacturing process and now accounts for as much as 6% of all global carbon emissions.

The Norcem Cement plant in Brevik, South-East Norway, has been experimenting with using biomass to power the kilns used to create its cement (which must heat ingredients to 1,500 degrees Celsius). Now it’s taking this a step further by becoming part of the country’s ambitious Full Chain CCS project.

The project will see 400,000 tonnes of CO2 captured annually, which will then be transported by ship to a storage site on Norway’s western coast. From here a pipeline will transport the CO2 50 kilometres away and deposit it deep below the North Sea’s bed.

The plan has the potential to work at an even bigger scale. The pipeline will be capable of receiving as much as 4 million tonnes of CO2 per year, meaning it could even import and store carbon from other countries.

Burning waste and growing algae

In a world that seems increasingly unsure how to safely deal with its waste, the idea of incinerating it and making use of the heat this produces seems widely beneficial. But combusting any solid means releasing carbon emissions.

In Japan, however, a biomass-fired waste incineration plant is changing this by being the first in the world to capture its carbon emissions.

To get this project up and running, Toshiba, the firm behind the project, had to overcome unique challenges. For example, waste incineration produces a greater mix of chemicals than in ethanol or power production, including some that are corrosive to the metal pipes normally used in carbon capture.

Now running at commercial scale, the Saga City waste incineration plant isn’t just capturing CO2, it’s also utilising it to cultivate crops at a nearby algae farm. The carbon is being absorbed and used to grow algae for use in commercial scale cosmetic products, such as body and skin lotions.

Carbon isn’t the only thing finding new use at the facility. Reconstituted scrap metal from the plant is being used to make the medals for the 2020 Tokyo Olympics.

The carbon capture system has been operational since 2016 and is capable of capturing 3,000 tonnes of CO2 a year, but it isn’t the region’s first deployments of BECCS. 

Fully integrating BECCS into biomass power

Nearby, the Mikawa power plant on the Fukuoka Prefecture, is leading the race in Asia to fully integrate carbon capture technology into a biomass power station.

The 50 MW power station successfully piloted carbon capture in 2009 through a partnership with Toshiba. At the time it was powered by coal, however, in 2017, the plant upgraded to a 100% biomass boiler fuelled by palm kernel shells – a waste product from palm oil extraction mills. Now it’s in the process of ramping up its carbon capture capabilities, with a target of being operational in 2020.

The system – which after Drax will be the second plant in the world to capture carbon using 100% biomass feedstock – will have the capacity to capture more than 50% of the biomass plant’s CO2 emissions, or as much as 180,000 tonnes per year. Japan’s government is now supporting efforts to develop CO2 transportation and potential offshore storage solutions for next year.

Pulping wood and growing food

BECCS technology has yet to be deployed in the paper industry to the same extent as in other organic-matter-based industries. But with many pulp and paper mills already using by-products, such as hog fuel, in generating power for their sites, it’s a prime area for BECCS growth.

In Saint-Felicien, Quebec, commercial-scale carbon capture technology is being deployed at a pulp mill run by Resolute Forest Products, and, as of March 2019, had a capacity of capturing 11,000 tonnes of CO2 a year. Rather than storage, however, it supplies the carbon to a cucumber-growing greenhouse next door to the mill, as well as supplying enough warm water to meet 25% of the greenhouses’ heating needs.

Both long established biomass-based industries like ethanol and paper, and new sectors like electricity, are now adopting BECCS technology and driving innovation.

The biomass feedstocks involved in BECCS must, however, be sourced sustainably – or else a positive climate impact could be at the expense of environmental degradation elsewhere. ‘It should be possible to expand biomass supply in a sustainable way,’ found a recent ‘Global biomass markets’ report from Ricardo AEA for the UK’s Department for Business, Energy and Industrial Strategy (BEIS).

While it’s still a complex technology to deploy, BECCS is increasingly operating at larger scales and growing to the level needed to seriously reduce industrial CO2 emissions and help to combat climate change.

Learn more about carbon capture, usage and storage in our series:

Heating the future

We all want our homes and our workplaces to be warm and cosy, but not at the cost of catastrophic climate change. That’s why decarbonising our heating is a challenge that simply cannot be ignored.

Making decisions about how this is done requires careful consideration and a detailed, deliverable national strategy.

Here we discuss the key issues in decarbonising heat.

The numbers

The Climate Change Act commits the UK to reducing its carbon emissions by at least 80 per cent of their 1990 levels by 2050.

As heating our homes and workplaces is responsible for almost one fifth of our country’s total carbon emissions, we are clearly going to need to make huge changes to the way we keep our homes and workplaces warm in order to meet those commitments.

‘Over 80% of energy used in homes is for heating – suggesting large potential for continued decarbonisation.’

— Energising Britain: Progress, impacts and outlook for transforming Britain’s energy system, by I. Staffell, M. Jansen, A. Chase, C. Lewis and E. Cotton, 2018.

Improved insulation, greater energy efficiency and electrification will all reduce the need for fossil fuel-based heating. However, domestic energy efficiency in the UK is lagging well behind targets, although the situation varies from region to region – and such targets do not even exist yet for the non-domestic sector.

Roof insulation material

Even in a low or zero-carbon future, we’re still going to need to keep our homes and workplaces warm – and affordably.

Future policy

Against this backdrop, in March 2018, the UK Government issued a call for evidence for a Future Framework for Heat in Buildings.

Chancellor Phillip Hammond introduced a new ‘future homes standard’ in his 2019 Spring Budget Statement, “mandating the end of fossil fuel heating systems.” Gas boilers will be banned from all new homes from 2025.

A major change is coming. But what else will we need to change in order to transform our heating systems?

1. More electrification

The most noticeable change in the way we heat our homes and workspaces in the future may well come from the need to switch from systems that fuelled by natural gas to ones that are driven by electricity.

Some technologies that can offer a solution to the challenge of decarbonising heating depend on a significant amount of electricity to keep the warmth flowing.

For instance, the hybrid heat pump scenario which is currently supported by the Committee on Climate Change would see up to 85% of a consumer’s need for heat being met by low-carbon electricity.

To give some context to that figure, according to the Committee, 85 per cent of the UK’s homes now rely on fossil-fuel derived natural gas for heating and hot water, and on average these: “currently emit around 2tCO2 per household per year… which represents around one tenth of the average UK household’s carbon footprint.”

Changing from a situation where our heating depends on 85% fossil fuel gas to one that depends on 85% low or zero carbon electricity is little short of a complete transformation. Given that the new future homes standard is due to be introduced in less than six years, this transformation will need to happen quickly.

Of course, a great deal of the extra electricity needed will come from intermittent renewables such as wind turbines and solar panels – especially as the cost of renewable electricity is falling.

Much of that power looks likely to be supplied by distributed sources rather than those integrated into the national grid. Indeed, since 2011, power generation capacity connected directly to the distribution network grew from 12 gigawatts (GW) to more than 40 GW by the end of 2017, according to estimates from energy experts Cornwall Insight in a report for our B2B energy supply business, Haven Power.

With so much of our electricity reliant on the weather, there will still be a need for dispatchable and flexible thermal sources and energy storage, such as Drax and Cruachan power stations. Their centralised power generation can be turned up and fed directly into the national transmission system at short notice, to keep our heating running and our homes warm.

Dam and reservoir, Cruachan Power Station, Scotland

Such a transformation will obviously require careful strategic planning as well as an enormous amount of investment.

There may well be no single solution to the challenge of heat decarbonisation, rather a number of different solutions that depend on where people live and work, their individual circumstances, the energy efficiency of their homes and the resources they have close at hand.

But while it has previously been reported that the overall or system costs of electrifying heating could be as much as three times the cost of using gas, another study suggests that the costs could be much closer.

2. More heat pumps

Heat pumps that absorb environmental warmth and use it to provide low carbon heating have always been considered a possible option for the four million homes and countless workplaces that are not currently connected to the UK’s mains gas network.

Recently expert opinion has been changing with hybrid heat pumps seen as a workable solution even for homes and workplaces that are connected to gas supplies. Indeed, in 2018 the Committee on Climate Change stated that hybrid heat pumps: “can be the lowest cost option where homes are sufficiently insulated, or can be insulated affordably.” This means that they may be one of the simplest and most affordable options to provide the heating of the future.

Hybrid heat pumps draw heat from the air or ground around them and use a boiler to provide extra heat when the weather is exceptionally cold. In a low carbon future, that boiler could be fuelled by biogas. In a zero carbon situation, it could be powered by hydrogen.

Heat pumps can be air-source (ASHP) – absorbing warmth from the atmosphere like the heat exchanger in your fridge in reverse – or ground source (GSHP). GSHPs absorb heat through on a network of pipes (a ground loop) buried or a vertical borehole drilled in the earth outside your home or workplace.

Both ASHPs and GSHPs can be used to support underfloor heating or a radiator system, though neither will provide water heated to the high temperature a natural gas boiler will reach to keep radiators hot.

And even though the warmth they absorb is free, heat pumps depend on a supply of electricity to condense it and to bring it back to the heating system inside the house.

This electricity could be generated by distributed power from local solar PV, wind turbines, drawn from batteries or even from the low carbon grid of the future.

It is worth noting that the size of heat pumps and the amount of land they require – especially GSHP – makes them a less attractive solution for people who live or work in built up areas such as cities. While for those who live in blocks of flats, it is difficult to see how individual heat pumps could be a practical solution.

3. More hydrogen

The idea of switching the mains gas grid to store and transport hydrogen has long appealed as a potential solution to the challenge of decarbonising heating. Renewable hydrogen could then be burnt in domestic boilers similar to those we currently use for natural gas.

The benefits are many. Hydrogen produces no carbon emissions when burnt, and can be stored and transported in much the same way as natural gas (provided old metal pipes have been replaced with modern alternatives).

And given the sunk costs involved in the existing gas grid and in the network of pipes and radiators already installed in tens of millions of homes, hydrogen has always been expected to be the lowest cost option too.

However, according to the Committee on Climate Change’s latest findings, hydrogen should not be seen as a ‘silver bullet’ solution, capable of transforming our entire heating landscape in a single change.

The main reasons they give for this judgment are the relatively high cost of the electricity required to produce sufficient hydrogen to power tens of millions of boilers, the undesirability of relying on substantial imports of hydrogen, and the lack of a carbon-free method to supply the gas cost-effectively at scale.

Hydrogen could, however, be produced by gas reformation of the emissions retained by bioenergy carbon capture and storage (BECCS) such as that being pioneered at Drax Power Station. Carbon capture use and storage (CCUS), of which BECCS is the renewable variant, is supported by the UK government through its Clean Growth Strategy as it has potential to accelerate decarbonisation in power and industrial sectors.

Extremely rapid progress to provide hydrogen in sufficient quantities from BECCS is unlikely – but the first schemes could begin operating in the late 2020s.

Hydrogen production also has the potential to radically transform the economics of CCUS, making it a much more attractive investment.

It was originally assumed that the power required to drive the energy-intensive process of hydrogen created via electrolysis would come from surplus electricity generated by intermittent renewables at times of low demand. However, that surplus is not now generally regarded as likely to be sufficiently large to be relied upon. 

It is these limitations, together with a comprehensive model of the likely costs involved in different approaches to decarbonisation, that led the Committee on Climate Change to suggest that hybrid heat pumps could provide the bulk of domestic heating in the future.

At present, it seems likely that converting to hydrogen-fuelled boilers will mainly be an attractive option for those who live and work near areas where the renewable fuel can be most easily created and stored. The north of England is a prime example – close to the energy and carbon intensive areas of the Humber and Tees valleys where CCUS and hydrogen clusters could be located with good access to North Sea carbon stores such as aquifers and former gas fields.

4. More solar

Many homes in the UK – especially in the south – could be heated electrically without carbon emissions at the point of use.

Solar thermal (for water heating) or solar PVs (for electric and water heating) common sights on domestic property rooftops. The intermittency of solar power need not be an issue as the electricity generated could then be stored in batteries ‘behind the meter’ until it is needed.

However, the lack of sufficient daylight for much of the year in many parts of the UK could, together with the still relatively high cost of battery storage, still mean that this would not necessarily be a solution that can be applied at scale to millions of homes and workplaces all year round.

As the cost of battery storage continues to fall, it may well be that solar becomes a more practical and cost-effective solution.

5. More biomass

More geothermal

Sustainably sourced compressed wood pellets and biomass boilers have long been proposed as a potential solution to decarbonising heating for the many people who live and work off the mains gas grid. Bioenergy as a whole – including biogas as well as wood pellets – now provides around four percent of UK heat, up from 1.4% in 2008.

The main barriers to this are the current relatively high cost of biomass boilers. This is currently offset by the Renewable Heating Incentive (RHI) which the UK government has committed to continuing until 2021.

As this solution is adopted by more consumers, it is anticipated that the real costs of such new technology will fall as economies of scale start to take effect in much the same way that solar PV and battery technology has recently become more affordable.

6. More geothermal

Ruins of a tin mine, Wheal Coates Mine, St. Agnes, Cornwall, England

Geothermal energy uses the heat stored beneath the surface of our planet itself to provide the energy we need.

While in some countries such as Iceland, geothermal energy is used to drive turbines to generate electricity that is then used to provide power for heating, it is envisaged that in the UK it could be converted into warmth through massive heat pumps that provide heating to entire communities – especially those in former mining areas. There is already one geothermal district heating scheme in operation in the UK, in Southampton.

It is envisaged that such geothermal schemes would work most effectively at a district level, providing zero carbon heat to many homes and workplaces. According to a recent report, geothermal energy has the potential to “produce up to 20 per cent of UK electricity and heat for millions.”

At present, drilling is being carried out to see if geothermal heating could be viable in Cornwall. However, there is no reason why it could not be used in disused coalmines too where ground source heat pumps (GSHPs) would absorb and condense the required heat. This means that geothermal could have strong potential as a solution to the challenge of decarbonisation for former mining communities.

7. More CHP

Cory Riverside Energy’s Resource Recovery Facility in Belvedere, London, could be operated as a CHP plant in the future

By using the heat created in thermal renewable electricity generation – such as biomass – in combined heat and power schemes, businesses and individuals can reduce their energy costs and their carbon emissions. Such schemes can work well for new developments on a district basis, and are already popular in mainland Europe, especially Sweden, Denmark and Switzerland.

Warm homes, factories and offices

There are already a number of viable solutions to decarbonising heating in the UK. They rely on smart policy, smarter technology and customers taking control of their energy.

Rather than any one of these technologies providing a single solution that can help every consumer and business in the country to meet the challenge in the same way, it is more likely that it will be met by a number of different solutions, depending on geography, cost and individual circumstances. These will sometimes also work in concert rather than alone.

The UK has made solid progress on reducing carbon emissions – especially in power generation. When it comes to heating buildings, rapid decarbonisation is now needed. And that decarbonisation must avoid fuel poverty and help to rebalance the economy.

Find out more about energy in buildings in Energising Britain: Progress, impacts and outlook for transforming Britain’s energy system.

Can Great Britain keep breaking renewable records?

How low carbon can Britain’s electricity go? As low as zero carbon still seems a long way off but  every year records continue to be broken for all types of renewable electricity. 2018 was no different.

Over the full 12-month period, 53% of all Britain’s electricity was produced from low carbon sources, which includes both renewable and nuclear generation, up from 50% in 2017.  The increase in low carbon shoved fossil fuel generation down to just 47% of the country’s overall mix.

The findings come from Electric Insights, a quarterly report commissioned by Drax and written by researchers from Imperial College London.

The report found electricity’s average carbon intensity fell 8% to 217 grams of carbon dioxide per kilowatt-hour of electricity generated (g/kWh), and while this continues an ongoing decline that keeps the country on track to meet the Committee on Climate Change’s target of 100 g/kWh by 2030, it was, however, the slowest rate of decline since 2013.

It also highlights that while Britain can continue to decarbonise in 2019, the challenges of the years ahead will make it tougher to continue to break the records it has over the past few years.

The highs and lows of 2018

Last year, every type of renewable record that could be broken, was broken. Wind, solar and biomass all set new 10-year highs for respective annual, monthly and daily generation, as well as records for instantaneous output (generation over a half-hour period) and share of the electricity mix. The result was a new instantaneous generation high of 21 gigawatts (GW) for renewables, 58% of total output.

Wind had a particularly good year of renewable record-setting. It broke the 15 GW barrier for instantaneous output for the first time and accounted for 48% of total generation during a half hour period at 5am on 18 December.

Overall low carbon generation, which takes into account renewables and nuclear (both that generated in Britain and imported from French reactors), had an equally record-breaking year with an average of almost 18 GW across the full year and a new record for instantaneous output of 30 GW at 1pm on 14 June – nearly 90% of total generation over the half hour period.

While low carbon and individual renewable electricity sources hit record highs, there were also some milestone lows. Coal accounted for an average of just 5% of electricity output over the year, hitting a record low in June, when it made up just 1% of that month’s total generation. Fossil fuel output overall had a similarly significant decline, hitting a decade-low of 15 GW on average for 2018 – 44% of total generation over the year.

One fossil fuel that bucked the trend, however, was gas, which hit an all-time output of 27 GW for instantaneous generation on the night of 26 January. There was low wind on that day last year, plus much of the nuclear fleet was out of action for reactor maintenance. In one case, with seaweed clogging a cooling system.

This was all aided by an ongoing decline in overall demand as ever smarter and more efficient devices helped the country reach the decade’s lowest annual average demand of 33.5 GW. More impressive when considering how much the country’s electricity system has changed over the last decade, however, is the record low demand net of wind and solar. Only 9.9 GW was needed from other energy technologies at 4am on 14 June.

How the generation mix has changed

The most remarkable change in Britain’s electricity mix has been how far out of favour coal has fallen. From its position as the primary source from 2012 to 2014, in the space of four years it has crashed down to sixth in the mix with nuclear, wind, imports, biomass and gas all playing bigger roles in the system.

 

This sudden decline in 2015 was the result of the carbon price nearly doubling from £9.54 to £18.08 per tonne of carbon dioxide (CO2) in April, making profitable coal power stations loss-making overnight. With coal continuing to crash out of the mix, biomass has become the most-used solid fuel in Britain’s electricity system.

Interconnectors are also playing a more significant part in Britain’s electricity mix since their introduction to the capacity market in 2015. Thanks to increased interconnection to Europe, Britain is now a net importer of electricity, with 22 TWh brought in from Europe in 2018 – nine times more than it exported.

While more of Britain’s electricity comes from underwater power lines, less of it is being generated by water itself. Hydro’s decline from the fifth largest source of electricity to the eighth is the most noticeable shift outside coal’s slide. New large-scale hydro installations are expensive and a secondary focus for the government compared with cheaper renewables.

Hydro’s role in the electricity mix is also affected by drier, hotter summers, which means lower water levels. For solar, by contrast, the warmer weather will see it play a bigger role and it’s expected to overtake coal in either 2019 or 2020.

What is unlikely to change in the near-future, however, is the position at the top. In 2018 gas generated 115 TWh – more than nuclear and wind combined. But this is just one constant in a future of multiple moving and uncertain parts.

2019: a year of unpredictability

Britain is on course to leave the EU on 29 March. The effects this will have on the electricity system are still unknown, but one influential factor could be Britain’s exit from the Emissions Trading Scheme (ETS), the EU-wide market which sets prices of carbon emitted by generators. This may mean that rather than paying a carbon price on top of the ETS, as is currently the case, Britain’s generators will only have to pay the new, fixed carbon tax of £16 per tonne the UK government says will come into play in April, topped up by the carbon price support (CPS) of £18/tonne.

Lower prices for carbon relative to the fluctuating ETS + CPS, could make coal suddenly economically viable again. The black stuff could potentially become cheaper than other power sources. This about-turn could cause the carbon intensity of electricity generation to bounce up again in one or more years between 2019 and 2025, the date all coal power units will have been decommissioned.

The knock-on effect of lower carbon prices, combined with fluctuations in the Pound against the Euro, could see a reverse from imports to exports as Britain pumps its cheap, potentially coal-generated, electricity over to its European neighbours. That’s if the interconnectors can continue to function as efficiently as they do at present, which some parties believe won’t be the case if human traders have to replace the automatic trading systems currently in place.

Sizewell B Nuclear Power Station

A reversal of importing to exporting could also reduce the amount of nuclear electricity coming into the country from France. Future nuclear generation in Britain also looks in doubt with Toshiba and Hitachi’s decisions to shelve their respective plans for new nuclear reactors, which could leave a 9 GW hole in the low-carbon base capacity that nuclear normally provides.

Renewables have the potential to fill the gap and become an even bigger part of the electricity system, but this will require a push for new installations. 2018 saw a 60% drop in new wind and solar installations and less than 2 GW of new renewable capacity came onto the system, making it the slowest year for renewable growth since 2010.

Britain’s electricity has seen significant change over the last decade and 2018 once again saw the country take significant strides towards a low carbon future, but challenges lie ahead. Records might be harder to break, but it is important the momentum continues to move towards renewable, sustainable electricity.

Explore the quarter’s data in detail by visiting ElectricInsights.co.ukRead the full report.

Commissioned by Drax, Electric Insights is produced, independently, by a team of academics from Imperial College London, led by Dr Iain Staffell and facilitated by the College’s consultancy company – Imperial Consultants.