Next stop, hydrogen-powered trains.

The train’s hydrogen power system produces sufficient power to take the train 50 to 75 miles. The train, called Hydroflex, is the UK’s first to be powered by hydrogen. It was being shown off to the public in June 2019 for the first time on the tracks at the Quinton Rail Technology Centre, a test facility at Long Marston, near Stratford-upon-Avon, in England.

Engineers who developed the new train, from the University of Birmingham and British rail company Porterbrook, wanted passengers to sit alongside the train’s hydrogen fuel cells. The sooner they would become familiar with the technology, the sooner they would feel safe, they reasoned.

Some apprehension around hydrogen as a fuel source is perhaps understandable considering the unfortunate history of hydrogen-filled dirigibles, namely airships such as the ill-fated British R101 and the German Hindenburg. But hydrogen-powered trains have been emerging as a viable – and much safer – means of transport. How close are we to fleets of trains that release only water as a waste product?

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The way hydrogen powers a train like the Hydroflex is quite simple. The fuel cell is made up of an anode, a cathode and an electrolyte membrane. The stored hydrogen passes through the anode, where it is split into electrons and protons. The electrons are then forced through a circuit that generates an electric charge that can be stored in lithium batteries or sent directly to the train’s electric motor. The leftover part of the hydrogen molecule reacts with oxygen at the cathode and becomes the waste product – water.

The Hydroflex’s hydrogen tanks, fuel cell and batteries currently sit inside a passenger car, but the ultimate plan is to store them underneath the train in order to fit in more passengers. Hydrogen is of course extremely flammable, but on the Hydroflex it is stored in four secured high-pressure tanks, one of a range of measures to ensure passengers’ safety.

Hydrogen-powered trains like Hydroflex are emissions free - provided their hydrogen comes from a renewable source (Credit: University of Birmingham)

In the midst of the climate crisis, the demand for decarbonisation across transport industries has grown and the Hydroflex is just one product of that. In 2016, Germany unveiled the Coradia iLint, the world’s first hydrogen-powered train, which can run for 600 miles on a single tank of fuel – on par with the distances that traditional trains achieve on a tank of diesel. Engineers in the US are also working on bringing a version of a “hydrail” to the states. However, since rail is already among the lowest greenhouse gas emitters in transportation, it remains to be seen whether the value of a massive overhaul of rail systems will be worth it.

The UK already has 42% of its route miles electrified, according to the Institution of Mechanical Engineers, meaning those trains are ready to become zero-carbon, if they use a renewable source of power. A single line running to London from Hampshire is currently the only one in the world to run solely on solar power. However, the remaining 58% of UK track is not yet electrified, so diesel trains are still needed to keep those areas connected by rail.

Engineers working on the Hydroflex say that hydrogen-powered trains could be the answer to decarbonising the UK’s rail system without incurring the high cost of electrifying its track. According to an assessment of 20 lines in Britain and mainland Europe, electrifying a single kilometer of track can cost £750,000 to £1m ($965,000 to $1.3m). Hydrogen-powered trains are less expensive, because they don’t require massive track overhauls and they can be created by retrofitting existing diesel trains. This is especially beneficial in rural areas where there are more miles to cover, but fewer passengers to justify the expense.

The German Coradia iLint was the world's first hydrogen-powered locomotive (Credit: Getty Images)

But hydrogen trains come with their own challenges.

“We store about 20kg of hydrogen, and that is enough to run the fuel cell for three hours,” says Stuart Hillmansen, professor at Birmingham University and leader of the Hydroflex project. As such, longer-distance journeys wouldn’t yet be feasible. Engineers at the University of Birmingham’s Centre for Railway Research and Education, Porterbrook’s partner on the Hydroflex, are working on ways to extend these limits.

With our current hydrogen storage technologies, hydrogen takes up significantly more space than equivalent fossil fuels do – Raphael Isaac

And while hydrogen fuel cells can be as energy-efficient as diesel fuel, storing the gas can be a problem. “While hydrogen has a lot of energy per mass, because it is super light, it also takes up a lot of volume,” says Raphael Isaac, a researcher on fuel alternatives in rail at Michigan State University's Center for Railway Research and Education. “With our current hydrogen storage technologies, hydrogen takes up significantly more space than [equivalent] fossil fuels do.” Even though hydrogen is typically compressed, it’s still not as efficient per unit volume as fossil fuels.

It’s also a space issue on trains. The fuel tanks on the Hydroflex, for example, have to be small enough to fit in an ordinary car that can pass through Victorian-era railway tunnels. These space constraints are one reason that Porterbrook chose to retrofit older train models with the hydrogen fuel power system, rather than construct entirely new vehicles like the Alstom did in Germany – the existing trains were already made to measure for the tunnels they had to pass through.

Hydrogen can be produced using other methods and from renewable energy sources, e.g. electricity from solar photovoltaics and electrolysis of water – Margaret S. Wooldridge

Even though the only direct waste product of hydrogen fuel is water, obtaining this form of power is not necessarily squeaky clean. “The challenge is, at the moment hydrogen is made as a byproduct of chemical processes,” says Helen Simpson, innovation and projects director at Porterbrook. The cheapest and most common method at present uses natural gas and high-temperature steam to produce hydrogen. Hydroflex runs on hydrogen produced from a combination of hydrogen produced using natural gas but its supplier, BOC, says it is looking into renewable options.

In order for hydrogen power to be truly sustainable, other methods of producing it that don’t rely on fossil fuels would need to become mainstream. “Hydrogen can be produced using other methods and from renewable energy sources, e.g. electricity from solar photovoltaics and electrolysis of water,” says Margaret S. Wooldridge, an aerospace engineer at the University of Michigan.

Electrolysis creates hydrogen by separating oxygen from water using an electric current. That current can be created using energy from renewable energy sources, but it has yet to be done outside of small test demonstrations. In order to be a truly green form of travel, the hydrogen would need to be created and stored using renewable energy sources, like off-shore wind farms and solar grids, rather than fossil fuels.

Another lingering environmental issue with hydrogen-powered trains is their use of lithium batteries. Currently, lithium processing takes a major toll on the surrounding environment. Mining one tonne of lithium requires 500,000 gallons of water, for example, and lithium mining has been linked to several measures of environmental degradation. Researchers hope that in the future it may be feasible to extract lithium from seawater instead using solar power, but the idea remains experimental.

Hydrogen trains have potential to be particularly useful in areas with large distances to cover and lower passenger demand (Credit: Getty Images)

On the flipside, one major benefit of trains like the Hydroflex is their potential as a bi-mode train, meaning they can run on the electrified or conventional lines alike. So even though there is certainly an expense to building new hydrogen-powered trains (one of the Alstrom hydrogen trains costs approximately £5.19m), or retrofitting older ones, they are a flexible alternative while the majority of lines – especially rural ones – are yet to be converted to carry electric-trains.

“This is really the space where hydrogen fuel comes in as a real cost-effective and valuable alternative and delivers a low-carbon railway,” says Simpson. “Where we’ve got all these long routes that don’t have as much passenger demand, the cost-benefit of electrifying the lines isn’t there.”

There are benefits to passengers too. Hydrogen-powered trains, like electric trains, are also incredibly quiet compared to their diesel counterparts. And unlike electric trains, they are more resilient to network-wide disruption. “The shared electric infrastructure means that if there is damage to the infrastructure, the operations of many trains on a line will be impacted,” says Isaac. A hydrogen powered train could switch over to its fuel cells if the electricity lines went down, for example.

There is a huge challenge in terms of developing the infrastructure to supply the hydrogen to the railway – Stuart Hillmansen

In countries where passenger trains are less popular, like the US, the ability to convert freight trains to hydrogen power will be key to making the case for mass producing them. A recent report sponsored by the US Energy Department and Federal Rail Administration notes that while powering freight trains with hydrogen is more technically challenging, it would ultimately have “the highest societal value”. Freight is, however, heavier than passengers, so it would require more hydrogen, or more efficiently compressed hydrogen, to carry the same load the same distance that diesel-fueled freight trains currently manage.

The engineers at Birmingham are currently working on more efficient ways to compress hydrogen, one of several hurdles Hydroflex still has to navigate. “There is a huge challenge in terms of developing the infrastructure to supply the hydrogen to the railway,” says Hillmansen. “This technology exists, but there will need to be an uplift in the scale of these operations.”

But the engineers emphasise that Hydroflex is not just a demonstration of hydrogen-power technology – it is set to become a viable commercial train, with mainline testing expected to begin in March or April this year. There a long list of approvals the train needs to pass in order to be considered safe for commercial use, but those involved in the project estimate Hydroflex will be fully up and running as soon as two years from now.

In the light of the UK’s ambition of doing away with diesel-only trains altogether by 2040, the Hydroflex’s forthcoming springtime test on the tracks makes it perhaps one of the most keenly anticipated arrivals in the country.

Six energy tech firms win business growth support from Energy Systems Catapult

Equiwatt's app for incentivising the shift of energy consumption from peak times. Image: Equiwatt.

Equiwatt's app for incentivising the shift of energy consumption from peak times. Image: Equiwatt.

Six energy technology companies have been selected for a business growth programme run by the Energy Systems Catapult.

In this round, the third of the ‘innovator challenge’, the Catapult was looking for digital and data-focused SMEs working on solutions to help create a smarter, more flexible energy system.

The companies are to receive tailored business and technical support both from the Catapult’s in-house technical services, tools and expertise and from its network of around 40 businesses, with the intention of speeding up the process of either getting their products to market or scaling up.

Digital Engineering, one of the companies to win the backing of the Innovator Support Platform, has developed technology to monitor the impact of weather on overhead lines, optimising investment by providing a clearer understanding of asset deterioration over time.

Rob Sunderland, managing director of Digital Engineering, pointed to “amazing innovations” the company has created with companies such as National Grid and SP Energy Networks previously.

“With the Catapult’s support we should be able to deliver these solutions to power transmission companies around the world. That’s a really exciting prospect and I can’t wait to get started,” Sunderland added.

Equiwatt, another of the companies selected, incentivises consumers to save energy at peak times through an app-based rewards scheme. Its digital platform monitors periods of peak demand, tracks home energy use via smart meters and helps households automatically turn off appliances during peak time events.

Households then earn points based on the amount of energy moved off peak, which can be exchanged for vouchers or smart products.

It bears a similarity to other energy management apps such as GenGame and Chameleon, aimed at reducing or shifting domestic energy consumption.

OrxaGrid, a software company that has developed a platform that can process grid data to produce insights into how to reduce energy losses and increase overall efficiency, has also been selected.

It has also developed a range of devices for building a smarter grid, including sensors that monitor the performance of transformers and overhead lines to continuously measure and detect outages and disturbances.

Smart Power Networks, another company selected, has created an “all-in-a-box solution” for creating a flexible and secure electricity grid, monitoring the system and enabling real-time control and protection of energy assets.

Anastasios Oulis Rousis, managing director and founder of Smart Power Networks, said working with the Catapult will help refine and improve the company’s offerings across “various dimensions”.

Another winner was Energeo, which uses geospatial big data such as satellite imagery to identify the most ideal locations for low carbon technology.

The last company, Scene Connect, has developed a digital platform allowing suppliers to sell heat and power as a service by calculating bespoke tariffs.

Its technology can also be used for trading energy with other local homes and businesses.

Paul Jordan, business lead for innovator support and international at the Energy Systems Catapult, said the Catapult was “blown away” by the variety of businesses that applied to the Innovator Challenge.

“Whittling it down to just six was not easy, but we are very pleased with the third cohort of SMEs to join our Innovator Support Platform,” Jordan said, adding that the Catapult knows the "complex challenges" the sector poses and will work hard to help the businesses "maximise their impact through a blend of support services tailored to their needs".

UK Government hints at RHI extension

28 February 2020, source edie newsroom

Energy and Clean Growth minister Kwasi Kwarteng has claimed the Government is "absolutely committed" to exploring new support mechanisms for low-carbon heat in the UK once the Renewable Heat Incentive (RHI) expires in March 2021.

Kwarteng also announced that the Government would consult on issuing tougher EPC standards for private-owner landlords

Kwarteng also announced that the Government would consult on issuing tougher EPC standards for private-owner landlords

During a House of Commons debate on energy efficiency measures and net-zero buildings, Business, Energy and Clean Growth Minister Kwarteng fielded questions from MPs on the UK Government’s approach to decarbonising the UK’s commercial and domestic building stock, which accounts for approximately 40% of the UK's carbon emissions.

During the session, Kwarteng claimed that the UK Government is “absolutely committed to seeing how we can support the RHI beyond the date on which it expires”.

The RHI is due to close in March 2021, with the Government yet to outline how it will promote low-carbon heating beyond that point. From April 2021, households signed up to the scheme will continue to receive payments until the end of a seven-year agreement.

The RHI was put in place by the Government as a means to convert 12% of UK homes to renewable heat by the end of 2020. Current trajectories suggest it will reach 8-10%.

While Government figures claim that the RHI has delivered payments of £2,800 annually to those signed up, all while saving 5.2 tonnes of carbon annually, it has been criticised for failing to provide financial value. In 2018, the Public Accounts Committee (PAC) concluded that the RHI had failed to provide value for money for the £23bn it was set to cost taxpayers.

The Committee on Climate Change has suggested that the UK would require 15 million homes to be fitted with heat pumps or hybrid heat pumps by 2035.

Last year, the Science and Technology Committee’s ‘Clean Growth: Technologies for meeting the UK’s emissions reduction targets’ report outlined a lack of replacements for the RHI as one of the 10 major shortfalls of Government efforts to date to reach net-zero emissions by 2050.

The report calls for the urgent development a clearer strategy for decarbonising heat that includes large-scale trials of different heating technologies, such as heat pumps and hydrogen gas heating, operating in homes and cities to build the evidence base required for long-term decisions.

Green homes

That report also called for an incentive scheme for energy efficiency home improvements, a topic that Kwarteng was also questioned on during the session.

Kwarteng noted that the proposed Future Homes Standard would act as a catalyst for reducing household carbon emissions and would perform better than the zero-carbon scheme that was scrapped in 2015.

“The Government feel that the future homes initiative is much more realistic and better in terms of reducing carbon emissions in houses than the initial zero-carbon scheme,” Kwarteng said. “That scheme allowed for offsetting, whereas the future homes standard will concentrate on lowering absolutely levels of emissions. I think that is a much better way of approaching the problem.”

The Future Homes Standard is due to come into effect in the latter half of 2020, covering England only. In its current form, it includes a headline goal to reduce the carbon intensity of new builds by 75% by 2025, which ministers plan to deliver through fresh mandates for housebuilders on triple glazing, low-carbon heating systems, onsite renewable generation and energy-efficient building fabrics. The 75% target is down from an initial proposal of 80%.

Kwarteng highlighted the £5m in green finance pledge to help homeowners make their buildings more energy efficient. The minister also announced that the Government would consult on issuing tougher standards for private-owner landlords in regards to EPC ratings for 2030.

“We aspire for private landlords not to get properties to EPC band E but to make investments to improve their properties to band B or C by 2030. That is a significant improvement and a step in the right direction,” he added.

Commenting on the announcements, Steve Collins, director of premier EcoEnergy said: “We welcome the measures being taken by government to improve home energy efficiency and specifically the commitment to supporting the RHI beyond its current term.

“However, we would like clarity as to whether RHI will remain in its current form. If the government is to achieve its climate targets, it is imperative to entice homeowners and businesses who live in older buildings which make up a substantial proportion of current emissions.”

Matt Mace

Mixed recycling ‘doubles contamination’

27 FEBRUARY 2020 by James Langley

Commingled recycling collections can lead to twice as much contamination when compared with separate streams, according to paper recycling specialists DS Smith.

The company said today (27 February) that in the last year it measured enough plastic contamination in paper and cardboard materials at its Kemsley Paper Mill to fill up to 4.8 million black bin bags.

DS Smith’s Kemsley Paper Mill is in Kent

The London-based corrugated-packaging company has now called on local authorities to adopt collections where materials are separated.

Jochen Behr, head of recycling for DS Smith, said: “It is important that the right materials end up at the right recycling facility.

“We have argued for many years on the importance of quality material for recycling, and the importance of separate collections to ensure that paper and cardboard can be easily recycled, and therefore underpinning their qualities as important contributors to the circular economy.”

The company says its research showed paper and card were more likely to be contaminated by plastics when it was collected as mixed recycling.

To ensure as much paper is recovered as possible, DS Smith says its own collection infrastructure implements an eight-step process to ensure plastic-riddled bales are separated and sorted for further processing before they arrive at the Kemsley Paper Mill in Kent.


As end markets tighten and material quality becomes more important, contamination is becoming an ever more significant issue.

Spot checks by Redditch borough council in Worcestershire found a “shockingly high” rate of 23% contamination in the material it collected from kerbside recycling bins (see story).

And, after having 156 tonnes of paper and card rejected for recycling because it was mixed up with other waste including nappies and food waste, Pendle borough council is placing stickers on receptacles if they contain the wrong items (see story). Residents are asked to remove the wrong items from the blue bins before the waste is collected.

In the past year DS Smith measured enough plastic contamination in paper and cardboard materials to fill 4.8 million black bin bags (Picture:Shutterstock)

In April 2019 DS Smith released a report titled Tipping Point which suggested the UK would not reach its target 65% recycling rate until 2048.

The report calls for policy makers to introduce mandatory separate collections of card and paper to improve the quality of material collected for recycling.


DS Smith says it has introduced quality measurement tools including Near Infrared technology to assess the quality of material arriving from household and commercial collections.

Mr Behr said: “Introducing state-of-the-art monitoring equipment at our mill has allowed us to be forensic about the quality of material that we process in the UK.”

A handful of green hydrogen options share £28 million in BEIS funding to kick-start bulk production

Five projects aiming to produce low-carbon hydrogen at bulk have together been awarded over £28 million in funding by the Department for Business, Energy and Industrial Strategy.

  • Dolphyn, awarded £3.12 million, and led by Environmental Resources Management, concerns production of hydrogen at scale from offshore floating wind farms  in deep water. The ‘green’ hydrogen can be piped to shore. The concept consists of a large-scale floating wind turbine (nominally 10MW) with an integrated water treatment unit and electrolysers for localised hydrogen production. This funding will enable the detailed design of a 2MW prototype system.
  • HyNet was awarded £7.48 million. It is led by Progressive Energy, who with Essar, Johnson Matthey, and SNC-Lavalin will deliver a 100,000 Nm3 per hour clean hydrogen production facility for deployment as part of the HyNet Cluster. Production is based on Johnson Matthey’s hydrogen technology which has methane as a feedstock but uses oxygen in the reforming (hydrogen production) process, increasing its efficiency, and includes carbon capture and storage. BEIS says the technology could lower the cost of low carbon hydrogen by 20% and it has become the basis for analysis by it and the Committee on Climate Change’s (CCC) analysis. It previously won government funding in November 2018 and the new tranche will cover engineering design to deliver a ‘shovel ready’ project. HyNet has also received development funding to help industry develop low-carbon fuel alternatives, see here
  • Acorn Hydrogen Project led by Pale Blue Dot Energy (PBDE) has won £2.7 million, which will also cover development of Johnson Matthey’s technology. It will cover engineering studies for an advanced reformation process, including assessment for hydrogen production from North Sea Gas, capturing and sequestering the associated CO2 emissions.
  • Gigastack was awarded £7.5 million. Led by ITM Power Trading  it will demonstrate bulk, zero-carbon electrolytic hydrogen using  ITM Power’s polymer electrolyte membrane (PEM) electrolysers. The funding will enable ITM Power to work towards developing a system that uses electricity from Orsted’s Hornsea Two offshore wind farm to generate renewable hydrogen for the Phillips 66 Humber Refinery.
  • Cranfield University won £7.44 million to develop a low carbon bulk hydrogen supply through pilot scale demonstration of the sorption enhanced steam reforming process, based on a novel technology invented by the Gas Technology Institute (GTI).

Energy partnership gears up to bring low carbon heating to Scottish homes

Shawfair Town Centre CGI, Midlothian
Press release Feb 11, 2020 2:00 G2T

Vattenfall revealed as preferred Midlothian Energy Partner

The partnership’s first project will be the installation of an innovative district heating network which will provide heat to new homes at the Shawfair development with a carbon saving of 75% when compared with conventional gas boiler heating.

The low temperature system, expected to be operational in 2021, will bring fourth generation heat network technology to Scotland - building on Vattenfall’s experience in constructing and operating some of Europe’s fastest growing heat networks in cities such as Amsterdam.

Tuomo Hatakka, Senior Vice President Business Area Heat, Vattenfall, said: “We’re delighted to have been selected by Midlothian Council for this long-term energy partnership that puts low carbon, fossil free living front and centre of its ambition. This partnership will serve as a platform for further growth in low-carbon energy solutions in Scotland and the United Kingdom. Any organisation or company serious about reaching net zero has low carbon heating at the top of its to do list, and this energy partnership is no different.”

Mike Reynolds, Managing Director of Vattenfall Heat UK, adds: “Midlothian is blessed with an abundance of local, low carbon heat potential which means that we can begin the partnership’s work with the installation of a state-of-the-art network that will deliver affordable, low carbon heating to local homes at the Shawfair development. The project provides a model to the kind of progress that can be achieved right now through the deployment of innovative, low carbon district heating networks in the tough challenge of decarbonising the UK’s heating supply.”

The Vattenfall Heat Team in the UK

The Vattenfall Heat UK Team is based in London and Edinburgh and is working on projects across the UK.

Midlothian Council’s Cabinet Member for Economic Development, Councillor Russell Imrie said: "We’re very excited to be working with Vattenfall to set up an energy services company for innovative new projects benefitting local residents and businesses in the area and setting us well on our way to a carbon neutral future. Working closely on our first project with Shawfair LLP, the local developer, and FCC Environment, our existing Zero Waste Contractor, we look forward to delivering another major pathfinding project for Scotland. "

Low temperature heat networks bring with them many benefits - including lower costs, maintenance, and an ability to adapt to take heat from many sources of waste heat such as waste water works and data centres.

The heat feeding the network will be sourced from waste heat produced by FCC’s Millerhill waste and recycling plant and will be fed through a network of pipes to local homes. The partnership will also begin actively exploring the potential of thermal storage and other local heat sources to enable the network to grow and expand across Midlothian and beyond.

This first £20m project will benefit from financial support of up to £7.3m from the Scottish Government’s Low Carbon Infrastructure Transformation Project, which is part funded by the European Regional Development Fund. The scheme will also benefit from a close working relationship on the project with Scottish Futures Trust.


Midlothian photo credit: Shawfair LLP.

Scotland Budget outlines multi-million-pound pots for net-zero heat and agriculture

7 February 2020, source edie newsroom by: Sarah George

The Scottish Government has this week published its draft 2020-21 Budget, which sets aside millions of pounds for ocean conservation and decarbonising sectors such as heat and agriculture.

The draft Budget was published on Thursday (6 February), building on Scotland's 2019 Climate Change policy package

The draft Budget was published on Thursday (6 February), building on Scotland's 2019 Climate Change policy package

On low-carbon heat, the Budget includes a £50m pot for local authorities looking to invest in heat networks and confirms that tax rate relief on district heating projects will continue until at least 2031. The Committee on Climate Change (CCC) claims that at least 18% of the UK’s overall heating demands will need to be met by such projects by 2050, if the net-zero goal is to be met.

A ‘Heat Transition Deal’ for private sector firms in the heating and heavy industry sectors is also promised.

Elsewhere, the Budget outlines a £65.5m package for marine conservation and restoration, up from £52.1m in 2018-19. This pot will be split across projects working to prevent overfishing; champion animal and human rights in the seafood supply chain; conserve and restore habitats and biodiversity; and scale-up marine renewables.

On the latter, a 2018 report from the Offshore Renewable Energy Catapult said that the tidal stream industry could generate a net cumulative benefit to the UK of £1.4 billion, supporting nearly 4,000 jobs by 2030. Given that the UK’s central Government has repeatedly failed to support tidal projects in England and Wales, it is widely expected that the majority of sector growth will happen in Scotland.

The Scottish Budget’s other green economy headlines include a £100.5m package to support the water sector – the same amount the Government has allocated for the past three Budgets – and £16.5m to reform land-use, down from £17.1m at the last Budget.

Land use has risen up the green policy agenda in the wake of the IPCC’s special report into the issue last year. According to the Panel, land use currently accounts for almost one-quarter (23%) of human-caused greenhouse gas (GHG) emissions, with agriculture accounting for the majority of these emissions.

The CCC last month published its UK-specific recommendations for changing land-use in line with net-zero, outlining the need for forestry and peatland restoration; food waste reductions across the value chain; bioenergy crops and a shift towards consuming 20% less red meat and dairy per capita.

With the context of Scotland’s natural landscape and food sector in mind, the large chunks of the Budget pot are expected to be allocated to forestry, peatlands and decarbonising the livestock sector.

Green economy reaction

The Scottish Government said in a statement that the environmental provisions in the Budget will “support and facilitate the pivot towards a net-zero trajectory which requires all portfolios to respond to the global climate emergency”.

“While there are significant challenges in this space, there are also exciting opportunities to diversify our economy and to lead the world in transitioning to net-zero,” the statement reads. “Our priority for the year ahead is to respond to the global climate emergency and biodiversity loss.“

WWF Scotland’s head of policy Gina Hanrahan said the Budget “clearly steps up funding” around the “twin” biodiversity and climate crises.

“It's welcome to see additional investment in heat networks, sustainable transport, as well as support for farmers to reduce emissions, and significant new investment in peatlands – our natural ally in the fight against climate change,” Hanrahan said.

But she felt the Government had missed an opportunity for greater investment in energy efficiency. The CCC’s annual report to the Scottish Parliament warned that the nation would miss its net-zero target without policy measures to ensure that “all buildings are as energy-efficient as can be practically achieved“ in the 2020s.

“While some additional funding for energy efficiency is a move in the right direction, this falls short of the transformational funding needed to tackle our leaky homes, cut fuel poverty and put Scotland at the forefront of the transition to high performing, green homes,” Hanrahan added. “We want to see this prioritised for additional funding.”

Elsewhere, Scottish Renewables has welcomed the Budget’s measures for low-carbon heat and marine renewables. It called the package of measures on decarbonizing heat “vital to plug funding gaps”, saying they would “give industry the certainty to invest and deliver on the enormous economic opportunity presented by the transition to low-carbon heat”.

The Scottish Green Party, meanwhile, was not so forgiving. It has slammed the Budget as “timid, not transformative”.

“It lacks the necessary action on the climate emergency and is an abdication of responsibility,” Green MSP Patrick Harvie said. “The Finance Minister must change tack if she wishes to secure our support for her budget.”

The Greens would specifically like to see local councils given greater powers to set – and funding to deliver against – more stringent carbon and biodiversity targets than Scotland’s central Government. It is also calling for greater financial support to decarbonise transport, the nation’s most-emitting sector. Green proposals on transport include a concessionary bus fare scheme for young people, in a bid to discourage individual car ownership in urban areas and support lower-carbon journeys through rural areas.

Could Great Britain go off grid?

Nearly a century after it was first built, is the national grid on the verge of breaking up?


Great Britain goes on grid

Bonnyfield, near Falkirk in Scotland, isn’t an exciting place. It’s home to a nature reserve, the remnants of a Roman wall, and a small neighbourhood bowls club. It’s sparse and suburban.

But it was here, in a wind-beaten field dotted with trees on the outskirts of town, that the largest infrastructure project in British history began.

On 14 July 1928 the first pylon of what would become the national grid was erected. It would be a decade before the grid as we know it today came into existence, but on that Saturday morning a small group of men gathered to hoist a steel tower upright and signal the arrival of the modern age.

Nearly a century later, the electricity network that grew from that first pylon remains, but it’s a vastly different thing. It’s bigger and more complex – its physical footprint covers almost 90,000 pylons, 4,500 miles of overhead cables and 342 substations operated by the National Grid Electricity Transmission company, as well as many more local distribution networks consisting of wires and transformers.

It’s a network of old and new technology spanning almost the whole country that helped propel a population into an age of rapid scientific and economic expansion. But today there’s one question being asked of it: is it fit for purpose?

In a world of small-scale, intermittent-renewable, decentralised, distributed and battery-powered microgrids, is an almost antique network what the country needs?

To answer that question, we have to start with a broader one.

Why do we even have a grid at all?

90,000 pylons
4,500 miles of overhead cables
342 substations

Great Britain's national grid

The history of the grid

Electricity came to Great Britain’s shores as a novelty. When it arrived in the 1880s its practical uses were limited – lighting was just about the only demonstrable function. As a result, electricity’s early adopters were either the rich – who used it to bring uniqueness to their homes – or hotels and seaside attractions such as those in Blackpool, which used electricity as a way to bring in curious punters.

The early electrification of Great Britain wasn’t a government effort to light up the country, it was a way to show off.

By the dawn of the 20th century electricity had begun to grow as a means for powering industrial machines, but its use was niche and viewed with scepticism. Great Britain’s deep reserves of coal had made steam the driving force behind its industrial revolution, and in domestic life people were familiar with coal stoves and gas lamps. Electricity was a complicated, unnecessary alternative with few supporters.

But by the 1910s it became apparent Great Britain was lagging far behind the economic and industrial development of the US, Scandinavia and Germany – three regions where electricity had grown to be more abundant and less expensive. It was clear to anyone comparing those countries that electricity use on a larger, integrated scale could unlock greater development and growth.

Britain took notice. But the question was, where to start? And more importantly who had the nerve to take it on?

The man who would be the grid king


Charles Merz had ambition born into him. The eldest son of a German-British chemist and industrialist father, he took up his first job aged 15 as an apprentice at the Newcastle-upon-Tyne Electric Supply Company, which was founded by his father in 1889.

By age 24 Merz was the Secretary and Chief Engineer of the Cork Electric Tramways and Lighting Company in Ireland, where he met fellow electrical engineer William McLellan. Together they set up the consulting firm Merz & McLellan with a vision to transform the nascent technology of electrification.

The pair returned to Tyneside in 1901 to open the Neptune Bank Power Station, the first power station in Great Britain built exclusively to supply electricity to industry rather than just to power domestic lighting. By 1914 Merz & McLellan had taken ownership of multiple power stations in the surrounding area, but rather than sitting back and reaping the economic rewards of this network, Merz saw something else.

In the concentrated geography of British industry, he recognised the opportunity for a public supply of electricity spread across sites. One that would be cheaper and more reliable than the private generators supplying individual factories – that would connect multiple power stations through high-voltage transmission lines, and would pool generation so it could be shared across multiple factories and facilities.

He set about building it, adding connections that linked his power stations to share their generation across the Newcastle-upon-Tyne region and, in the process, formed the country’s first ever local grid.

He used the project as a working demonstration to influence Parliament to take the task of interconnection much further. He was met with little enthusiasm, but then World War One struck and everything changed.

Industrial production would be essential to the war effort. The 1915 Shell Crisis – a severe shortage of artillery shells on the western front – highlighted that British industry was not up to the pace needed. Furthermore, mass conscription  caused labour shortages in the coal industry, threatening the main source of Great Britain’s electricity and industrial power.

It was through direct government intervention, such as rationing of domestic coal and drafting women into factories and mines, that Great Britain’s industry could get up to speed.

Merz seized the narrative of British survival to advocate for regional grids. He argued that reorganising the electricity system to use the latest energy technology would make the most efficient use of coal reserves and generate the electricity needed to ramp up industrial production and overcome the struggle.

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The early electrification of Great Britain wasn’t a government effort to light up the country, it was a way to show off.

Getting the grid in shape

The feeling that the UK had only just scraped through World War One thanks to the US’ intervention with its industrial might (powered by regional grids) was deeply troubling. It was now apparent to many electrical engineers that radical change was needed. But despite the clear need, progress was slow.

The long-anticipated peace following the war was fraught with tension. Coal miners went on strike against wage cuts in 1919, disrupting the country’s most vital source of electricity and heat, and exposing the vulnerabilities of the fractured electricity system.

That same year a group of electrical engineers gathered to write a report in response to the war calling for greater interconnection. The ‘Williamson Report’ set out to make the country’s electricity systems more efficient and secure, but did so through voluntary involvement and gradual legislation. As a result, progress was slow, ad hoc and marginal – not the radical shift that was needed.

This significant overhaul would come in 1926 with the release of another report – once again with Merz one of the main players. The ‘Weir Report’ laid out the first true vision of a connected grid across the nation and became a point of reference for advocates. Its first step was to establish seven separate, regional networks.

The committee behind the report was chaired by Lord Weir of Eastwood, a Scottish industrialist who had come to prominence during the war as director of aircraft production and then as Secretary of State for Air. He made it clear to Conservative Prime Minister Stanley Baldwin that the plan would not just advocate for a gradual progression of electrification, but call for major reorganisation and financial investment.

Baldwin rallied significant support for the construction of the grid thanks to the Labour Party’s support of greater public electricity supply, which it saw as a step towards eventual nationalisation. But the complexity of the existing network meant the feat of integration would be enormous.

Dr Paul Warde, a professor at Cambridge University sums up the state of the country’s power network at the time. “Before the grid as we know it became established, Britain had 572 local electricity suppliers, and almost as many power stations as that.” The plan to integrate all of them would be the biggest infrastructure project ever undertaken by the government.

Looking over the planned transmission lines crisscrossing a map of the country for the first time, Charles Merz stood back and said what he saw – a ‘gridiron’ impression across Great Britain.

The man to champion the idea of a national grid had also just given it its name.

“Before the grid as we know it became established, Britain had 572 local electricity suppliers, and almost as many power stations as that.”

Dr Paul Warde, Cambridge University

The largest infrastructure project ever undertaken

Legislation was passed in 1926 and planning began immediately. One of the first tasks in 1927 was to found the Central Electricity Board (CEB), which would oversee the construction and operation of the system.

This included everything from finding and procuring the right land, to deciding which power stations were high capacity and efficient enough to be brought onto the system, to overcoming the technical challenges of standardising voltage and frequency. Nearly a century later, this decision to unify voltage and frequency remains one of the fundamentals of the grid as we know it.

The final of the 26,000 original pylons that would become the national grid was erected on the outskirts of the New Forest on 5 September 1933. Just seven years after the project began it was completed – on time and within budget. Its impact on the country was immediate.

Between 1926 and 1933 electricity consumption in Great Britain doubled from 5 million kilowatt hours (KWh) to 10 million KWh, while industrial production grew significantly. Factories and workshops now had a cheap, reliable, public supply of electricity they could use rather than having to depend on their own.

The homes of ordinary people across the country also now gained access to electricity for the first time. It became a political debate in the 1930s when the decision as to whether public housing should have electricity or not was raised.

Primarily Conservative local councillors worried about inflicting the cost of electricity on poorer tenants, while Labour councillors advocated for modernity in anticipation of cost falling in the future. In an era when the vast majority of people rented their housing, the decision would ultimately fall to landlords rather than tenants. In the end electrification won out.

These were huge steps forward, but there was still no nationwide, fully integrated network. The country had interconnected its power stations, but it remained regionally divided into seven individual networks.

Another change was needed, but it wasn’t going to come easily. It needed a maverick plan.

The rebels that turned seven into one

On the evening of 29 October 1937, almost a decade after the construction of the first pylon there was a rebellion brewing. A group of electrical engineers at the CEB had launched a plan behind their employers’ back to run an experiment that would once again transform the country’s electricity system.

The network was divided into seven separate networks, but this group of engineers saw the potential for something else – an integrated system. A truly national grid.

That evening the group of co-conspirators decided to run all seven separate networks as one integrated system. As an unauthorised experiment, there was high potential for disaster – if it didn’t work, the country could falter and each engineer would likely lose their jobs. The group advanced regardless.

There was no disaster, no loss of power and, crucially, it worked. Authorities at the CEB were initially deeply unhappy with the maverick plan, but the potential for a single system was clear and they would soon need to consider it further.

In the harsh winter of 1938, the possibility of shortfalls in the South of England prompted the decision to formally attempt to run the system as one grid and to connect the more plentiful generation of the North with the rest of the country. It was intended as a short-term measure, but this time it stuck. The country’s grid has remained connected and centrally coordinated ever since.

By 1940 electricity consumption had once again doubled to 20 million KWh a year, while through the 1930s Great Britain’s industrial production grew to sit behind only Germany and the Soviet Union’s – which would prove massively important given what the next decade would entail.

Merz, the man who had kicked it all off, however, would not live to see how robust and vital the grid proved throughout the Second World War. In 1940 he died during a German air raid at his home in Kensington at the age of 66.

As the country emerged from the Second World War, the unified, electrified Great Britain he had imagined decades before was just coming into being. More than just transforming industry, it was changing society.

Transformation at home and work 

The grid Merz helped shape was responsible for ramping up the industrial power that would help the UK survive the Second World War, but away from the shipyards and factories, it was changing the lives of ordinary people across the country.

The shift from small locally-placed power stations to larger plants located further from towns and cities massively reduced the level of pollution in urban areas. The benefit was felt in homes, too, where the reduced need for gas canisters and oil wicks cut indoor pollution – though coal would still play a role in heating and cooking in homes until the 1970s.

The immediately obvious lifestyle benefits this brought meant greater electrification – and the construction that came with it – was invited rather than obstructed. Communities of all kinds saw recognisable benefits brought by electrification and were willing to accept transmission lines and cables traversing the landscapes for it.

In the post-war years, the practical applications of electricity in homes and businesses expanded significantly as new appliances came to market – from fridges to electric ovens to hoovers to kettles. Advertising for these appliances was targeted at women, the belief being that having been tasked with labour-intensive domestic jobs for centuries, new electrical appliances suddenly made these much less time consuming.

From houses to factories and neighbourhoods to regions, reliable safe electricity from the grid allowed modern Great Britain to emerge in the second half of the 20th century. The transformation was radical, positive and rapid, but there was a silent problem lurking at the heart of it – the fuel powering it.

When everything changed

Coal had been the backbone of British industry for as long as there had been any British industry – the electricity revolution was no different. Power stations across the country may have been connected to one another, but in the immediate post-war years almost all were running on coal, and as populations grew and electricity demand increased, more and more coal was needed.

At the same time, so did awareness of what that coal was doing to the world around it. Air pollution in urban areas may have improved as power stations had moved beyond city limits following the 1956 Clean Air Act, but their cumulative effect to the world at large could no longer go unnoticed.

As science and computing advanced in the 1950s and 60s, researchers were slowly gathering more evidence that carbon dioxide (CO2) was no longer just another invisible by-product of burning coal, but a world-damaging gas slowly filling the atmosphere.

The world needed to cut carbon emissions, but it still needed power. In fact, it needed more power than ever. So, the industry began looking at other sources of electricity. Part of the solution was found in nuclear, which grew in the 1950s and 60s, before the arrival of natural gas in the 1990s. But elsewhere technologies that ran on sources that would never run out, and that wouldn’t emit the malicious molecule – CO2  – were gaining greater traction and interest.

By the turn of the millennium solar and wind generation weren’t new technologies, but they came under renewed consideration as an option to provide cleaner, renewable power at scale. And as more minds began to tackle this challenge, the costs of these technologies began to fall while their abilities grew, triggering the rise of larger, more plentiful pockets of renewable generation that existed in localised hubs centred on servicing single homes, facilities or regions.

It was an historic moment in recognition of a cleaner energy future, but for Great Britain it also signalled the end of coal – the fuel that for centuries had powered the country. Instead, the future would be focused on renewable and lower-carbon power sources.

The first great leap of the national grid was to unify generation so that no part of the country would ever be without power. There was now a second: how do we make it cleaner?

The pockets of renewable generation dotted across the country that had been quietly developed and cultivated were now something else – they were no longer the fringe, they were the future. But they would need to grow. The focus wasn’t the big connected network, but the smaller sections within it.

And if this was where we were headed, what would that mean for Merz’s great interconnected grid?

As we entered the 21st century in earnest, the grid began to break.


The big break

In the North-West Highlands of Scotland is a peninsula jutting out into the North Atlantic. The community of Scoraig is only accessible by boat or a five-mile hike. It is also completely cut off from the national grid.

The local homes and community school are partly-powered by small-scale wind turbines built by a local physicist and wind-power hobbyist called Hugh. Scoraig has become a haven for people who want to escape the traditional nine-to-five and seek a self-sustained lifestyle. It is exactly what comes to mind when you think of living ‘off-grid’.

But the idea of ‘off-grid’ is no-longer limited just to these types of remote communities. Instead, aided by technological advances and government incentives, it has become a feasible, small-scale way to begin to decarbonise Great Britain’s electricity system, and to bring generation closer to electricity’s point of use.

These off-grid communities bring advantages, but there are also repercussions for the broader network.

Great Britain’s grid was built with big power stations that generate a lot of electricity in mind. Facilities like Drax Power Station – now the biggest in the country – can generate 600-plus megawatts from each of its four biomass units and contribute as much as 8% of the country’s total electricity. The substations and transmission cables that make up the national grid were built to integrate and transmit vast quantities of power from stations of a similar size to plugs across the country.

But when electricity generation is happening at the place of consumption (such as at a local wind turbine or solar panel on an office building) much of that grid infrastructure isn’t needed. What’s more, the cost of maintaining it suddenly disappears, offering lower-cost electricity to end consumers.

What was built to connect a handful of big power generators is instead having to accommodate many smaller ones that don’t need to feed their power into a central, integrated pool.

This shift is called decentralisation – a move away from a network built around a handful of big generators to one made up of multiple, smaller ones.

But as more buildings, communities and businesses develop the ability to go off-grid and decentralise, the relationship between electricity producers and consumers changes. And inevitably so does the business of power.

The result could be a complete transformation of the centralised grid the country’s electricity system is built on. A transformation not of consolidation but of separation. A transformation that is already well underway.

The growth of decentralised generation


The primary catalyst for decentralisation was decarbonisation, but what’s arguably moved it into the mainstream is economics and energy independence.

The falling costs of renewable technologies – in particular solar panels – have made the ability for individuals to generate their own electricity a possibility for anyone able to afford the initial outlay. This has given rise to what’s known as ‘prosumers’ – individuals and businesses who both produce and consume their own electricity.

The benefits of this are obvious. Families and organisations can save money by generating their own renewable power rather than buying it from suppliers. This in turn reduces utility bills, and in many cases allows them to sell the excess power they generate back to the grid to even make money. And it’s not just in the private sector that it’s gaining traction.

Three quarters of local authorities around the country are exploring governing electricity at a local level with decentralised sources, including the country’s capital. The London Mayor’s Office expects 25% of the city’s power, as well as heat, to be generated through decentralised sources by 2025. This would be an impressive achievement for such a large city as well as a signal of intent for where the rest of the country may head.

But it wouldn’t be the first of its kind, globally.

The renewable village, the resilient country

The village of Feldheim lies in a flat, windswept stretch of Germany just south east of Berlin. With just a few hundred residents it’s far from big, but it is unique. In the mid-nineties it began experimenting with renewables, erecting four wind turbines in an effort to begin generating its own power.

Feldheim’s wind turbines eventually grew to 47 in number, and in 2008 these were joined by a biogas plant using local farm waste to create methane for heating, as well as a solar farm. All together these installations were generating so much electricity that 99% of it was being sold by the community back to the local energy market.

But Feldheim was still a part of the local grid. Utility company E.ON – who owned and operated the grid – refused to sell or lease the part of the grid the village sat on to the community. This meant the electricity being used there remained a mix of all the different sources of power on the country’s centralised, integrated grid, rather than coming directly from the local, renewable sources sitting on their doorstep.

So, the community did something drastic – they built their own grid. Using donations from residents, EU subsidies and a partnership with a French energy company it raised enough money to build a parallel grid that would only service the village. In 2010 it was switched on and Feldheim achieved total energy independence. Feldheim was now entirely off-grid, decentralised, and truly carbon neutral.

Just a year later, on the other side of the world, a devastating natural disaster would begin a move to decentralisation on a far bigger scale, one not just focused on decarbonisation, but on security.

In the wake of the 2011 Great East Japan earthquake and subsequent Fukushima nuclear incident, Japan found itself at a crossroads. It recognised its centralised electricity system was susceptible to major disruption from natural disasters, and that its geography made those natural disasters more likely. The country was also on an ambitious plan to reduce its carbon emissions in 2030 by 26% from 2013 levels. There was a need for resilience.

Shioashiya Smart City, a new district in the city of Ashiya near Osaka, began development in 2012 with the aim of building a net-zero carbon emission city on a microgrid using solar and storage facilities. Built in partnership with Panasonic, each of its 400 homes features a 4.6 kW solar generator and a 11.2 kWh storage cell, as well as systems allowing users to share excess power with other buildings in the neighbourhood including three condominium complexes.

The region regularly over-generates allowing the community to sell excess power back to the main grid, but even if connection to this is interrupted in an emergency, Shioashiya can continue to function from stored power and solar generation.

Nearly 600 miles away to the northeast of the country the city of Higashi Matsushima has taken a less-technological, but larger scale, approach. A city of 40,000 people, it was awarded funding as part of Japan’s National Resilience Program to construct a series of microgrids and renewable generation clusters that now produce 25% of the city’s total electricity.

The approach to decentralisation of the small German village and Japan-at-large are very different – not just in geography but in ambition. One is driven by a desire to isolate itself as a carbon-neutral off-grid haven, the other to demonstrate security through separation.

What they share, however, is a progression towards empowering users of electricity rather than just those that produce and manage it. This doesn’t mean a benefit just to individuals, but potentially whole societies.

Changing generation, changing where the money goes 

Emma Bridge is CEO of Community Energy England (CEE), an organisation which acts as a voice for community energy schemes around the country. With several years’ experience in renewable and community energy projects, she recognises the transformational potential of decarbonisation and digitalisation. More importantly she sees the opportunity they present for society.

One example of how are Community Benefit Society Cooperatives. These are renewable projects built through money raised by share and bond offers to community members. Once up and running the electricity they generate is offered back to the community, in some cases at a discount.

Bridge gives the example of a school installing solar panels on its roof: “The school would get discounted electricity from the panels, while selling power to the community. Any surplus income is then invested back into the local community, which has a say on how the money is spent.”

This can include helping to alleviate fuel poverty in areas where it is needed. A scheme in Barnsley has seen more than 300 solar panels and battery systems installed in council-owned houses in an area where 75% of residents are elderly and 25% are on pre-payment meters. The scheme estimates in its first year it saved tenants more than £40,000 through reduced electricity bills, and lowered carbon emissions by more than 400 tonnes.

Bridge points out how the benefits of decentralised projects can play an even more important role by driving the behavioural change needed to further decarbonise the electricity system.

“The beauty of community energy comes in the trusted intermediary,” she says. “It’s very effective in reaching people and helping them to adopt different patterns, because if we’re going to tackle energy challenges, it’s not just about generation. It’s about changing the way we use energy.”

But while community energy projects like these sit outside the control of national or regional electricity suppliers, they still utilise the national grid’s local distribution systems to move megawatts around. And this is where the challenges of decentralisation begin to emerge.

The grid that Merz and his contemporaries designed and built was based around big, coal power stations on the outskirts of cities pumping electricity through the transmission system to consumers.

What it enabled – constant, secure and stable power at all times, anywhere in the country – created the society we live in, the industries we work in and set the standard for how we use power. It’s a system that has endured for almost 100 years, and its success is evidenced in how little we notice it in our daily lives.

The creation of this connected power system worked to ensure there is always power and there is always an integrated, highly complex system in place to manage the flow of that power back and forth. The country’s operation relies on some degree of centralisation to keep it all running together as one.

“If we’re going to tackle energy challenges, it’s not just about generation. It’s about changing the way we use energy.”

Emma Bridge, CEO, Community Energy England

Decentralisation creates benefits at street level, but in a world with only decentralised renewable microgrids, what powers the traffic lights in Devon when the sun is only shining in Scotland? And how do we manage the power of a country of 66 million connected, technology-dependent people when everyone is a prosumer, but the country still needs to operate in unison?

These are questions that aren’t easy to answer at the best of times. They are made significantly more difficult given the scale and rate at which decentralisation is occurring. A decade ago Britain had 80 individual points of generation to manage. Today there are nearly one million.

Can we keep up with a system that is decentralising faster that we can adapt to it? And how do we support separation while maintaining the stability of the country?


Evolve or die

It’s easy to tell when electricity is working – a light bulb comes on, a kettle begins to boil. It’s a far harder task to spot when an electricity system is working, because when it works it’s invisible.

This might give the impression the system is therefore simple – it’s not. It is a complex web of infrastructure that relies on an incredible number of moving parts working in sync, at all times.

At face value, the move towards decentralisation simplifies this system. A home with a solar panel on its roof has its electricity source directly attached to what it’s powering. But behind the scenes, beyond that single house, decentralisation is actually making the whole system more complex.

To truly understand how and why it’s doing this, we need to fully understand what it takes to make the grid work.

The big bucket of electricity

Power generation must exactly match power use at all times of day, across the whole country. If more electricity is generated on the grid than is needed at that precise moment, that excess electricity can’t always be stored and used at a later date. Small amounts can be stored in batteries and larger amounts at pumped hydro storage power stations. But a large-scale nationwide seasonal storage system would be needed to meet the challenge of storing all excess electricity.

Conversely, when demand suddenly surges, power stations need to just as quickly ramp up generation to match it. It leaves the electricity network in a constant balancing act of supply and demand.

One way of thinking about this is like a bucket of water with a tap near its top. Water feeds into the top of this bucket from two different sources, which keeps the bucket full and allows the tap to flow freely when it’s open. If too much water is let in, the bucket quickly overflows. Not enough and the tap runs dry.

So far, quite simple.

But now imagine it’s not just two sources of water filling up the bucket but many. And that there are multiple taps. And these sources and taps can open and close at any moment without warning and drastically change how much water is both coming in and out of that bucket.

The risk of suddenly having too much water and the bucket overflowing grows exponentially, as does the possibility of the taps running dry.

Now imagine this system working seamlessly twenty-four hours a day, every day.

In the case of Great Britain’s electricity system, making sure this constant balancing act happens smoothly is the job of the National Grid Electricity System Operator company, which manages the integrated power system by forecasting demand, instructing generators to switch on or off, and ultimately ensuring constant stability.

Decentralisation, however, is making this task increasingly tricky. It’s ‘hiding’ a large part of the electricity being generated and used, such as self-generating office buildings or homes with solar panels. And in cases where generation remains connected to the central grid (which is still the majority of time), decentralisation has the secondary effect of adding even more complexity to the system by increasing the number of potential points of generation that may or may not be supplying power at any given time.

This system grows even more complex when we consider the way many of these sources operate. Solar and wind power operate very differently to more traditional sources. They are unable to generate at all times – such as when the weather doesn’t permit it – and can’t ramp up generation, nor easily reduce it. In the main, where they are not accompanied by storage, they are either on or off.

Because of this it’s necessary to partner these sources with flexible and dispatchable generators that can make up the difference when weather conditions limit renewable generation and can run as backup in case of sudden spikes in demand.

The grid, as a result, is a complex web of sources and systems, all of which operate in different ways and from different fuels, but all must work together to deliver electricity at all times, across the country. It has grown incredibly complicated, but it is also needed to bring some sort of order and stability to the increasingly fractured system.

The growth of this decentralised system has largely been led by a leap in technological ability. A leap that allowed solar panels and storage to become a feasible option for powering homes and communities. But to grow and remain stable the grid now needs a similar leap in something far less exciting: operational ability.

Keeping the balance in a changing system

One of the key challenges electrical engineers had to overcome when constructing the grid was standardising voltage and frequency. Electricity can operate at a different voltage or frequency depending on how it’s generated, but in a system where electricity was to be shared nationally and used to power different devices across many different wires and cables, it had to be standardised – in the UK this was set at 50 Hertz (Hz) and 230 volts (V).

Monitoring and maintaining this has been a vital part of keeping the grid stable ever since. National Grid does this through a set of tools called ‘ancillary services’, but decentralisation through intermittent renewables is making the balancing act these services provide more challenging.

One example of this is just how much power is actually running through Britain’s power lines. As the country decentralises, its power lines are increasingly becoming ‘lightly loaded’, meaning there is less current flowing along them. This is because there are more decentralised power sources meeting local demand, rather than large power plants supplying wider areas through the integrated network.

When lines are lightly loaded, voltage across the entire network rises. When there is a high load on the lines the voltage sinks. This is a problem because even small fluctuations can cause damage to equipment and lead to blackouts, so this voltage needs to be managed to remain consistent at all times.

This is done using reactive power, a type of power that helps effectively ‘move’ electricity from power stations through the system to where it’s used. Power generators can add more reactive power to the system – increasing the voltage – or absorb it to lower the voltage.

Unlike the megawatt power that lights and devices all run on, reactive power does not travel far. It’s a local product, but the balance in each area must be managed to produce the correct conditions for megawatts to flow from region to region. The National Grid’s Electricity Systems Operations division (ESO) must direct individual generators to maintain this balance. Even if distributed generators, like wind farms and solar panels, are capable of providing reactive services the ESO does not have the capability to dispatch thousands of individual units.

When the grid was first conceived it was built to provide power to a range of demands including heavy industry in factories and shipyards. Those industries have since declined and have been replaced by small electronic devices which make up so much of electricity demand today.

“Large industrial inductive power loads, such as those required for steel mills, coal mines and other heavy industries, brings voltage down and creates a demand for more reactive power,” explains Ian Foy, Head of Ancillary Services at Drax. “Now, with more small-power consumer products, service industries, and less large motor-driven demand the need for active power production is falling. Keeping the voltage down is the greater concern.”

The result is that Drax Power Station and other thermal power plants now spend more time absorbing reactive power than exporting it to keep voltage levels down. In the past, by contrast, Foy says the station would export reactive energy during the day and absorb it at night.


Perhaps an even greater threat to the stability of the network posed by decentralisation is the volatility created by the intermittent sources being added.

This creates greater need for reserve power which can suddenly jump into action and fill any sudden spikes in demand for generation – for example a football match going into extra time, clouds passing over a solar farm or gusting wind. This reserve is important in making sure there’s enough power to meet demand, but it is also critical in keeping the system frequency at 50 Hz.

Because when it isn’t there can be significant repercussions.

The effects of major frequency change

It was a lightning strike and a sudden drop in frequency that caused Great Britain’s first widespread blackout in a decade when, in August 2019, a gas power station and an offshore wind farm suffered simultaneous outages.

The initial lightning strike caused multiple small ‘embedded’ generators (such as small wind turbines, solar and small gas generators) to trip off the system. This was immediately followed by the loss of one module from the Hornsea One wind farm, and Little Barford Gas fired power station.

Such a large portion of generation coming off the grid – almost 1.8 gigawatts (GW) – couldn’t be replaced with enough fast acting reserve (as the ESO was only required to hold 1 GW in reserve at the time), which in turn caused an imbalance in supply and demand. The imbalance meant frequency dropped below the grid’s safety limits, triggering a string of safety trips that resulted in automated-but-controlled power outages across large sections of the country.

The reality of power generation is things do occasionally go wrong, and when a large power station trips and stops supplying electricity to the grid, the frequency is pulled down rapidly. In an electricity system made up of 10,000, rather than 10 different sources of power, one or even 10 small sources can suddenly stop working without severely disrupting the grid’s ability to operate.

But while this might insure against single large scale changes on the grid, it increases the potential for many more smaller ones, and this means the act of managing the grid requires a similar approach to the services that stabilise it – more of them, called upon more often.

While it’s incredibly rare for multiple large-scale power generators to cut out at the same time, the August 2019 blackout does highlight a strength of a diversified electricity system based around multiple different types of generation.

In recent times the ESO has operated the system with lower levels of inertia than historically due to the closure of large power stations. These low inertia conditions mean that it is harder to respond to changes in frequency caused by a sudden increase or decrease in demand or generation.

The promises of expanding grid scale battery and storage technologies means intermittent renewable generated electricity will be able to provide increasing amounts of these services such as reserve power and voltage management in the future.

But at present Great Britain has limited storage at the scale needed to do so – mainly its pumped storage hydro fleet in Scotland and Wales. Instead, it falls on flexible, fast acting thermal generators to provide these services.

And as more of these are called upon to ensure the grid operates flexibly, it becomes far more complex to manage it from a central point. The response to this challenge has been to split how National Grid operates it.

From nationwide to regional

National Grid made the decision to divide its electricity systems operations division (ESO) into a separate company from its electricity transmission (ET) business – which maintains the high-voltage infrastructure, in order to better manage the changing nature of the electricity system.

The National Grid’s Distributed Resource Desk was established in April 2019 to enable power system engineers to give instructions much faster to smaller generators, battery storage operators and demand side response (DSR) suppliers, and act as a central coordinating force in a diverse ecosystem.

This follows a rise in importance of locally-operated grids, also driven by the ambition to provide a degree of autonomy to regional power networks.

The local grids of Great Britain’s electricity system are currently run by six Distribution Network Operators (DNOs), which bring electricity from the national high-voltage transmission system – which National Grid ET owns and National Grid ESO controls – onto local electricity networks and into homes.

DNOs own and operate the cables, poles and transformers that make up the local electricity systems. However, as more electricity generation shifts to a local level, their role is changing from DNOs to Distributed Service Operators (DSOs) – a one-letter change that makes a big difference.

Instead of just maintaining and repairing the actual physical aspect of the local electricity network, DSOs will increasingly play a role in actually managing demand, storage capacity and generation at a local level. This is currently the responsibility of the National Grid ESO. It maintains the  generation and demand balance, and carries the reserve and ancillary services on behalf of the whole supply system. How, or even if, this responsibility can be delegated is still uncertain.

One of the first challenges these DSOs will run into, however, will be the imminent growth of another of the key players in the world’s decarbonisation efforts – electric vehicles (EV).

In 2040 Britain will ban the sale of new petrol and diesel cars, giving rise to a sudden influx of EVs in the preceding two decades. National Grid ESO’s most recent forecast puts the number of EVs it expects to be on UK roads by 2050 at over 30 million, which will in turn create an added electricity demand of close to 50 TWh on top of the current national need for just shy of 300 TWh. This growth will not only require a similar increase in generation capacity, but in how that electricity is managed.

This is because EVs won’t add an even amount of demand to the grid, they’ll add spikes at certain times of day – for example, when drivers get home from work and all plug in their vehicles to recharge or potentially in the time before rush hour begins.

The use of intelligent charging systems might be one way to help deal with this increased demand by enabling cars to automatically charge when there is a surplus of electricity and costs are low for consumers. Smart charging will also allow vehicles to act as distributed storage systems that can store excess electricity from the grid and feed it back when there’s high demand.

This type of technology – called vehicle-to-grid or V2G – is still in its infancy, but it could have a major impact. In decentralised systems, it will allow buildings to tap into connected vehicles or entire fleets of vehicles for power when demand is high but generation from sources like wind and solar is low.

It has the potential to bring added stability to the grid in its abilities to store and supply power, but it also adds yet again more complexity to the system. The difference of this complexity, however, is that it comes with a way to manage it: data.

The great data revolution

Smart meters are slowly being rolled out across Great Britain. By the end of 2020, the government has the ambitious aim of installing 50 million in homes and businesses across the country. This will vastly increase the amount of data available to help inform decisions on how the grid functions, such as what types of generation are available with the lowest carbon emissions or how much reserve power is needed at any given moment across the electricity system.

Carl Skerritt, Head of Smart Innovation at Drax highlights the potential power of this data: “If you’re getting real time readings from every single meter in every single property you’ll be able to forecast and balance the grid better.”

It’s not just the organisations controlling electricity generation and balancing that will feel the impact of smart systems. For everyday consumers the increased access to information about how they use electricity, its cost and its impact could be transformative.

“It’s an industrial revolution of the energy industry,” says Kerry Maisey, Head of Smart Integration at Drax. “For years, people have had no clarity whatsoever about the energy they’re using. That drives a certain type of behaviour where people emotionally disconnect themselves. We know we can’t keep going on the path we are, but it’s a real cultural shift for people.”

This shift represents a change in our relationship with electricity not seen in generations. When the grid first brought electricity into homes it made a noticeable and immediate positive impact to everyday lives. People were very aware of their electricity. But during the decades that followed it has become an invisible part of modern life. It is taken for granted, only noticed when bills arrive or in the rare occasion of an outage.

“It’s an industrial revolution of the energy industry.”

Kerry Maisey, Head of Smart Integration, Drax

Smart meters that deliver a more in-depth understanding of how we use electricity have the potential to reset the relationship so electricity will be something we’re all more aware of. The devices are also a vital stepping stone in the difficult task of shifting how society thinks about electricity and building the data-driven future of the grid. The question is, who will own all the detailed data on our electricity consumption and who will control access to it?

This is where centralisation, rather than decentralisation, could prove important. The Data Communications Company (DCC) is responsible for the construction and maintenance of a secure smart grid infrastructure which will be instrumental in connecting suppliers, DSOs and other third parties to allow for universal access to electricity data.

This could bring benefits similar to how granting access to the data on your phone allows apps to offer tailored services, like delivering a pizza to your precise location. By agreeing to share electricity data it could open the door to new potential technology offerings.

Maisey suggests this may manifest in services that quickly and automatically switch customers between suppliers as rapidly as every half hour to get the best deal, or in services that switch them to suppliers with the most renewable generation in action on any given day.

As with anything driven by data, cybersecurity will consequently become an important part in the world of electricity, by protecting individuals’ and organisations’ information. A central authority that can approve or revoke third-party’s access to data could prove more secure than spreading control of data across multiple businesses, by decreasing the number of potential points of penetration that unauthorised parties could breach and steal data from.

Blockchain technologies will also have the potential to be transformational for the industry as well as a further force for decentralisation. Distributed platforms like blockchain are maintained by all participants without a central authority, so they can execute millions of transactions very quickly and for a very low cost. In the case of electricity, this could allow even the smallest electricity generator to send electricity to the grid, or in a fully decentralised system, to peers on a local system.

What is certain is technology and data have the power to rapidly transform the electricity system. Together they can enable more accurate forecasting of demand and generation, begin to structure and organise the growing numbers of decentralised sources, and ultimately help bring order to a rapidly changing system.

The potential is great, but so is the question it raises: is the grid – at nearly 100 years old – fit to support this?


From the gridiron into the future

Nearly 100 years ago a small group of people hoisted up a pylon and set in motion one of the most dramatic transformations this country has ever seen. But the journey that began on that Saturday morning in Scotland and brings us to today’s sprawling, complex system is not a linear one.

It is only with the benefit of hindsight we can map out how Charles Merz, Stanley Baldwin and the rogue engineers of the CEB managed to build a grid that integrated electricity across the country.

Today we find ourselves in a similar position. We are once again at the beginning of a transformation, but where this will lead and how our electricity system will eventually look is difficult to define because the grid is always changing – it’s written into its DNA.

The grid was built to propel the country into a new age of economic and technological development. But by transforming the country it powered, it created a requirement for itself to change. It must change with – and for – the world it helps create.

This is what’s driving its transformation today.

We’re in the middle of an energy revolution that needs us to transition out of the coal-powered gridiron that Merz envisioned and into a much more complex, renewably-powered and tech-enabled future. The promise of that first centralised grid was electricity whenever we need it, wherever we are, but today we’re looking to fulfil a new promise – electricity whenever we need it, wherever we are, created in a cleaner way. This is the promise of a decentralised grid.

It’s impossible to know exactly what shape this grid will take, but we know where we’re headed, with data at its heart, driven by smart meters. The efficiencies and stability a centralised electricity system created will remain essential, but so will increasing the level of decentralised and intermittent generation. We can be certain more communities, businesses and homes will generate their own electricity.

The grid will need to play a crucial role in supporting and stabilising this. It’s a role quite different from its historic one of just a physical backbone for the power system.

Instead, this grid will need to be a centralised entity that ensures electricity remains accessible and reliable for everyone, that uses technology and data to bring order to the millions of new points of generation and storage, and that brings stability to a network of sources generating at different times, in different places and in different ways.

The grid will be the force that connects and powers us, and even though it will run through many similar cables and cross the same country it did 100 years ago, it will be a very different thing.

But it will be a national grid, and we will remain on it.

© 2020 Drax Group plc

National Grid ESO claims world first approach to inertia, awarding £328m in contracts

Image: National Grid.

Image: National Grid.

Five companies are to provide National Grid ESO with inertia without the need to simultaneously provide electricity in what it is claiming to be a world first.

The six-year contracts – worth £328 million – have been awarded to Drax, Statkraft, Triton, Rassau Grid Services (Welsh Power) and Uniper, with nine companies putting their hat in the ring.

All of the successful companies will be either modifying existing assets or building new assets to provide stability services, using less energy and enabling reduced carbon emissions, the ESO said.

Key among these services will be inertia, particularly prominent in light of the 9 August blackout.

Under the new approach, inertia will be provided without having to provide electricity, allowing more renewable generation to operate and ensuring system stability at lower costs, the ESO said.

In total the contracts are procuring 12.5GVA seconds of inertia, which traditionally has been provided using the kinetic energy in the moving parts of large generators while they are providing electricity to the grid.

National Grid ESO accesses stability by calling on synchronous generators to run through the balancing mechanism, subsequently turning down non-synchronous generation.

However, this is an expensive process, with the ESO exploring whether there are more economic solutions available through the pathfinder tenders.

Having a large number of synchronous stations running at a low load also impinges on the ESO's ability to access frequency and reserve services required for managing demand losses, it said.

The technology types the ESO accepted for the tender were synchronous compensators and synchronous generators running in a synchronous compensation mode.

The second phase of the Stability Pathfinder will facilitate a wider range of technology types, it said.

The ESO issued the invitation to tender for the Stability Pathfinder Phase 1 GB 2020, on 5th November 2019.

Julian Leslie, ESO head of networks, said lauded the approach as "the first of its kind anywhere in the world".

"Our system is one of the most advanced in the world, both in terms of reliability and the levels of renewable power, and we’re really excited to be adding to that with this new approach to managing stability.

"These contracts are finding new ways to help balance the grid which are cheaper and greener, reducing emissions and saving consumers over £100m.”

National Grid ESO signed a deal with Reactive Technologies in August for the measurement of inertia in-real time.

Following the blackout in August, Ofgem’s report into the event recommended that the ESO come forward with recommendations to improve the transparency of real time operational requirements and its holding of reserve, response and system inertia.

Ofgem also said in its report that the ESO should also undertake a review, in consultation with the industry, into the SQSS requirements for holding reserve, response and system inertia.

Cutting payments to embedded generators: a questionable decision

Ofgem has recently decided to cut payments to embedded generators – but this could have unintended negative consequences for the whole waste management sector.

Currently, and consistently for the past seven years, the UK has been producing around 27 million tonnes of municipal waste each year after recycling, as well as similar levels of commercial and industrial waste. Even if successful waste minimisation and recycling policies decrease waste generation per capita in the future, forecasts still predict an increase in overall waste produced by 2030 due to expected population growth.

Moreover, high-quality recycling is not always possible for several reasons, including the over-contamination of waste, the impossibility of recycling materials infinitely, and the need to dispose of remaining residues after recycling.

Hence, if we are serious about transitioning to a more circular economy, we need to acknowledge the reality of residual waste and adopt appropriate solutions to process it in the most sustainable way.

In line with the waste hierarchy, the preferred option for treating non-recyclable waste is energy recovery.

It is widely known that the waste and resource management industry has enabled the UK to increase its recycling rate from near zero to 45% today, by operating hundreds of energy intensive material recovery facilities (MRFs) and transfer stations around the country.

However, the industry also generates 13.874 GWh per year of electricity through energy from waste (EfW), landfill gas to energy, and anaerobic digestion (AD), providing 9% of the UK‘s renewable electricity. By recovering energy from material that would otherwise be wasted, these technologies play an important role in driving the UK towards a more circular economy.

The low-carbon electricity and heat that they recover also contributes to reduce GHGs emissions, as every tonne of waste diverted from landfill saves 200kg of CO2, and could support more low-carbon local heat networks recommended within the Clean Growth Strategy. Progressively, the UK is moving towards a sustainable circular economy model similar to Scandinavia’s, where recycling is maximised and low-carbon energy recovery technology is used to recover electricity and heat from non-recyclable wastes.

Unfortunately, Ofgem’s Targeted Charging Review (TCR), published on 21 November 2019, risks undermining the business case for waste-fuelled energy generation.

In the final decision, the government’s regulator for the gas and electricity markets in Great Britain announces plans to remove so-called “embedded benefits”. While larger electricity generators are directly connected to the national electricity transmission network, distributed generators and electricity storage which include EfW, landfill gas, and AD connect to the electricity system using distribution networks. To put this more clearly, the transmission network represents the equivalent of the motorway, while distribution networks are the local A and B roads of the electricity network system.

Because distributed generators are located close to demand, they cost consumers less in network infrastructure and are rewarded for this through embedded benefits. These are credits against various nationwide charges that those exporting onto the distribution network can earn in return for reducing these costs. Over time, the size of these payments has increased, and so Ofgem has targeted them for review in 2017, and has now decided to remove them from April 2021.

While we do appreciate that the charging regime needed to be reviewed in order to become more cost-reflective and fair for end users, Ofgem’s decision penalises small, decentralised energy generation, despite it providing significant advantages to the system, in favour of larger generators.

In the case of the waste and resources sector, this decision penalises the sector for problems it has not created since it largely produces baseload power that does not create cost or distortions in the network.

In doing so Ofgem is penalising the environmental solutions that this sector provides. Waste-fuelled energy generation not only generates low-carbon electricity that will help the UK to meet the 2050 net zero target, but it also provides an essential sanitary service which safeguards public health. These infrastructures are not located according to where they can connect to the national electricity system for a cheaper price, and in that sense they do not influence charges. Instead, they are necessarily located close to waste generation, which means they simply have to accept the price of connection as determined by the charging regime.

Ofgem’s TCR decision risks affecting the commercial viability of waste-fuelled generation and potentially waste management contracts with local authorities too. This could impede much-needed investment to deliver new waste and resources infrastructure and modify existing facilities, as well as undermine the UK’s long-term ambition to transition to a more circular economy.

Defra’s Resources and Waste Strategy, which aims to make the most out of the nation’s residual waste by diverting more residual waste from landfill to EfW, collecting and sending more food waste to AD, and by continuing to generate electricity from landfill, might well be impeded by Ofgem’s decision.

The additional costs to the waste and resources industry will have important consequences for waste management, and could lead to a waste treatment capacity crisis by undermining current and future investment.

This comes at a time when the resources and waste industry is already facing a number of challenges. The business cases for AD are already marginal. On top of this, billions of pounds of private investment are urgently needed to avoid a 3-6Mt shortfall of residual waste treatment capacity.

In reaching this position, Ofgem seems to have largely ignored small generators’ interests for the benefit of a few large energy producers. The decision risks not only undermining the government’s recycling ambitions, but even reversing the progress we have made in recent years. In the long-term it may mean disconnecting from the grid, or that recycling and EfW plants have to co-locate, but this will take time, money, and will not be possible in all circumstances.

In a context of environmental and climate emergency, undermining the business cases for distributed generators which provide low-carbon electricity infrastructure as well as essential sanitary services seems like a rather questionable decision.

Go to the profile of Eleonore Soubeyran

Eleonore Soubeyran

Policy and Parliamentary Affairs Officer, Environmental Services Association

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