Author: Alice Roberts

What makes a country’s electricity system stable?

How reliable is Great Britain’s electricity system? Across the country electricity is accessible and safe to use for just about everyone, every day. Wide-scale blackouts are very rare, but they do happen.

On 9 August 2019 a power cut saw more than 1 million people and services lose power for just under an hour. It was the first large-scale blackout since 2013. Although this proves the network is not infallible, the fact it was such an outlier in the normal performance of the grid highlights its otherwise exemplary stability and reliability.

But what is it exactly that makes an electricity system stable and reliable?

At its core, system stability comes down to two key factors: a country or region’s ability to generate enough electricity, and its ability to then transport it through a transmission system to where it’s needed.

When everything is running smoothly an electricity system is described as being ‘balanced’. In this state supply meets demand exactly and all necessary conditions – such as voltage and frequency – are right for the safe and efficient transport of electricity. Any slight deviation or mismatch across any of these factors can cause power stations or infrastructure to trip and cut off power.

A recent report by Electric Insights identified the countries around the world with most reliable power systems, in which the UK was fourth. It offers an insight into what factors contribute to building a stable system, as well as those that hold some countries back.

Generation and reliable infrastructure  

According to the report, France has the most reliable electricity system of any country with a population of more than five million people, having gone a decade without a power outage. One reason for this is the country’s fleet of 58 state-controlled nuclear power stations which generate huge amounts of consistent baseload power.

In 2017 nuclear power made up more than 70% of France’s electricity generation while hydropower accounted for another 10% of the 475 Terawatt hours (TWh) consumed across the county that year.

Penly Nuclear Power Station near Dieppe, France.

Now, as its nuclear stations age, France is increasing its renewable power generation. As these sources are often weather dependent, imports from and exports to its neighbours are expected to become a more important part of keeping the French network stable at times when there is little sunlight or wind – or too much.

Importing and exporting electricity is also key to Switzerland’s power system (third most reliable network on the list), with 41 border-crossing power lines allowing the country to serve as a crossroads for power flowing between Italy and Germany. It means its total imports and exports can often exceed electricity production within the country.

Electricity pylons in Switzerland.

Switzerland’s mountainous landscape also means ensuring a reliable electricity system requires a carefully maintained transmissions system. The Swiss grid is 6,700 kilometres long and uses 40,000 hi-tech metering points along it to record and process around 10,000 data points in seconds.

The key to the stability of South Korea – the second most stable network on the list – is also its imports, but rather than actual megawatts it comes in the form of oil, gas and coal. The country is the world’s fourth biggest coal importer and its coal power stations account for 42% of its total generation.

Seoul, South Korea.

However, in the face of urban smog issues and global decarbonisation goals it is pursuing a switch to renewables. This can come with repercussions to stability, so South Korea is also investing in transmission infrastructure, including a new interconnector from the east of the country to Seoul, its main source of electricity consumption.

It highlights that if decarbonisation is going to accelerate at the pace needed to meet Paris Agreement targets, then many of the world’s most stable and reliable electricity systems need to go through significant change. Balance will be needed between meeting decarbonisation targets with overall system stability.

However, there are many countries around the world that focus less on ensuring consistent stability through decarbonisation and are instead more focused on how to achieve stability in the first place.

Stalling generation

The Democratic Republic of Congo is the eleventh-largest country on earth. It is rich with minerals and resources, yet it is the least electrified nation. Just 9% of people have access to power (in rural areas that number drops to just 1%) and the country suffers blackouts more than once a month as a result of ‘load shedding’, when there isn’t enough power to meet demand so parts of the grid are deliberately shut down to prevent the entire system failing.

Currently, the country has just 2.7 GW of installed electricity capacity, 2.5 GW of which comes from hydropower. The country’s Inga dam facility on the Congo river has the potential to generate more electricity than any other single source of power on the planet (it’s thought the proposed Grand Inga site could produce as much as 40 GW, twice that of China’s Three Gorges Dam) and provide electricity to a massive part of southern Africa. A legacy of political instability in the country, however, has so far made securing financing difficult.

Congo River, Democratic Republic of Congo.

Nigeria is one of the world’s fastest growing economies, and with that comes rapidly rising demand for electricity. However, just 45% of the country is currently electrified, and of these areas, many still suffer outages at least once a month. The country has 12.5 GW of installed capacity, most of which comes from thermal gas stations, but technical problems in power stations and infrastructure, mean it is often only capable of generating as much as 5 GW to transmit on to end consumers.

This limited production capability means it often fails to meet demand, resulting in outages. The problem has been prolonged by struggling utility companies that are unable to make the investments needed to stabilise electricity supply.

Keen to resolve what it has referenced as an ‘energy supply crisis’, the Nigerian government recently secured a $1 billion credit line from the World Bank to improve access to electricity across the country.

The investment will focus in part on securing the transmission system from theft, thus allowing the private utility companies to generate the revenue needed to improve generation.

Transmission holding back emerging systems

Balancing transmissions systems is a crucial part of stable electricity networks. Maintaining a steady frequency that delivers safe, usable electricity into homes and businesses is at the crux of reliability. Even countries that can generate enough electricity are held back if they can’t efficiently get the electricity to where it is needed.

Brazil has an abundance of hydropower installed. Its 97 GW of hydro accounts for more than 70% of the country’s electricity mix. However, the country’s dams are largely concentrated around the Amazon basin in the North West, whereas demand comes from cities in the south and eastern coastline. Transporting electricity across long distances between generator and consumer makes it difficult to maintain the correct voltage and frequency needed to keep a stable and reliable flow of electricity. As a result, Brazil suffers a blackout every one-to-three months.

Hydropower plant Henry Borden in the Serra do Mar, Brazil.

The country is tackling its transmissions problems by diversifying its electricity mix to include greater levels of solar and wind off its east coast – closer to many of its major cities. The country has also looked to new technology for solutions.

At the start of the decade as much as 8% of all electricity being generated in Brazil was being stolen, reaching as high as 40% in some areas. These illegal hookups both damage infrastructure, making it less reliable, as well as blur the true demand, making grid management challenging.

Brazil has since deployed smart meters to measure electricity’s journey from power stations to end users more accurately, allowing operators to spot anomalies sooner. Electricity theft is a major problem in many developing regions, with as much as $10 billion worth of power lost each year in India, which suffers blackouts as often as Brazil.

It highlights that even when there is generation to meet demand, maintaining stability at a large scale requires constant attention and innovation as new challenges arise.

This looks different around the world. Some countries might face challenges in shifting from stable thermal-based systems to renewables, others are attempting to build stability into newly connected networks. But no matter where in the world electricity is being used, ensuring reliability is an ever-ongoing task.

Electric Insights is commissioned by Drax and delivered by a team of independent academics from Imperial College London, facilitated by the college’s consultancy company – Imperial Consultants. The quarterly report analyses raw data made publicly available by National Grid and Elexon, which run the electricity and balancing market respectively, and Sheffield Solar. Read the full Q3 2019 Electric Insights report or download the PDF version.

How Scotland’s sewage becomes renewable energy

Stevie Gilluley Senior Operator at Daldowie fuel plant

From traffic pollution to household recycling and access to green spaces, cities and governments around the world are facing increasing pressure to find solutions to a growing number of urban problems.  

One of these which doesn’t come up often is sewage. But every day, 11 billion litres of wastewater from drains, homes, businesses and farms is collected across the UK and treated to be made safe to re-enter the water system.   

Although for the most part sewage treatment occurs beyond the view of the general population, it is something that needs constant work. If not dealt with properly, it can have a significant effect on the surrounding environment.  

Of the many ways that sewage is dealt with, perhaps one of the most innovative is to use it for energy. Daldowie fuel plant, near Glasgow is one such place which processes sewage sludge taken from the surrounding area into a renewable, low carbon form of biomass fuel.  

The solution in the sludge   

In operation since 2002, Daldowie was acquired by Drax at the end of 2018 and today processes 35% of all of Scotland’s wastewater sludge, into dry, low-odour fuel pellets.   

“We receive as much as 2.5 million tonnes of sludge from Scottish Water a year,” says Plant Manager Dylan Hughes who leads a team of 71 employees, “And produce up to 50,000 tonnes of pellets, making it one of the largest plants of this kind in the world.”  

“We have to provide a 24/7, 365-day service that is built into the infrastructure of Glasgow,” he explains.   

This sludge processed at Daldowie is not raw wastewater, which is treated in Scottish Water’s sewage facilities. Instead, the sludge is a semi-solid by-product of the treatment process, made of the organic material and bacteria that ends up in wastewater from homes and industry, from drains, sinks and, yes, toilets.   

Until the late 1990s, one of Great Britain’s main methods of disposing of sludge was by dumping it in the ocean. After this practice was banned, cities where left to figure out ways of dealing with the sludge.   

Using sludge as a form of fertiliser or burying it in landfills was an already established practice. However, ScottishPower, instead decided to investigate the potential of turning sludge into a dry fuel pellet, that could offer a renewable, low carbon substitute to coal at its power plants. 

Cement manufacturing fuel kilns

Daldowie was originally designed to supply fuel to Methil Power Station near Fife, which ran on coal slurry. However, it was decommissioned in 2000, before Daldowie could begin delivering fuel to it. This led the plant to instead provide fuel to Longannet Power Station where it was used to reduce its dependency on coal, before it too was decommissioned in 2016. 

Today Daldowie’s pellets are used in England and Scotland to fuel kilns in cement manufacturing – an industry attempting to navigate the same decarbonisation challenges as power generation which Daldowie was established to tackle.  

Though the end use of the fuel has changed, the process through which the facility transforms the waste remains the same.  

The process of turning waste to energy  

The process starts after wastewater from Glasgow and the surrounding area is treated by Scottish Water. Daldowie receives 90% of the sludge it processes directly via a pressurised sludge pipeline, the rest is delivered via sealed tanker lorries.   

When it arrives at Daldowie, the sludge is 98% water and 2% solid organic waste. It is first screened for debris before entering the plant’s 12 centrifuges, which act as massive spinning driers. These separate water from what is known as ‘sludge cake’, the semi-solid part of the sludge feedstock. This separated water is then cleaned so it can either be used elsewhere in the process or released into the nearby River Clyde. 

Membrane Tank at Daldowie fuel plant

The remaining sludge cake is dried using air heated to 450 degrees Celsius using natural gas (this also reduces germs through pasteurisation), while the rotating drums give the fuel granules their pellet shape. Once dried the pellets are cooled and inspected for quality. Any material not up to necessary standards is fed back into the system for reprocessing. Fuel that does meet the right standards is cooled further and then stored in silos.   

Where possible throughout the process, hot air and water are reused, helping keep costs down and ensuring the process is efficient.  

Nearly two decades into its life, very little has had to change in the way the plant operates thanks to these efficiencies. But while the process of turning the waste sludge into energy remains largely unchanged, there is, as always, room for new innovation 

 Improving for the future of the site 

Daldowie is contracted to recycle wastewater for Scottish Water until 2026. To ensure the plant is still as efficient and effective as possible, the Daldowie team is undertaking a technical investigation of what, if anything, would be needed to extend the life of the plant for at least an additional five years. 

“The plant operates under the highest environmental and health and safety standards but further improvements are being planned in 2020.” Hughes explains, “We are upgrading the odour control equipment to ensure we have a best in class level of performance.  

The control room and plant operators at Daldowie

“Drax’s Scotland office, in Glasgow, is working with other industrial facilities in the area, as well as the Scottish Environmental Protection Agency (SEPA), to work with the local community. We are putting in place a series of engagement events, including plant tours from early 2020, offering local residents an opportunity to meet the local team and discuss the planned improvements.”    

There are also other potential uses for the fuel, including use at Drax Power Station. As the pellets are categorised as waste and biomass, it would require a new license for the power station.  

However, at a time when there is a greater need to reduce the impact of human waste and diversify the country’s energy, it would add another source of renewable fuel to Great Britain’s electricity mix that could help to enable a zero carbon, lower cost energy future.  

The policy needed to save the future

Abstract picture of a modern building closeup

Over the past decade the United Kingdom has decarbonised significantly as coal power has been replaced by sources like biomass, wind and solar. Every year power generation emits fewer and fewer tonnes of carbon thanks to renewables and with the ban on the sale of new diesel and petrol cars coming in no later than 2040, roads and urban areas are about to get cleaner too.

However, there are still tough challenges ahead if the UK is to meet its target of carbon neutrality by 2050. Aviation, heavy industry, agriculture, shipping, power generation – some of the key activities of daily economic life – all remain reliant on fuels that emit carbon.

This is where Greenhouse Gas Removal (GGR) technologies have a big role to play. These can capture carbon dioxide (CO2) and other greenhouse gases from the atmosphere, and either store them or use them, helping the drive towards carbon neutrality.

While the idea of being able to capture carbon has been around for some time, the technology is fast catching up with the ambition. There now exist a number of credible solutions that allow for capturing emissions. The challenge, however, is putting in place the framework and policies needed to enable technologies to be implemented at scale.

Time is short. A recent report by Vivid Economics for the Department for Business, Energy and Industrial Strategy (BEIS) emphasised the need for government action now if we are to achieve the volume of carbon removal needed to achieve net zero emissions by 2050.

The tech to take emissions out of the atmosphere

The planet naturally absorbs CO2, forests absorb it as they grow, mangroves trap it in flooded soils, and oceans absorb it from the air. So, harnessing this power through planting, growing and actively managing forests is one natural method of GGR that can be easily implemented by policy.

Aerial view of mangrove forest and river on the Siargao island. Philippines.

The idea of using technology to capture CO2 and prevent its release into the atmosphere has been around since the 1970s. It was first deployed successfully in enhanced oil recovery, when captured emissions are injected into underground oil reserves to help remove the oil from the ground.

Over time it’s been developed and is now in place in a number of fossil fuel power stations around the world, allowing them to cut emissions. However, by combining the same technology with renewable fuels like compressed biomass wood pellets, we can generate electricity that is carbon negative.

Each of these solutions operate in different ways, but all are important. Vivid Economics’ report emphasises that a range of different solutions will be required to reach a point where 130 million tonnes of CO2 (MtCO2) are being removed from the atmosphere in the UK annually by 2050.

However, investment and clear government planning and guidance will be crucial in enabling the growth of GRR. The report estimates large-scale GGR could cost around £13 billion per year by 2050 in the UK alone, a figure similar in size to current government support for renewables.

“If you went back 20-odd years, people were sceptical of the role of wind, solar and biomass and whether the technologies would ever get to a cost point where they could be viably deployed at scale,” explains Drax Policy Analyst Richard Gow.

“In the last few years we’ve seen enormous cost reductions in renewables and people are far more confident in investing in them – that has been driven by very good government policy.”

GGR needs the same clear long-term strategy to enable companies to make secure investments and innovate. But what shape should those policies take for them to be effective?

Options for policies                    

Perhaps the most straightforward route to enabling GGR is to build on existing policies. For example, there are existing tree planting schemes such as the Woodland Carbon Fund, Woodland Carbon Code and the Country Stewardship Scheme, all of which could receive greater regulatory support, or additional rules obliging emitters to invest in actively managed forests.

More technically complex solutions, like bioenergy with carbon capture and storage (BECCS) and direct air carbon capture and storage (DACCS), could be incentivised by alternative mechanisms in order to provide clarity on, and to stabilise, revenue streams. These are already used to support companies building low-carbon power generation such as through the Contracts for Difference scheme and have been effective in encouraging investment in projects with high upfront costs and long-payback periods.

Alternative options to support the roll-out of negative emissions technologies should also be considered. For example, the government could make it obligatory for companies that contribute to emissions, to pay for GGR to avoid increased burden on electricity consumers.

In such a scenario, fossil fuel suppliers would be required to offset the emissions of their products by buying negative emissions certificates from GGR providers. As a result, the price of fossil fuels for users would likely rise to cover this expense and the costs would then be shared across the supply chain rather than just a single party.

Another approach that passes the costs of GGR deployment on to emitters is using emissions taxes to fund tax credits for GGR providers.

Making these tax credits tradable would also mean any large tax-paying company, such as a supermarket or bank, could buy tax credits from GGR providers. This approach would come at no cost to government as sales of the tax credits would be funded by an emissions tax and would offer revenue to GGR providers.

The challenge with tax credits, however, is they are vulnerable to changes in government. An alternative is to offer direct grants and long-term contracts with GGR providers which would ensure funding for projects that transcends changes in Parliament. They could, however, prove costly for government.

Whatever policy pathway the government may choose to follow, there are underlying foundations needed to support effective GGR deployment.

Making policies work

 There are still many unknown factors in GGR deployment, such as the precise volume that will be needed to counter hard-to-abate emissions. This means all policy must be flexible to allow for future changes, and the individual requirements of different regions (forest-based solutions might suit some regions, DACCS might be better in others).

Underlying the strength of any of these policies, is the need for accurate carbon accounting. Understanding how much emissions are removed from the atmosphere by each technology will be key to reaching a true net zero status and giving credibility to certificates and tax credits.

Pearl River Nursery, Mississippi

Proper accounting of different technologies’ impact will also be crucial in delivering innovation grants. These can come through the UK’s existing innovation structure and will be fundamental to jumpstarting the pilot programmes needed to test the viability of GGR approaches before commercialisation.

Different approaches to GGR have different levels of effectiveness as well as different costs. BECCS, for example, serves two purposes in both generating low-carbon power and capturing emissions – resulting in overall negative emissions across the supply chain. 

“It’s important to account for the full value chain of BECCS,” explains Gow. “Therefore, it should be rewarded through two mechanisms: a CfD for the clean electricity produced and an incentive for the negative emissions. A double policy here is important because you are providing two products which benefit different sectors of the economy, one benefits power consumers and the other provides a service to society and the environment as a whole, and cost should be apportioned as such.

BECCS and DACCS also have to consider wider supply chains, such as carbon transport and storage infrastructure. Although this requires a high initial investment, by connecting to industrial emitters, it can enable providers to recover the costs through charges to multiple network users.

Ultimately, the key to making any GGR policies work effectively and efficiently is speed. In order to put in place accounting principles, test different methods, and begin courting investors, government needs to act now.

The Vivid Economics report “is further confirmation of the vital role that BECCS will play in reaching a net zero-carbon economy and the need to deploy the UK’s first commercial project in the 2020s,” Drax Group CEO Will Gardiner says.

“Our successful BECCS pilot is already capturing a tonne of carbon a day. With the right policies in place, Drax could become the world’s first negative emissions power station and the anchor for a zero carbon economy in the Humber region.”

It will be significantly more cost efficient to begin deploying GGR in the next decade and slowly increase it up to the level of 130 MtCO2 per year, than attempting to rapidly build infrastructure in the 2040s in a last-ditch effort to meet carbon neutrality by 2050.

Read the Vivid Economics report for BEIS, Greenhouse Gas Removal (GGR) policy options – Final Report. Our response is here. Read an overview of negative emissions techniques and technologies. Find out more about Zero Carbon Humber, the Drax, Equinor and National Grid Ventures partnership to build the world’s first zero carbon industrial cluster and decarbonise the North of England.

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

Maintaining electricity grid stability during rapid decarbonisation

Cruachan pylons

Great Britain’s electricity system is in the middle of a revolution. Where power supply was once dominated by some big thermal coal, gas and nuclear power stations, it now comes from an array of sources. Thousands of new individual points have been added to the mix, ranging from large interconnectors, that bring in power from neighbouring countries, through to wind farms, solar panels, small gas and diesel engines.

The energy mix has been changing radically, with low carbon sources expected to provide 58% of Great Britain’s power by 2020, up from 22% in 2010 and 53% in 2018. However, the security standards at which the electricity grid needs to be operated remain the same; these are predominantly voltage and frequency, and nominally 230 V and 50Hz for a domestic consumer.

The operation of the Transmission system, including maintaining these standards is overseen by the National Grid Electricity System Operator (ESO), using a set of vital tools it needs to have available, known as ancillary services. Some of this capability was inherent in large generators, which could provide the ancillary services required to keep a stable transmission system. Maintaining system stability, with thousands of generation points — a large part of which are not directly controllable — is increasingly challenging.

Click graphic to view/download

Ancillary services enable electricity to reach the end customer when and where it is required, in a safe manner, within acceptable quality standards. In addition to managing voltage and frequency levels, these standards also include maintaining adequate reserves to accommodate demand forecast uncertainties, generator breakdown and system faults. 1.

As the electricity mix changes, so must the process by which these services are secured. A diverse set of existing and genuinely new solutions will be needed to keep the lights on in the net zero carbon future.

Three steps to creating the right environment for a stable, resilient future grid:

1. Make the value of ancillary services transparent

In order for companies to help the ESO, be they generators or other service providers, it must be open and transparent about what’s needed to maintain grid stability and build resilience for the future.

“The ESO is the only buyer in the ancillary services market and is well-positioned to understand how the system is evolving. It should be proactively flagging how its needs may evolve in the future, so that the market can develop solutions to meet them”, says Marcelo Torres, Drax’s Regulation Manager – Markets.

Certain ancillary services still don’t have their own competitive markets and are provided as a “by-product” of the generation of electricity. An example is reactive power, for which there are no developed functioning regional markets yet. Generally, all power stations connected to the transmission network with a generation capacity of over 50MW are required to have the capability to provide this service, at a default price that may not reflect its real value to the system.

Another example is inertia, provided today largely through the heavy spinning turbines of thermal and pumped-storage hydro stations, which serve as stored energy that can slow down or smooth out sudden changes in network frequency.

If ancillary services were valued explicitly, market participants would have an insight into how much they are actually worth to the ESO and the grid’s stability, which would in turn incentivise new, competitive products to reach the market.

Torres points to technologies such as synchronous compensators, which are machines capable of providing ancillary services, including inertia and reactive power, without generating potentially unneeded electricity.

Services which can be provided by different power technologies

Click graphic to view/download

“These solutions will enable more renewables to connect safely to the network at a lower cost to consumers. For these solutions to come forward, ascribing the right value to ancillary services will be key. Without clear price signals, there is a risk of underinvestment in those technologies that provide the services needed, potentially resulting in price shocks for consumers”.

“The ESO is moving in the right direction with its recent Network Development Pathfinder projects. It has accelerated this work, launching its first ever tender for inertia and should roll out similar initiatives GB-wide. Such procurements should align with existing investment signals such as those provided by the Capacity Market. This should allow for the right type of capacity to be built where it is most needed, delivering a secure and resilient grid”.

2. Create market confidence

“Constructing the machinery and infrastructure that will enable the ESO to operate a carbon-free system will require major financial investment, as well as years to plan and build,” says Torres.

“This can only be achieved if Ofgem designs the ESO’s incentives in a way that rewards it for taking bold, strategic initiatives that have the potential to deliver good value for money to consumers in the long-term.”

Evidence of this working is shown in the success of offshore wind, which now provide around a sixth of Great Britain’s electricity, at record low prices. This is partly due to the government providing offshore wind developers with revenue stabilisation mechanisms, known as ‘Contracts for Difference’ (CfDs).

This is not a new concept for government and regulators around the world looking to enable investment in energy infrastructure. Financing renewables to achieve decarbonisation is enabled through CfDs or market-led hedging tools, like Power Purchase Agreements. Investment to ensure there is sufficient capacity to meet peak demand is secured through long-term contracts, competitively awarded through the Capacity Market. Similarly, investment in interconnection is supported through Ofgem’s ‘Cap & Floor’ regime.

“Subsidy isn’t required for investment in ancillary services. What’s needed,” says Torres, “is a clear and stable market framework designed around the system’s needs, which provides a mix of short and long-term signals. More certainty over the market landscape and the expected returns will lower the risk of these investments and get the solutions needed at a lower overall cost to consumers.”

“Long-term procurement is not the right answer everywhere. Where there is already a mature and liquid market, such as the case for frequency response, buying services closer to real time makes sense for two reasons. First, it allows prices to reflect more accurately the market conditions and therefore the real value of a service at the time when it is needed. Second, it allows a wider range of resources to participate in the market, increasing competition. Striking the right balance between short and long-term procurement is key to create a sustainable ancillary services market.”

Currently, the ESO requests that electricity-generation firms commit to supplying a certain amount of power for the purpose of frequency response, a month ahead of time. For resources such as wind farms or solar, which are dependent on the weather, this makes it extremely difficult for them to enter this market. Even for conventional large thermal generators it can be a problem, as many of them do not know how or if they will be running beyond a few days.

“The ESO is currently conducting some trials procuring frequency response one week in advance. While this is an improvement, it is still too long a lead time for intermittent sources or demand-side response, which ideally need day-ahead or almost real time auctions to unlock their full potential,” says Torres.

“The ancillary services market has been through a prolonged period of change since the ESO published its System Needs and Product Strategy in 2017. Without knowing how the market landscape will look like by the end of these reforms, it’s difficult for providers to develop the right solutions.”

A shift in thinking, which considers what the electricity network might require in the future, and how to provide the market with financial incentives to make it a reality, is needed. A resilient, stable future system is to the advantage of consumers.

3. Diversify

There will be no silver bullet that can solve all the challenges the energy transition poses. Maintaining system reliability in a high renewables world will require large amounts of dispatchable power, with different response time and duration. From small batteries and demand-side response that will manage instantaneously frequency fluctuations, through to large pumped storage hydro plants that will provide backup power during the days when the wind won’t blow and the sun won’t shine. A framework structured around the system’s different needs should aim at harnessing flexibility across a range of technologies and sizes.

 

Truly diversifying will also involve unlocking the flexibility potential on the distribution grid. To achieve this, the way that access to the distribution network is managed and paid for will need to evolve. Today, with big parts of the distribution network being congested, small flexible assets are asked to wait in the queue for several years or face disproportionate amount of network reinforcement costs to get connected.

Machine hall, Cruachan Power Station

The ongoing review of the network access and forward-looking charging arrangements needs to address these barriers soon, if we are serious about making use of flexibility to foster the energy transition, while keeping consumer bills as low as possible.

Since 2018, GB’s Distribution Network Operators (DNOs) have been tendering and procuring for various flexibility services to manage congestion in regional electricity grids. In 2019, they published a roadmap setting out the steps they intend to take to enable a smarter and more flexible energy system.

“As we transition from DNOs towards Distribution System Operation – a wider set of functions and services to run a smart distribution grid – the regional networks will be open to market-based flexibility solutions. DSOs will be able to compete on a level playing field, offering options for network reinforcement. As DNOs move from trials to more structured flexibility procurement, harmonisation and effective coordination with the national markets will be the key pre-requisites to reveal the true value that flexibility can bring to the energy system,” argues Torres.

“To build a modern and resilient grid we will need a wider lens on what’s possible. It’s going to be an exciting journey on the road to net zero!”

This story is part of a series on the lesser-known electricity markets within the areas of balancing services, system support services and ancillary services. Read more about black startsystem inertiafrequency responsereactive power, voltage control and reserve power. View a summary at The great balancing act: what it takes to keep the power grid stable and find out what lies ahead by reading Balancing for the renewable future.

The men who built a power station inside a mountain

Cruachan tunnel tigers

Travelling through the Highlands towards the West Coast of Scotland, you pass the mighty Ben Cruachan – its 1,126 metre peak towers over the winding Loch Awe beneath. It is the natural world on a huge scale, but within its granite core sits a manmade engineering wonder: Cruachan Power Station.

Opened by The Queen in 1965, it is one of only four pumped-hydro stations in the UK and today remains just as impressive an engineering feat as when it was first opened.

Cruachan is operated safely and hasn’t had a lost time injury in 15 years. The robust health and safety policies and practices employed at the power station were not in place all those decades ago.

It took six years to construct, enlisting a 4,000-strong workforce who drilled, blasted and cleared the rocks from the inside of the mountain, eventually removing some 220,000 cubic metres of rubble. The work was physically exhausting – the environment dark and dangerous.

Nicknamed the ‘Tunnel Tigers’, the men that carried the work out came from far and wide, attracted to its ambition as well as a generous pay packet reflective of the danger and difficulty of the work. But few of them were fully prepared for the extent of the challenge.

One labourer, who started at Cruachan just after his 18th birthday, recalls: “I was in for a shock when I went down there. The heat, the smoke – you couldn’t see your hands in front of you.”

Inside the mountain

The work of hollowing out Ben Cruachan was realised by hand-drilling two-to-three metre deep holes into the granite rockface. An explosive known as gelignite, which can be moulded by hand, was packed into the drilled holes and detonated. The blasted rocks were removed by bulldozers, trucks and shovels, before drilling began on the fresh section of exposed granite. In total, 20km of tunnels and chambers were excavated this way, including the kilometre-long entrance tunnel and the 91-metre-long, 36-metre-high machine hall.

Wilson Scott was just 18 when he got a job working as a labourer at Cruachan while the machine hall was being cleared out.

“The gelignite, it had a smell. Right away I was told not to put it near your face,” he says, “It’ll give you a splitting headache and your eyes will close with the fumes that come off it. It was scary stuff.”

This process allowed for rapid expansion through the mountain. With three or four blasts each 12-hour shift, some 20 metres of rock could be cleared in the course of a day. Activity was constant, and to save the men having to make the journey back up to the surface, refreshments came to them.

“There was a bus that went down the tunnel at 11 o’clock with a huge urn of terrible tea,” says Scott. “Most of the windows were out of the bus because the pressure of the blasting had blown them in.”

The tea did little to make the environment hospitable, however. From the water dripping through the porous rocks making floors slippery and exposed electrics vulnerable, to the massive machinery rushing through the dense dust and smoke, danger was ever-present. Loose rocks as large as cars would often fall from exposed walls and ceilings while the regular blasting gave the impression the entire mountain was shaking.

“I’ll tell you something: going into that tunnel the first time,” Scott says. “It was a fascinating place, but quite a scary place too.

Above them, on top of the mountain, a similarly intrepid team tackled a different challenge: building the 316-metre-long dam. They may have escaped the hot and humid conditions at the centre of Cruachan, but their task was no less daunting.

Cruachan dam construction, early 1960s

Cruachan dam construction, early 1960s

On top of the dam

Out in the open, 400 metres above Loch Awe, the team were exposed to the harsh Scottish elements. John William Ross came to Cruachan at the age of 35 to work as a driver and spent time working in the open air of the dam. “You’d get oil skins and welly boots, and that was it. We didn’t have gloves, if your hands froze – well that’s tough luck isn’t it.” Mr Ross sadly passed away recently.

Charlie Campbell, a 19-year-old shutter joiner who worked on the dam found an innovative way around the cold. “You’d put on your socks, and then you’d get women’s tights and you’d put them over the top of the socks, and then you’d put your wellies on and that’d keep your feet a wee bit warmer. We thought it did anyway. Maybe it was just the thought of the women’s stockings.”

Pouring the concrete of the dam – almost 50 metres high at its tallest point – was precarious work, especially given the challenges of working with materials like concrete and bentonite (a slurry-like liquid used in construction).

“It was horrible stuff. It was like diarrhoea, that’s the only way of explaining it,” says Campbell. “There was a boy – Toastie – I can’t remember his real name. He fell into it. They had quite a job getting him out, they thought he was drowned, but he was alright.”

Many others were not alright. The danger of the work and conditions both inside and on top of the mountain meant there was a significant human cost for the project. During construction, 15 people tragically lost their lives.

Today a carved wooden mural hangs on the wall of the machine hall to capture and commemorate the myth of the mountain and the men who sadly died – a constant reminder of the bravery and sacrifice they made.

The men that made the mountain

The Cruachan ‘Tunnel Tigers’

The Tunnel Tigers were united in their efforts, but came from a range of backgrounds and cultures. Polish and Irish labourers worked alongside Scots, as well as displaced Europeans, prisoners of the second world war and even workers from as far as Asia. The men would work 12, sometimes 18-hour shifts, seven days a week. Campbell adds that some men opted to continue earning rather than rest by doing a ‘ghoster’, which saw them working a solid 36 hours.

Many men would make treble the salary of their previous jobs, with some receiving as much as £100 a week, at a time when the average pay in Scotland was £12. Some teams’ payslips were stamped with the words ‘danger money’ – illustrative of the men’s motivation to endure such life-threatening work.

While it was a dangerous and demanding job, many of the Tigers look back with fond memories of their time on the site and many stayed in the area for years after. “It was an experience I’m glad I had,” says Scott. “It puts you in good stead for the rest of your days.”

As for Cruachan Power Station, its four turbines are still relied on today by Great Britain to balance everyday energy supply. As the electricity system continues to change, the pumped hydro station’s dual ability to deliver 440 megawatts (MW) of electricity in just 30 seconds, or absorb excess power from the grid by pumping water from Loch Awe to its upper reservoir, is even more important than when it opened.

Standing at the foot of a mountain more than 50 years ago, the men about to build a power station inside a lump of granite may have found it unlikely their work would endure into the next millennium. They may have found it unlikely it was possible to build it at all. But they did and today it remains an engineering marvel, a testament to the effort and expertise of all those who made it.

Visit Cruachan – The Hollow Mountain

Further statement in relation to the AGM vote on political donations

Meeting Seminar Conference Business Collaboration Team Concept

In the lead up to the 2019 AGM, the Company undertook initial consultation with major shareholders and received a variety of feedback on both the Resolution and the Company’s approach to engagement with regulators and policymakers including political parties and governments.

Following the AGM, the Board of Directors initiated further engagement to facilitate a clear understanding of the reasons underpinning the votes cast against the Resolution. This included writing to the Company’s largest shareholders and offering to discuss how the Company proposed to respond to points raised during the initial consultation and policy on stakeholder engagement. The Company is grateful to those shareholders that provided feedback at that time.

The Company regularly engages with regulators and policymakers in the UK, Europe and USA (including those associated with political parties and governments) to understand and contribute to discussions on a wide range of matters which are associated with our business and delivering increased value to our shareholders. This approach is detailed on pages 32 and 33 of the 2018 Annual Report as a fundamental aspect of our stakeholder engagement. Political and regulatory risk has been identified by the Board as one of the nine principal risks that the business faces. Activities of this nature are not designed to support any political party or to influence public support for a particular party and would not be thought of as political donations in the ordinary sense of those words.

Reflecting the feedback received from shareholders, it has been determined that within future Annual Reports additional disclosure will be provided. This will describe the forms of engagement that have taken place with regulators and policymakers in the financial year as well as additional disclosure regarding the oversight of that engagement. To assure shareholders of the governance associated with managing engagement and transparency, the Company has also developed and published a policy explaining how stakeholder engagement is undertaken, including oversight and associated reporting.

The term ‘political donation’ is widely defined in the Companies Act 2006 (“the Act”). For clarity, the Company has not made, and does not intend to knowingly make, political donations. The Company continues to believe it is in the best interests of the business and shareholders to renew the authority most recently granted at the 2019 AGM to avoid any inadvertent infringement of the Act.

Prior to 2019, the Company had proposed an authority to spend up to £50,000 under each of the three categories covered by the Act. At the 2019 AGM, Drax sought an authority to spend up to £100,000 under the same three categories which was approved by a majority of shareholders.Nonetheless and reflecting feedback received in connection with the Resolution, at the 2020 and future AGMs the Company will propose an authority to spend up to £100,000 in each of the three categories but will introduce an aggregate cap of £125,000.

Further explanation on these matters, and our ongoing engagement with shareholders, will be included in the 2019 Annual Report and notice of the 2020 AGM.

Enquiries:

Drax Investor Relations: Mark Strafford
+44 (0) 1757 612 491

Media:

Drax External Communications: Matt Willey
+44 (0) 1757 612 285

Smart ways to charge EVs

Electric car

The future of electric cars and electric vans holds great potential – not just for the transport industry’s overall carbon footprint, but for the populations of heavily congested, polluted cities and even individual drivers looking for more efficient fuel costs.

That future is approaching fast. By 2040 or even as soon as 2035 no new cars or vans sold in the UK can be solely powered by diesel or petrol. While this is a positive step, it brings with it a shift in the way drivers will need to manage the way they plan journeys and, more importantly, refuel.

Dark Blue Electric Sports Car Driving

For years drivers have relied on a quick and plentiful supply of fuel at petrol stations. But an EV doesn’t charge as quickly as a conventional car, nor are fast charging points widespread – at least not right now.

The change will be considerable, but it won’t necessarily take shape in a single form. Here we look at four things that will become increasingly influential in how drivers recharge their EVs over the coming years.

  1. Smart charging and time-of-use tariffs

Electricity costs more to produce and supply at certain times of the day. This wholesale price depends on the demand for power, weather conditions and the costs of different generation technologies and fuels.

For example, electricity is often more expensive in the evenings when people are coming home from work and turning on lights, TVs, ovens and plugging in devices. Just a few hours later it rapidly drops in price as homes and offices turn off lights and appliances. But the power system is changing.

The price of electricity is increasingly driven by less predictable factors such as the weather. On windy and sunny days, wind and solar generation can drive down the cost of producing power. On calm and cloudy days, the costs of electricity can increase.

While this, in theory, makes it sensible to wait for a cheap period of time to plug in and charge an electric vehicle (EV), in practice people are unlikely to spend the time sit refreshing websites which display the price of electricity in real time to get the best value. Instead, the use of ‘smart charging technology’ can play a big role to capitalise on fluctuations in prices. Electric charge in a village house. Outside the city the countryside.

Smart charging technology will be able to monitor things like electricity prices and even electricity usage across an entire site (for example across a business where many devices are using electricity) and automate the charging process to make use of the best prices and limit overall electricity use.

Rather than needing someone to recharge EVs at one o’clock in the morning, this means people or businesses can plug in at times convenient to them and set their vehicles to charge at the cheapest times and have an appropriate amount of charge to carry out tasks when they need to.

“By shifting power usage into cheaper periods you’re saving money and you can be more sympathetic to supply and demand limits on a company,” explains Adam Hall, who leads Drax’s EV proposition. “If I know my battery will be fully charged by nine in the morning, do I care if it charges immediately or delays it and saves me a few pounds?” For business fleet owners who manage large numbers of electric vehicles the difference this can make is even larger, he adds.

  1. Vehicle-to-grid (V2G) technology

Each EV has a battery in it that powers the vehicle’s motor. But what if the electricity stored in that battery could also be harnessed to deliver electricity back to grid? And what if that concept could be used to collect a small portion of power from every idle EV in the country and use it to plug gaps in the electricity system?

“There are over 30 million cars on UK roads. National Grid predicts by 2050, 99% of those vehicles will be powered by electricity,” explains Hall. “The majority of cars remain idle for 95% of any day. That’s a huge amount of storage potential that could be used to balance the grid at key times. It’s a battery network that assets around the country will be able to use.”

This concept is what’s called vehicle to grid technology  (V2G), and while it holds great potential, it’s still some way from becoming a mainstream source of reserve power. Right now the technology is costly and limited – only ‘CHAdeMO’ charging systems, as found on Japanese models, actually support bi-directional charging. Nevertheless, Hall remains optimistic of its future role in the energy system, particularly as this technology will be hugely important in managing future grid constraints

“The cost of bi-directional hardware is coming down all the time,” he says. “At the moment there aren’t enough vehicles, we don’t have the scale to do it, but I fully believe it will change quite dramatically.”

For domestic users the benefit will be less immediate than it will be for entire countries. For business fleet managers, allowing the grid to take some power from their idle vehicles could lead to financial compensation or other advantages for offering grid support.

  1. The out of sight, out of mind approach: third party management schemes

More suited for businesses managing whole fleets of vehicles, employing a third party to manage the charging of vehicles allows for the delegation of a potentially costly and time-consuming task.

Adam Hall, Drax EV proposition lead, with Drax’s electric vehicle fleet service.

“Effectively the customer knows they’ll get the vehicles with the amount of charge they want when they need it,” says Hall. “That might be for the cheapest price or as fast as possible. It means the customer doesn’t have to think, they just get their charged vehicle in the optimum way for their needs.”

Third party providers could also open up new charging businesses models, such as flat monthly rates for unlimited vehicle charging or all-renewable services. By taking the technical aspects of running a fleet out of businesses hands, third parties could even serve to lower the barrier to EV adoption.

  1. Mandatory managed charging

It’s difficult to accurately know how much demand electric vehicles will place on the electricity system– some estimates see demand growing in Great Britain as much as 22% by 2050 as a result of EVs.

While the constant development of battery and charging technology will likely mean this prediction will come down, there are some theories as to how the country will need to deal with this rapid growth. One of these is to actually turn down the electricity surging through charging points at certain points to prevent widespread blackouts.

“The idea is there to protect the grid,” explains Hall. “When local distribution networks have a lot of demand they may need to turn charge points down.” He adds there will likely be exemptions for emergency services, however.

Hall is sceptical mandatory managed charging would ever really come into play, for the damage it would do to consumer attitudes to EVs. The idea also taps into wider scaremongering around EVs and quite how much they will push up electricity demand.

Instead what will really need to shift for a future of efficiently charged vehicles is a mindset shift. “There’s a psychological element to it,” he suggests. “Everyone goes through some range anxiety at first but soon realises the technology is sound.”

As battery technology continues to improve, vehicles evolve to go further on a single charge, and networks of super-fast charge points expand, transitioning to electric vehicles will become easier and more economical for businesses than continuing to depend on fossil fuel.

“I personally believe once electric vehicles are doing 300 miles on a single charge, the requirement for on-route charging will be pretty low,” says Hall. “Not many people drive 300 miles, need to recharge at a service station and then drive anther 300 in one fell swoop. It’s much more important to have good charging installations at work and at home.”

There are many ways in which EVs will change the way the world drives, from how we charge them to how and where we travel. We can be certain this will mean a shift in mindsets and our approach to transport. What remains uncertain is just how quickly and widespread that shift will be.

From coal to pumped hydro storage in 83 mountainous miles

Moving of transformers from Longanett to Cruachan

Nestled in in the Western Highlands in Scotland, Cruachan Power Station is surrounded by a breathtaking landscape of plunging mountainsides and curving lochs, between which weave narrow roads.

It makes for scenic driving. What might be trickier, however, is transporting 230 tonnes of electrical equipment up and down said mountains, navigating narrow bends.

But that’s exactly what a team from Drax was tasked with when it came to moving two 115 tonne transformers, the equipment used to boost electricity’s voltage. They were in storage 83 miles away at Longannet, currently being demolished, near Fife.

“You’re moving a piece of equipment that is designed to stay in one place. It’s not designed to go on the roads,” explains Jamie Beardsall, an Electrical Engineer from the EC&I Engineering team who worked on the project. “You’re very aware of your environment and the risks. Everything is checked and doubled checked.”

Transformers being driven to Drax’s Cruachan pumped storage hydro power station

The complicated task required colleagues from both Cruachan and Drax power stations to collaborate from the very beginning. Gary Brown, Mark Rowbottom and Jamie from the EC&I Engineering team based in Yorkshire teamed up with Gordon Pirie and Roddy Davies from Scotland who met frequently and planned the project alongside specialist transport contractor, ALE, which advised on heavy lifting and movement.

Planning and execution of the works also required constant liaison and coordination with the police and highway authorities in both Scotland and England. But more than that, the transformers’ one-by-one journey from the demolition site of what was once Europe’s biggest coal-fired power station, to a hydro-powered energy storage site on the other side of Scotland, represents the continual shift of Great Britain’s electricity away from fossil fuels.

Stepping up voltage

Transformers are an essential part of the electricity system. By increasing or decreasing the voltage of an electrical current they can enable it to traverse the national grid or make electricity safe to enter our homes.

“When we generate electricity, it is at a lower voltage than we need to send it out to the national grid,” says Beardsall. “We use transformers to increase the voltage so it can go out to the national grid and be transmitted over long distances more efficiently. We then reduce the voltage again so it can be brought safely into our homes.”

While all transformers apply the same principles for stepping voltage up and down, the two transformers that were transported through the Highlands to Cruachan were designed specifically for the pumped storage hydro power station, but stored at Longannet where there was more space. At the time, both stations where owned by Scottish Power. Cruachan was purchased by Drax on the last day of 2018.

Engineers at Cruachan Power Station in front of one of the original transformers

When transported, each transformer weighs 115 tonnes and is almost four metres high. Transporting them isn’t as simple as loading them into the back of a van.

“You can’t transport them in a fully built state, they would be too heavy and wouldn’t go under bridges,” says Beardsall. “We had to strip them back to the core and now we’re working to reassemble them on site.”

Cutting down to the core

Each transformer consists of two main components; a core made of iron, and two windings made of copper. The transformer itself has no moving parts. When a voltage is applied to one of the transformer windings (the primary winding), a magnetic field is created in the iron core. This field then induces a voltage into the other winding (the secondary winding). Depending on the number of coils on each set of windings, the output voltage will increase or decrease. More coils on the secondary winding steps the voltage up, fewer coils on the secondary steps the voltage down.

This entire apparatus is submerged in an oil to provide insulation and keep the transformer cool, meaning the first step was to drain 50,000 litres of oil from each transformer. This was then sent to a refinery to be processed, cleaned and stored until the transformers are reassembled at Cruachan.

Oil removed, the Drax engineers oversaw and managed the dismantling of the transformers at Longannet. Once the transformers were stripped down to a state suitable for movement, they were loaded up one-by-one for transportation.

Meanwhile, at Cruachan, engineers worked on construction of a purpose built bunded area for storage of the transformers. The transformers were destined to be stored on land outside the main admin buildings, adjacent to Loch Awe.

Loch Awe at Cruachan Power Station

The Loch itself is a beautiful place with abundant animal and birdlife – and a fish farm is located almost directly opposite the power station. In the event of a transformer leaking, the natural environment must be protected. An oil-tight storage area was therefore built, to ensure that no oil would end up in the Loch.

The road to Cruachan

Rather than heaving each of the transformers onto a trailer, each one was raised using hydraulic jacking equipment. A trailer was then driven underneath, and the transformer lowered onto it.

“The trailer is specifically designed to take the transformers and fit certain dimensions,” explains Beardsall. “It has 96 wheels over 12 sets of axles, each of which can be turned individually to assist in navigating around tight spots.”

The trailers are towed by large tractor units, each weighing over 40 tonnes. These provided the motive power to move the transformers. Each was moved in two stages over the space of two weeks. The first transformer over the course of a weekend, the second in the middle of the night some 10 days later.

“When we could go was governed by the police and highways agencies as they need to close the roads,” says Beardsall. “We set off from Longannet at 7pm on the Friday evening and moved them 60 miles along the route to a layby where we stored them. That leg took approximately five hours. Then the second leg was the last 25 miles to Cruachan, carried out on the Sunday morning of the same weekend.”

Navigating the Highlands with 115 tonnes of hugely valuable equipment is where the real challenge came in. Hills, dips and tight turns made for slow progress.

Generator transformer at Cruachan Power Station

The original generator transformer at Cruachan Power Station

“The average speed was about 10mph, but we’re going through the Highlands so it was quite a bit slower than that in some places. We occasionally hit 20+ mph at points, but that was definitely for the minority of the time!” says Beardsall. “Some of the roads were so narrow it was difficult to get two cars past each other. The contractors also had to put metal plating over bridges because they weren’t strong enough to take the load.”

Having safely arrived at Cruachan, the transformers are being stored at surface level until they are needed, at which time they will be taken down the half-a-mile-long tunnel into the energy storage station.

“Typically a transformer has a design life of 25 years, although they can last longer” explains Beardsall. “There are four units at Cruachan and the transformers for two of these units have already been replaced, so these transformers would be used to replace the existing transformer for the two remaining units should it ever be needed. The existing transformer having been in operation since 1965.”

Moving heavy objects is part and parcel of running Drax’s multiple power stations around the country. However, navigating the Highlands, the very terrain which makes Cruachan possible, added a unique challenge for Drax’s engineers.

Visit Cruachan Power Station – The Hollow Mountain

Read the press release

A brief history of Scottish hydropower

The Clatteringshaws Dam in the Galloway Forest Park in south west Scotland. Built by Sir Alexander Gibb & Partners in 1932-38, it is on the south west

Over the last century, Scottish hydro power has played a major part in the country’s energy make up. While today it might trail behind wind, solar and biomass as a source of renewable electricity in Great Britain, it played a vital role in connecting vast swathes of rural Scotland to the power grid – some of which had no electricity as late as the 1960s. And all by making use of two plentiful Scottish resources: water and mountains.

But the road to hydro adoption has been varied and difficult, travelled on by brave death-defying construction workers, ingenious engineers and the inspirational leadership of a Scottish politician.

To trace where the history of Scottish hydropower began, we need to go back to the end of the 19th Century and to the banks of Loch Ness.

Loch Ness, Scottish Highlands

Loch Ness, Scottish Highlands

From abbeys to aluminium 

It was on the shores of Loch Ness that one of the first known hydro-electric schemes was built at the Fort Augustus Benedictine abbey. The scheme provided power to the monks living there as well as 800 village residents – though legend has it that their lights went dim every time the monks played their organ.

However, it was the British Aluminium Company, formed in 1894, that first realised the huge potential of Scotland’s steep mountains, lochs and reliably heavy rainfall to generate substantial amounts of hydro power. In need of a reliable source of electricity to help turn raw bauxite into aluminium, the firm established a hydro-electric plant and smelting works at Foyers and Loch Ness. Several similar schemes to support the aluminium industry soon appeared around the country.

But it took another 20 years for the first major hydro-power project to supply electricity to the public to emerge.

In 1926, the Clyde Valley Electrical Power Co. opened the Lanark Hydro Electric Scheme, which used energy from the River Clyde’s flow to create power. Now owned by Drax, it still has a generation capacity of 17 MW – enough to supply more than 15,000 homes.

River Clyde, Lanark

It was quickly followed by power stations at Rannoch and Tummel in the Grampian mountains and, in 1935, by what became a highly influential scheme in the history of Scottish hydro power at Galloway.

Drawing enough energy from local rivers to support five generating power stations, the project was the largest run-of-the-river scheme ever created. Architecturally, it also set the tone for later projects with stylised dams and modernist turbine halls.

A fairer share of power for the Highlands

The Galloway scheme supplied energy to a wide area, too, including parts of the central Highlands. Scottish Labour MP Tom Johnston, a staunch socialist and Scottish patriot saw how this new power source could provide massive benefits to northern communities. In the early 1940s, only an estimated one in six Scottish farms and one in a hundred small land crofts had electricity.

In 1941, Johnston became Scotland’s Minister for State with a vision, as he put it, to create “large-scale reforms that might mean Scotia Resurgent”. Expanding hydro power was a priority.

Tom Johnston MP

Two years later, he formed the North of Scotland Hydro-Electric Board (NSHEB). Its aim was to create several new schemes, including at Tummel and Loch Sloy, that would supply the national grid and bring electricity to more rural Scottish areas.

The projects were met with fierce opposition from landowners and local pressure groups who feared new dams and power stations would ruin the countryside and bring unwelcome industrialisation.

Public enquiries followed, but the board’s promises that the developments would be sensitive to the environment and bring cheap electricity in areas such as the Isle of Skye and Loch Ewe eventually won the day.

Thousands of local men, as well as German and Italian former prisoners of war, were drafted in to work on the projects.

Among the most courageous were workers known as ’Tunnel Tigers’ who blasted away rock using handheld drills and gelignite to create water channels and underground chambers, including at Drax’s Cruachan pumped storage hydro station.

Deaths caused by everything from blast injuries to fires were common. The men also had to cope with incessant rain and cold, and were housed in bleak military-style camps. With little to do in their spare time, besides drink, fights would break out regularly.

But the financial rewards were enormous, with wages up to ten times higher than labourers employed on Highland estates could expect.

Glenlee penstocks

The future takes shape

The board’s first small projects were completed in 1948 at Morar and Nostie Bridge, supplying electricity to areas including parts of Wester Ross. Catherine Mackenzie, a local widow, performed the Morar opening ceremony, reportedly declaring: “Let light and power come to the crofts.”

Bigger schemes were plagued by problems. Conveyor belts had to be built to transport stone across 1.75 miles of moor during construction at Sloy, for instance, and there were frequent stone and timber shortages.

But Sloy eventually opened in 1950, the largest conventional hydro electrical power station in Great Britain with an installed capacity of 128 MW. It would be followed by major schemes at Glen Affric and Loch Shin.

By the mid Sixties, the Board had built 54 main power stations and 78 dams. Northern Scotland was now 90% connected to the national grid. Hydro Board shops began popping up on high streets, selling appliances and collecting bill payments.

Tom Johnston died in 1965, aged 83. The Provost of Inverness declared: “No words can say how grateful we are.”

Cruachan Power Station

Loch Awe beside Cruachan Power Station

That same year, the world’s then largest reversible pumped storage power station opened at Cruachan. During times of low electricity demand, its turbines pump water from Loch Awe to the reservoir above. When demand rises, the turbines reverse, and water flows down to generate power. A similar scheme opened at Foyes in 1974.

Glendoe, near Loch Ness, was the most-recent major hydro scheme to be built. Opening in 2009, it has a generation capacity of 100 MW.

There are plans for a pumped storage scheme at Coire Glas, with a storage capacity of 30 GWh– more than doubling Great Britain’s current total pumped storage capacity. Drax’s Cruachan Power Station could also be expanded.

In recent years, however, the real growth has been in smaller hydro-electric schemes that may power just one or a handful of properties – with more than 100 MW of such generation capacity installed in the Highlands since 2006.

Boosting the environment and economy

Scotland now provides 85% of Great Britain’s hydro-electric resource, with a total generation capacity of 1,500 MW. Improved power supplies have attracted more industry to the Highlands, without seriously altering its character. And access roads created during hydro-power schemes’ construction have opened up remote areas to tourism.

For many, the dams built by NSHEB are among the greatest construction achievements in post-war Europe and remain an essential part of Great Britain’s attempts to move towards a low-carbon energy future.