Tag: electricity generation

Half year results for the six months ended 30 June 2021

Engineers walking in front of sustainable biomass wood pellet storage dome at Drax Power Station, June 2021

RNS Number: 8333G
Drax Group plc
(“Drax” or the “Group”; Symbol:DRX)

Six months ended 30 JuneH1 2021H1 2020
Key financial performance measures
Adjusted EBITDA (£ million)(1)(2)186179
Continuing operations165160
Discontinued operations – gas generation2119
Net debt (£ million)(3)1,029792
Adjusted basic EPS (pence)(1)14.610.8
Interim dividend (pence per share)7.56.8
Total financial performance measures from continuing operations
Operating profit / (loss) (£ million)84(57)
Profit / (loss) before tax (£ million)52(85)

Will Gardiner, CEO of Drax Group, said:

“We have had a great first half of the year, transforming Drax into the world’s leading sustainable biomass generation and supply company as well as the UK’s largest generator of renewable power.

“The business has performed well, and we have exciting growth opportunities to support the global transition to a low-carbon economy.

Drax Group CEO Will Gardiner in the control room at Drax Power Station

Drax Group CEO Will Gardiner in the control room at Drax Power Station

“Drax has reduced its generation emissions by over 90%, and we are very proud to be one of the lowest carbon intensity power generators in Europe – a huge transformation for a business which less than a decade ago operated the largest coal power station in Western Europe.

“In the past six months we have significantly advanced our plans for Bioenergy with Carbon Capture and Storage (BECCS) in the UK and globally. By 2030 Drax could be delivering millions of tonnes of negative emissions and leading the world in providing a critical technology needed to tackle the climate crisis.

“We are pleased to be announcing a 10% increase in our dividend, and we remain committed to creating long-term value for all our stakeholders.” 

Financial highlights

Pinnacle named ship

  • Adjusted EBITDA from continuing and discontinued operations up £7 million to £186 million (H1 2020: £179 million)
  • Acquisition of Pinnacle Renewable Energy Inc. (Pinnacle) for cash consideration of C$385 million (£222 million) (enterprise value of C$796 million) and sale of gas generation assets for £186 million
  • Strong liquidity and balance sheet
    • £666 million of cash and committed facilities at 30 June 2021
    • Refinancing of Canadian facilities (July 2021) with lower cost ESG facility following Pinnacle acquisition
  •  Sustainable and growing dividend – expected full year dividend up 10% to 18.8 pence per share (2020: 17.1p/share)
    • Interim dividend of 7.5 pence per share (H1 2020: 6.8p/share) – 40% of full year expectation

Strategic highlights

Kentaro Hosomi, Chief Regional Officer EMEA, Mitsubishi Heavy Industries (MHI) at Drax Power Station, North Yorkshire

Kentaro Hosomi, Chief Regional Officer EMEA, Mitsubishi Heavy Industries (MHI) at Drax Power Station, North Yorkshire

  • Developing complementary biomass strategies for supply, negative emissions and renewable power
  • Creation of the world’s leading sustainable biomass generation and supply company
    • Supply – 17 operational plants and developments across three major fibre baskets with production capacity of 4.9Mt pa and $4.3 billion of long-term contracted sales to high-quality customers in Asia and Europe
    • Generation – 2.6GW of biomass generation – UK’s largest source of renewable power by output
  • >90% reduction in generation emissions since 2012
    • Sale of gas generation assets January 2021 and end of commercial coal March 2021
  • Development of BECCS
    • Planning application submitted for Drax Power Station and technology partner (MHI) selected
    • Participation in East Coast Cluster – phase 1 regional clusters and projects to be selected from late 2021
    • Partnerships with Bechtel and Phoenix BioPower evaluating international BECCS and biomass technologies
  • System support – option to develop Cruachan from 400MW to over 1GW – commenced planning approval process

 Outlook

  • Adjusted EBITDA, inclusive of Pinnacle from 13 April 2021, full year expectations unchanged

Operational review

Pellet Production – acquisition of Pinnacle, capacity expansion and biomass cost reduction

close-up of truck raising and lowering

  • Sustainable sourcing
    • Biomass produced using forestry residuals and material otherwise uneconomic to commercial forestry
    • Science-based sustainability policy fully compliant with current UK, EU law on sustainable sourcing aligned with UN guidelines for carbon accounting
    • All woody biomass verified and audited against FSC®(4), PEFC or SBP requirements
  • Adjusted EBITDA (including Pinnacle since 13 April 2021) up 60% to £40 million (H1 2020: £25 million)
    • Pellet production up 70% to 1.3Mt (H1 2020: 0.8Mt)
    • Cost of production down 8% to $141/t(5) (H1 2020: $154/t(5))
  • Near-term developments in US Southeast (2021-22)
    • Commissioning of LaSalle expansion, Demopolis and first satellite plant in H2
  • Other opportunities for growth and cost reduction
    • Increased production capacity, supply of biomass to third parties and expansion of fuel envelope to include lower cost biomass

Generation – flexible and renewable generation

  • 12% of UK’s renewable electricity, strong operational performance and system support services
  • Adjusted EBITDA down 14% to £185 million (H1 2020: £214 million)
    • Biomass – Lower achieved power prices and higher GBP cost of biomass reflecting historical power and FX hedging
    • Strong system support (balancing mechanism, Ancillary Services and optimisation) of £70 million (H1 2020: £66 million) – additional coal operations and continued good hydro and pumped storage performance, in addition to coal operations
    • Coal – utilisation of residual coal stock in Q1 2021 and capture of higher power prices
  • Pumped storage / hydro – good operational and system support performance
    • £34 million of Adjusted EBITDA (Cruachan, Lanark, Galloway schemes and Daldowie) (H1 2020: £35 million)
  • Ongoing cost reductions to support operating model for biomass at Drax Power Station from 2027
    • End of commercial coal operations in March, formal closure September 2022 – reduction in fixed cost base
    • Major planned outage for biomass CfD unit – August to November 2021 – including third turbine upgrade delivering improved thermal efficiency and lower maintenance cost, supporting lower cost biomass operations
    • Trials to expand range of lower cost biomass fuels – up to 35% load achieved in test runs on one unit
  • Strong contracted power position – 29.3TWh sold forward at £52.1/MWh 2021-2023. Opportunities to capture higher power prices in future periods, subject to liquidity
As at 25 July 2021 202120222023
Fixed price power sales (TWh) 15.99.14.3
-      CfD(6)3.80.6-
-      ROC10.88.44.0
-      Other1.30.10.3
At an average achieved price (£ per MWh)51.752.452.7

Customers – renewable electricity and services under long-term contracts to high-quality I&C customer base

 

  • Adjusted EBITDA loss of £5 million inclusive of £10-15 million impact of Covid-19 (H1 2020 £37 million loss inclusive of £44 million impact of Covid-19)
  • Continuing development of Industrial & Commercial (I&C) portfolio
    • Focusing on key sectors to increase sales to high-quality counterparties supporting generation route to market
    • Energy services expand the Group’s system support capability and customer sustainability objectives
  • Closure of Oxford and Cardiff offices as part of SME strategic review and the rebranding of the Haven Power I&C business to Drax
  • Continue to evaluate options for SME portfolio to maximise value and alignment with strategy

Other financial information

  • Total operating profit from continuing operations of £84 million including £20 million mark-to-market gain on derivative contracts and acquisition related costs of £10 million and restructuring costs of £2 million
  • Total loss after tax from continuing operations of £6 million including a £48 million charge from revaluing deferred tax balances following announcement of future UK tax rate changes
  • Total loss after tax from continuing operations of £6 million including a £48 million charge from revaluing deferred tax balances following confirmation of UK corporation tax rate increases from 2023
  • Capital investment of £71 million (H1 2020: £78 million) – continued investment in biomass strategy
    • Full year expectation of £210–230 million, includes pellet plant developments – LaSalle expansion, satellite plants and commissioning of Demopolis
  • Group cost of debt now below 3.5% reflecting refinancing of Canadian facilities in July 2021
  • Net debt of £1,029 million (31 December 2020: £776 million), including cash and cash equivalents of £406 million (31 December 2020: £290 million)
    • 5x net debt to Adjusted EBITDA, with £666 million of total cash and committed facilities (31 December 2020: £682 million)
    • Continue to expect around 2.0x net debt to Adjusted EBITDA by end of 2022
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What is electricity trading?

What is electricity trading?

Electricity trading is the process of power generators selling the electricity they generate to power suppliers, who can then sell this electricity on to consumers. The system operator – National Grid ESO in Great Britain – oversees the flow of electricity around the country, and ensures the amounts traded will ultimately meet demand and do not overwhelm the power system.

Who is involved in electricity trading?

There are three main parties in a power market: generators (thermal power plants and energy storage sites, sources such as wind turbines and solar panels producing electricity), consumers (hospitals, transport, homes and factories using electricity), and suppliers in the middle from whom you purchase electricity.

Electricity is generated at power stations, then bought by suppliers, who then sell it on to meet the needs of the consumers.

Electricity trading refers to the transaction between power generators, who produce electricity, and power suppliers, who sell it on to consumers.

How are electricity contracts made?

Electricity trading occurs in both long- and short-term time frames, ranging from years in advance to deals covering the same day. Generation and supply must meet exact demand for every minute of the day, which means that traders must always be ready to buy or sell power to fill any sudden gaps that arise.

When trading electricity far in advance, factors such as exchange rates, the cost and availability of fuel, changing regulations and policies all affect the price. Short-term price is more volatile, and factors such as weather, news events and even what’s on television having the biggest impact on price. 

Traders analyse live generation data and news reports, to predict ahead of time how much electricity will be needed during periods of high demand and then determine a price. Traders then make offers and bids to suppliers and strike a deal – these deals then dictate how and when a power station’s generators are run every day.

Why is electricity trading important?

Running a power station is an expensive process and demand for electricity never stops.  The electricity market ensures the country’s power demands are met, while also aiming to keep electricity businesses sustainable, through balancing the price of buying raw materials with the price at which electricity is sold.

To ensure the grid remains balanced and meets demand, the systems operator also makes deals with generators for ancillary services, either far in advance, or last-minute. This ensures elements such as frequency, voltage and reserve power are kept stable across the country and that the grid remains safe and efficient.

Electricity trading ensures there is always a supply of power and that the market for electricity operates in a stable way

Electricity trading fast facts  

Go deeper

Turning waste into watts

Fields being ploughed by tractor

Think of carbon emissions and the image that comes to mind is often of industrial sites or power generation – not of what we eat and what we throw away. But food waste is a major contributor of greenhouse gas emissions.

Globally, food loss and waste from across the food chain generates the equivalent of 4.4 gigatonnes of carbon dioxide (CO2) a year, or about 8% of total greenhouse gas emissions.

But what if there was a way to reduce those emissions and generate power by using discarded food and other organic waste like grass cuttings or nut shells? A technology known as anaerobic digestion is increasingly making this idea a reality.

How anaerobic digestion works

All organic waste products have energy in them, but it’s tied up in the form of calories. When food and vegetation rots, microorganisms break down those calories into gases and other products.

Methane or Ammonium molecules. Science concept. 3D rendered illustration.

Methane or Ammonium molecules.

Exactly what these ‘other products’ are depends on whether there is any oxygen present. With oxygen, the products are water, CO2 and ammonia, but remove oxygen from the equation and a very valuable gas is produced: methane (CH4). The lack of oxygen is also what gives anaerobic digestion its name – when oxygen is present it becomes aerobic digestion.

During the anaerobic digestion process, bacteria and other microorganisms break down organic matter, gradually deteriorating complex polymers like glucose or starch into progressively simpler elements, such as alcohol, ammonia, CO2 and, ultimately, CH4, a biogas with huge potential as a fuel for other processes.

Anaerobic power in practice

The CH4 produced in anaerobic digestion is incredibly useful as a fuel – turn on a gas hob or stovetop and it’s predominantly methane that provides the fuel for the flame. The chemical compound is also the main component in the natural gas that makes up much of Great Britain’s electricity supply.

This means using anaerobic digestion to create CH4 out of waste products turns that waste into a valuable power source. But it’s not as simple as putting a bag over a rubbish tip and hoping for the best.

Instead, anaerobic digestion is carried out in large tanks called digesters. These are filled with feedstocks from biological substances that can include anything from food scraps, to alcohol and distillery waste, to manure. Under the right conditions microorganisms and bacteria begin to digest and breakdown these substances into their basic elements.

The air quantity and temperature of the digesters is carefully regulated to ensure the microorganisms have the best possible environment to carry out the digestion of the feedstock, with different types of feedstock and microorganisms operating best in different conditions.

The biogas created as a result of this digestion is then captured, ready to be turned into something useful.

biogas plant

Making use of biogas

Three different things can happen to the biogas produced during the course of the digestion. Locally, it can be combusted on-site to provide further heat to regulate the temperature of the anaerobic digestion units.

Or, it can be combusted in a combined heat and power (CHP) generator, where it can generate electricity to be used on site — for example to power a farm — or sold through energy suppliers such as Opus Energy onto wider regional or national electricity networks. This biogas electricity is an important element of Great Britain’s energy supply, accounting for 6,600 GWh or 7.3% of all power generated by solid and gaseous fuels in 2017.

Some of the biogas can even be cleaned to remove CO2, leaving behind pure methane that can be pumped onto natural gas grids and used to provide heat and power to households. Government research estimates a fully utilised biogas sector could provide up to 30% of the UK’s household gas demands.

After the digestion process has been completed and the biogas has been removed, what is left behind in the digester is a mass of solid matter called digestate. This is extremely rich in nutrients and mineral, such as potassium and nitrogen, making it an excellent soil enhancer.

Where anaerobic digestion is being used today

Today, much of anaerobic digestion power is generated on farms – unsurprisingly, given the ready access to biological waste material to use as feedstock. As well as a potential source of electricity and heat, it also gives farmers access to a new revenue stream, by selling electricity or biogas, as well as reducing utility and fertiliser costs.

While many of these installations are smaller scale, some can get quite big. Linstock Castle Farm in North Cumbria, for example, has a biogas facility with a 1.1 megawatt(MW) operating capacity, enough to power as many as 2,000 homes at a time. It was originally installed by the farmers as a more cost-effective way of growing their business than buying more dairy cows.

Biogas plant on a farm processing cow dung as a secondary business activity

There is, however, potential for anaerobic digestion to operate on an even larger scale. In the US, the city of Philadelphia is developing a system that will link all newly built households together into a network where food waste is automatically collected and transported to a biogas generating facility.

Closer to home, Northumbrian Water uses 100% of its sludge, the waste produced from purifying water, to produce renewable power via anaerobic digestion. It’s estimated to have reduced the carbon footprint of the facility’s operations by around 20%, and saved millions of pounds in savings on operating costs.

There have also been experiments with using biogas to power vehicles. The ‘Bio-Bus’ was the first bus in the UK to be powered by biomethane made from food, sewage and commercial liquid waste, and ran between Bath and Bristol Airport.

But anaerobic digestion power is not a magic bullet. It will be right in certain situations, but not all. If utilised effectively, anaerobic digestion and biogas could fill a vital role in national electricity and gas networks, while at the same time helping dispose of waste products in an environmentally-friendly and cost-effective way.

How to count carbon emissions

Reduced demand, boosted renewables, and the near-total abandonment of coal pushed last quarter’s carbon emissions from electricity generation below 10 million tonnes.

Emissions are at their lowest in modern times, having fallen by three-quarters compared to the same period ten years ago.  The average carbon emissions fell to a new low of 153 grams per kWh of electricity consumed over the quarter.

The carbon intensity also plummeted to a new low of just 18 g/kWh in the middle of the Spring Bank Holiday.  Clear skies with a strong breeze meant wind and solar power dominated the generation mix.

Together, nuclear and renewables produced 90% of Britain’s electricity, leaving just 2.8 GW to come from fossil fuels.

The generation mix over the Spring Bank Holiday weekend, highlighting the mix on the Sunday afternoon with the lowest carbon intensity on record

National Grid and other grid-monitoring websites reported the carbon intensity as being 46 g/kWh at that time.  That was still a record low, but very different from the Electric Insights numbers.  So why the discrepancy?

These sites report the carbon intensity of electricity generation, as opposed to consumption.  Not all the electricity we consume is generated in Britain, and not all the electricity generated in Britain is consumed here.

Should the emissions from power stations in the Netherlands ‘count’ towards our carbon footprint, if they are generating power consumed in our homes?  Earth’s atmosphere would say yes, as unlike air pollutants which affect our cities, CO2 has the same effect on global warming regardless of where it is produced.

On that Bank Holiday afternoon, Britain was importing 2 GW of electricity from France and Belgium, which are mostly powered by low-carbon nuclear.  We were exporting three-quarters of this (1.5 GW) to the Netherlands and Ireland.  While they do have sizeable shares of renewables, they also rely on coal power.

Britain’s exports prevented more fossil fuels from being burnt, whereas the imports did not as they came predominantly from clean sources.  So, the average unit of electricity we were consuming at that point in time was cleaner than the proportion of it that was generated within our borders.  We estimate that 1190 tonnes of CO2 were produced here, 165 were emitted in producing our imports, and 730 avoided through our exports.

In the long-term it does not particularly matter which of these measures gets used, as the mix of imports and exports gets averaged out.  Over the whole quarter, carbon emissions would be 153g/kWh with our measure, or 151 g/kWh with production-based accounting.  But, it does matter on the hourly timescale, consumption based accounting swings more widely.

Imports and exports helped make the electricity we consume lower carbon on the 24th, but the very next day they increased our carbon intensity from 176 to 196 g/kWh.

When renewable output is high in Britain we typically export the excess to our neighbours as they are willing to pay more for it, and this helps to clean their power systems.  When renewables are low, Britain will import if power from Ireland and the continent is lower cost, but it may well be higher carbon.

Two measures for the carbon intensity of British electricity over the Bank Holiday weekend and surrounding days

This speaks to the wider question of decarbonising the whole economy.

Should we use production or consumption based accounting?  With production (by far the most common measure), the UK is doing very well, and overall emissions are down 32% so far this century.  With consumption-based accounting it’s a very different story, and they’re only down 13%*.

This is because we import more from abroad, everything from manufactured goods to food, to data when streaming music and films online.

Either option would allow us to claim we are zero carbon through accounting conventions.  On the one hand (production-based accounting), Britain could be producing 100% clean power, but relying on dirty imports to meet its entire demand – that should not be classed as zero carbon as it’s pushing the problem elsewhere.  On the other hand (consumption-based accounting), it would be possible to get to zero carbon emissions from electricity consumed even with unabated gas power stations running.  If we got to 96% low carbon (1300 MW of gas running), we would be down at 25 g/kWh.  Then if we imported fully from France and sent it to the Netherlands and Ireland, we’d get down to 0 g/kWh.

Regardless of how you measure carbon intensity, it is important to recognise that Britain’s electricity is cleaner than ever.

The hard task ahead is to make these times the norm rather than the exception, by continuing to expand renewable generation, preparing the grid for their integration, and introducing negative emissions technologies such as BECCS (bioenergy with carbon capture and storage).


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Front cover of Drax Electric Insights Q2 2020 report

Electric Insights Q2 2020 report [click to view/download]

The cost of staying in control

What: Industrial landscape with cables, pylons and train at sunset Where: Somerset, UK When: January 2016

The cost of keeping Britain’s power system stable has soared, and now adds 20% onto the cost of generating electricity.

The actions that National Grid takes to manage the power system have typically amounted to 5% of generation costs over the last decade, but this share has quadrupled over the last two years.  In the first half of 2020, the cost of these actions averaged £100 million per month.

Supplying electricity to our homes and workplaces needs more than just power stations generating electricity.

Supply and demand must be kept perfectly in balance, and flows of electricity around the country must be actively managed to keep all the interconnected components stable and prevent blackouts.  National Grid’s costs for taking these actions have been on the rise, as we reported over the previous two summers; but recently they have skyrocketed.

At the start of the decade, balancing added about £1/MWh to the cost of electricity, but last quarter it surpassed £5/MWh for the first time (see below).

Balancing prices have risen in step with the share of variable renewables.  The dashed line below shows that for every extra percent of electricity supplied by wind and solar adds 10 pence per MWh to the balancing price.  Last quarter really bucks this trend though, and balancing prices have risen 35% above the level expected from this trend.  The UK Energy Research Centre predicted that wind and solar would add up to £5/MWh to the cost of electricity due to their intermittency, and Britain has now reached this point, albeit a few years earlier than expected.

This is partly because keeping the power system stable is requiring more interventions than ever before.  With low demand and high renewable generation, National Grid is having to order more wind farms to reduce their output, at a cost of around £20 million per month.  They even had to take out a £50+ million contract to reduce the output from the Sizewell B nuclear reactor at times of system stress.

Two charts illustrating the costs of balancing Great Britain's power system

[Left] The quarterly-average cost of balancing the power system, expressed as a percentage of the cost of generation. [Right] Balancing price shown against share of variable renewables, with dots showing the average over each quarter

A second reason for the price rise is that National Grid’s costs of balancing are passed on to generators and consumers, who pay per MWh.  As demand has fallen by a sixth since the beginning of the coronavirus pandemic, the increased costs are being shared out among a smaller baseOfgem has stepped in to cap the balancing service charges at a maximum of £10/MWh until late October.  Their COVID support scheme will defer up to £100 million of charges until the following year.

For a quarter of a century, the electricity demand in GB ranged from 19 to 58 GW*.  Historically, demand minus the intermittent output of wind and solar farms never fell below 14 GW.  However, in each month from April to June this year, this ‘net demand’ fell below 7 GW.

Just as a McLaren sports car is happier going at 70 than 20 mph, the national grid is now being forced to operate well outside its comfort zone.

This highlights the importance of the work that National Grid must do towards their ambition to be ready for a zero-carbon system by 2025.  The fact we are hitting these limits now, rather than in a few years’ time is a direct result of COVID.  Running the system right at its limits is having a short-term financial impact, and is teaching us lessons for the long-term about how to run a leaner and highly-renewable power system.

Chart: Minimum net demand (demand minus wind and solar output) in each quarter since 1990

Minimum net demand (demand minus wind and solar output) in each quarter since 1990


Read full Report (PDF)   |  Read full Report   |   Read press release


Front cover of Drax Electric Insights Q2 2020 report

Electric Insights Q2 2020 report [click to view/download]

Could hydrogen power stations offer flexible electricity for a net zero future?

Pipework in a chemical factory

We’re familiar with using natural gas every day in heating homes, powering boilers and igniting stove tops. But this same natural gas – predominantly methane – is also one of the most important sources of electricity to the UK. In 2019 gas generation accounted for 39% of Great Britain’s electricity mix. But that could soon be changing.

Hydrogen, the super simple, super light element, can be a zero-carbon emissions source of fuel. While we’re used to seeing it in everyday in water (H2O), as a gas it has been tested as an alternative to methane in homes and as a fuel for vehicles.

Could it also replace natural gas in power stations and help keep the lights on?

The need for a new gas

Car arriving at hydrogen gas station

Hydrogen fuel station

Natural gas has been the largest single source of electricity in Great Britain since around 2000 (aside from the period 2012-14 when coal made a resurgence due to high gas prices). The dominance of gas over coal is in part thanks to the abundant supply of it in the North Sea. Along with carbon pricing, domestic supply makes gas much cheaper than coal, and much cleaner, emitting as much as 60% less CO2 than the solid fossil fuel.

Added to this is the ability of gas power stations to start up, change their output and shut down very quickly to meet sudden shifts in electricity demand. This flexibility is helpful to support the growth of weather-dependant renewable sources of power such as wind or solar. The stability gas brings has helped the country decarbonise its power supply rapidly.

Hydrogen, on the other hand, can be an even cleaner fuel as it only releases water vapour and nitrous oxide when combusted in large gas turbines. This means it could offer a low- or zero-carbon, flexible alternative to natural gas that makes use of Great Britain’s existing gas infrastructure. But it’s not as simple as just switching fuels.

Switching gases

Some thermal power stations work by combusting a fuel, such as biomass or coal, in a boiler to generate intense heat that turns water into high-pressure steam which then spins a turbine. Gas turbines, however, are different.

Engineer works on a turbine at Drax Power Station

Instead of heating water into steam, a simple gas turbine blasts a mix of gas, plus air from the surrounding atmosphere, at high pressure into a combustion chamber, where a chemical reaction takes place – oxygen from the air continuously feeding a gas-powered flame. The high-pressure and hot gasses then spin a turbine. The reaction that takes place inside the combustion chamber is dependent on the chemical mix that enters it.

“Natural gas turbines have been tailored and optimised for their working conditions,” explains Richard Armstrong, Drax Lead Engineer.

“Hydrogen is a gas that burns in the same way as natural gas, but it burns at different temperatures, at different speeds and it requires different ratios of oxygen to get the most efficient combustion.”

Switching a power station from natural gas to hydrogen would take significant testing and refining to optimise every aspect of the process and ensure everything is safe. This would no doubt continue over years, subtly developing the engines over time to improve efficiency in a similar way to how natural gas combustion has evolved. But it’s certainly possible.

What may be trickier though is providing the supply of hydrogen necessary to power and balance the country’s electricity system. 

Making hydrogen

Hydrogen is the most abundant element in the universe. But it’s very rare to find it on its own. Because it’s so atomically simple, it’s highly reactive and almost always found naturally bonded to other elements.

Water is the prime example: it’s made up of two hydrogen atoms and one oxygen atom, making it H2O. Hydrogen’s tendency to bond with everything means a pure stream of it, as would be needed in a power station, has to be produced rather than extracted from underground like natural gas.

Hydrogen as a gas at standard temperature and pressure is known by the symbol H2.

A power station would also need a lot more hydrogen than natural gas. By volume it would take three times as much hydrogen to produce the same amount of energy as would be needed with natural gas. However, because it is so light the hydrogen would still have a lower mass.

“A very large supply of hydrogen would be needed, which doesn’t exist in the UK at the moment,” says Rachel Grima, Research & Innovation Engineer at Drax. “So, at the same time as converting a power plant to hydrogen, you’d need to build a facility to produce it alongside it.”

One of the most established ways to produce hydrogen is through a process known as steam methane reforming. This applies high temperatures and pressure to natural gas to break down the methane (which makes up the majority of natural gas) into hydrogen and carbon dioxide (CO2).

The obvious problem with the process is it still emits CO2, meaning carbon capture and storage (CCS) systems are needed if it is to be carbon neutral.

“It’s almost like capturing the CO2 from natural gas before its combusted, rather than post-combustion,” explains Grima. “One of the advantages of this is that the CO2 is at a much higher concentration, which makes it much easier to capture than in flue gas when it is diluted with a lot of nitrogen.”

Using natural gas in the process produces what’s known as ‘grey hydrogen’, adding carbon capture to make the process carbon neutral is known as ‘blue hydrogen’ – but there are ways to make it with renewable energy sources too.

Electrolysis is already an established technology, where an electrical current is used to break water down into hydrogen and oxygen. This ‘green hydrogen’ cuts out the CO2 emissions that come from using natural gas. However, like charging an electric vehicle, the process is only carbon-neutral if the electricity powering it comes from zero carbon sources, such as nuclear, wind and solar.

It’s also possible to produce hydrogen from biomass. By putting biomass under high temperatures and adding a limited amount of oxygen (to prevent the biomass combusting) the biomass can be gasified, meaning it is turned into a mix of hydrogen and CO2. By using a sustainable biomass supply chain where forests absorb the equivalent of the CO2 emitted but where some fossil fuels are used within the supply chain, the process becomes low carbon.

Carbon capture use and storage (CCUS) Incubation Area, Drax Power Station

Carbon capture use and storage (CCUS) Incubation Area, Drax Power Station

CCS can then be added to make it carbon negative overall, meaning more CO2 is captured and stored at forest level and in below-ground carbon storage than is emitted throughout its lifecycle. This form of ‘green hydrogen’ is known as bioenergy with carbon capture and storage (BECCS) hydrogen or negative emissions hydrogen.

There are plenty of options for making hydrogen, but doing it at the scale needed for power generation and ensuring it’s an affordable fuel is the real challenge. Then there is the issue of transporting and working with hydrogen.

“The difficulty is less in converting the UK’s gas power stations and turbines themselves. That’s a hurdle but most turbine manufacturers already in the process of developing solutions for this,” says Armstrong.

“The challenge is establishing a stable and consistent supply of hydrogen and the transmission network to get it to site.”

Working with the lightest known element

Today hydrogen is mainly transported by truck as either a gas or cooled down to minus-253 degrees Celsius, at which point it becomes a liquid (LH2). However, there is plenty of infrastructure already in place around the UK that could make transporting hydrogen significantly more efficient.

“The UK has a very advanced and comprehensive gas grid. A conversion to hydrogen would be more economic if you could repurpose the existing gas infrastructure,” says Hannah Steedman, Innovation Engineer at Drax.

“The most feasible way to feed a power station is through pipelines and a lot of work is underway to determine if the current natural gas network could be used for hydrogen.”

Gas stove

Hydrogen is different to natural gas in that it is a very small and highly reactive molecule,  therefore it needs to be treated differently. For example, parts of the existing gas network are made of steel, a metal which hydrogen reacts with, causing what’s known as hydrogen embrittlement, which can lead to cracks and failures that could potentially allow gas to escape. There are also factors around safety and efficiency to consider.

Like natural gas, hydrogen is also odourless, meaning it would need to have an odourant added to it. Experimentation is underway to find out if mercaptan, the odourant added to natural gas to give it a sulphuric smell, is also compatible with hydrogen.

But for all the challenges that might come with switching to hydrogen, there are huge advantages.

The UK’s gas network – both power generation and domestic – must move away from fossil fuels if it is to stop emitting CO2 into the atmosphere, and for the country to reach net zero by 2050. While the process will not be as simple as switching gases, it creates an opportunity to upgrade the UK’s gas infrastructure – for power, in homes and even as a vehicle fuel.

It won’t happen overnight, but hydrogen is a proven energy fuel source. While it may take time to ramp up production to a scale which can meet demand, at a reasonable cost, transitioning to hydrogen is a chance to future-proof the gas systems that contributes so heavily to the UK’s stable power system.

What is the national grid?

Electricity grid

What is the grid?

The national grid, or simply the grid, is the network of powerlines, pylons, gas lines and interconnectors that makes up Great Britain’s electricity and gas systems — and the engineers, technology and rules responsible for their seamless operation. It ensures electricity generated anywhere, by any source, can be transmitted to meet the demand for power wherever it’s needed across the country. It heats homes and businesses. It helps us to cook our food.

The national electricity grid consists of a high voltage transmission system, which connects electricity from power stations to substations and smaller local networks – called Distribution Network Operators, or DNOs – which transport electricity into homes and businesses.

Key national grid facts

How does it work?

Transporting electricity around the grid is more complicated than just connecting cables to power generators. In order to move power around the country, things like voltage and frequency of electricity must be balanced and kept uniform at all times. Without this, unstable electricity could damage equipment and ultimately lead to blackouts.

The National Grid Electricity System operator (ESO) is a separate entity from the National Grid company, and is responsible for maintaining the correct voltage, frequency and reserve power levels to ensure electricity is transmitted safely and efficiently at all times.

It does this by working with power generators and energy storage facilities to provide what are known as ‘ancillary services’ – a set of processes that keep the power system in operation, stable and balanced.

The national grid is the network of power stations, powerlines and electricity infrastructure that allows electricity to be generated, transported and used across the country.

Who controls it?

In Great Britain the National Grid company owns and operates the transmission systems which ensure electricity is delivered safely and reliably across the country.

The local distribution system is made up of 14 regional DNO companies, which deliver electricity at a lower voltage from substations to homes and businesses.

Great Britain’s grid incudes England, Scotland, Wales and several surrounding islands. Northern Ireland is part of an island-wide electricity system with the Republic of Ireland.

National grid fast facts

  • Great Britain’s grid is made up of more than 7,000 kilometres of cables, 90,000 pylons, 346 substations, and 1,500 kilometres of underground cables
  • Construction of the grid began on 14 July 1928 and was completed on 5 September 1933
  • It was originally designed to operate as 7 separate, connected grids, before a group of rebellion engineers attempted to run it as one on 29 October 1938. It has run as one grid ever since
  • A decade ago, Britain had 80 individual points of generation to manage. Today there are nearly one million
  • All electricity in Great Britain operates at a frequency of 50Hz. A deviation of just 1% above or below could cause damage

How is the grid changing?

As the sources that generate Great Britain’s electricity change to include more renewables, the grid has also changed.

The grid was built to work with large power stations that operate huge spinning turbines. With decarbonisation it’s evolved to include a greater variety of intermittent weather dependent sources such as wind, solar and decentralised power sources that serve individual buildings or communities.

This makes managing the grid’s stability more complicated, and requires the use of more ancillary services, usually delivered by flexible generators such as thermal power stations.

Go deeper

What are ancillary services?

Ancillary services

What are ancillary services?

Ancillary services are a set of processes that enable the transportation of electricity around the grid while keeping the power system operating in a stable, efficient and safe way.

Why do we need ancillary services? 

When electricity makes its way through the country, it needs to be managed so that the power generation and electricity useage levels are equal.

The regulating of elements such as frequency and voltage has to be carefully managed, so that the massive amounts of electricity moving – or transmitted – are able to be used safely in homes,  businesses, schools and hospitals around the country.

Ancillary services enable the power system to operate in a stable, efficient and safe way.

 What do ancillary services offer?

Ancillary services include a wide variety of electrical efficiency and safety nets, all focussed on ensuring the power system delivers enough output to meet demand yet remains stable:

Frequency: The UK’s power system runs at a frequency of 50 hertz – to stay balanced, it has to remain at that frequency. Turbines and generators adjust the speed at which they spin automatically to increase or decrease power in line with demand and ensure that the system is kept stable.

Voltage: Different parts of the UK’s transmission system use voltages of either 400, 275 or 132 kilovolts. To ensure that voltage remains within 5% of those figures at all times, to be safe for domestic electricity use, power stations can produce or re-absorb excess energy as reactive power, keeping the overall system reliable.

Inertia: Turbine use is important in keeping the system operating in its current state, even with disruptions and sudden changes. The electricity system uses the weight of heavy spinning turbines to create stability, acting as dampeners and smoothing out unexpected changes in frequency across the network.

Reserve: An important part of ancillary servicing is making sure that there are no surprises – so holding back powerto release if something unexpected happens means that the network can function confidently, knowing that there are generators and other power providers such as pumped hydro storage waiting ready to back it up.

Key facts about ancillary services

Who manages ancillary services?

In the UK the grid’s stability is managed by National Grid Electricity System Operator (ESO) – a  separate company of National Grid Electricity Transmission (ET). The ESO works with ancillary service providers to either sign long-term contracts or make short term requests for a service.

These partners are often power stations, such as Drax Power Station, which have large spinning turbines capable of controlling voltage, frequency, providing inertia and serving as a source of reserve power. 

What is the future of ancillary services, as we move to a more renewable system?

As the UK’s electricity system continues to change, so to do its requirements for different ancillary services. The switch from a few very large power stations to a greater variety of different electricity sources, some of which may be dependent on the weather, as well as changes in how the country uses electricity, means there is a greater need for ancillary services to keep the grid stable.

These services have historically been delivered by thermal power stations, but new innovations are enabling wind turbines to provide inertial response and overcome changes in frequency, and batteries to store reserve power that can then be supplied to the power system to ensure balance.

Ancillary Services

Ancillary services fast facts  

  • Batteries can in some cases be cheaper ancillary alternatives to conventional sources of energy. The Hornsdale Power Reserve, which runs on a Tesla battery in South Australia, lowered the price of frequency ancillary services by 90% after just four months of use.
  • Ancillary services usually work from habit; knowing when to slow electricity production, or increase supply based around the general public’s standard working hours, dinner time and the early morning rush.
  • But during the COVID-19 lockdown, electricity consumption on weekdays fell by 13% and so National Grid ESO had to intervene with ancillary services to keep the lights on.
  • Every year, the ESO’s ancillary services move 300 terawatt hours (TWh) of electricity, which is equal to 4 trillion kettles boiling at once.

With recent innovations around renewable energies, there are a wider variety of ways for ancillary services to generate power.

Go deeper

Button: What is decarbonisation?

How electrical transformers work

Getting electricity safely and efficiently from generators, through power lines and across the country into our devices is a careful balancing act. One of the vital aspects of this is the voltage.

An electrical substation with transformers.

The National Grid’s transmission lines work at a voltage of 400,000 volts (v) and 275,000v, but if electricity were to enter homes at this voltage it would quickly damage anything it powered. Instead, regional distributors deliver electricity into homes at a much lower level of 230v.

Achieving a voltage level that’s safe to use requires stepping it up or down through transformers – huge pieces of electrical grid equipment that use a simple idea to have a big impact.

Why we need transformers

Voltage is like water pressure. Having high voltage transmission lines means the charged electrons that make up electricity are moving very efficiently through the system, with less energy being lost as heat along the way. However, that same ‘pressure’ is too much for just charging a phone. It would likely overload the device’s circuits and leave the user with a smouldering mess.

That’s where transformers step in. Electricity is produced at a variety of voltages around Great Britain, depending on different types of generation. In order to send it to where the demand is without losing too much energy as heat along the journey, a transformer attached to large power generators such as Drax’s biomass power plant or Beatrice offshore wind farm increases the voltage to 400,000v or 275,000v. The voltage depends on what part of the national transmission system the power station is connected to.

When the electricity arrives via pylons at a particular region of Great Britain, another transformer brings the voltage down to 132,000v for the regional distribution system. Subsequently, another reduces it to 11,000v in towns and villages, before a final transformer reduces the voltage to a safe 230v for use in homes and businesses.

Keeping the voltage high is useful in preventing energy loss to heat, but it also does something else important to the electricity shooting around the country.

Keeping voltage high to cut down current

If voltage is the water pressure, then current is the actual water particles moving through the pipes. In electrical terms the current is the charged electrons that actually power our lights and devices.

When these electrons travel along the electricity grid’s cables, they face resistance (imagine a partial blockage in a water pipe) this causes some electrical energy to be lost to heat. Getting the right amount of electricity needed around the country means keeping energy loss as low as possible. If the current is lower, fewer charged electrons are bumping into resistance at any one point in the system and less electrical energy is being lost.

Conveniently for the grid, raising the voltage of electricity causes the current to decrease and vice versa. How transformers actually do this is all a matter of coils. 

Super transformer at Cruachan Power Station

Transformer at Cruachan Power Station

Winding voltage up and down

Transformers work using the principal of electromagnetic induction, something the British scientist Michael Faraday first realised in 1831. He noticed that when a magnet moved through a coil of copper wires, a current flowed through those wires. It’s this same principal that enables spinning turbines to generate electricity today.

Michael Faraday

Michael Faraday

Similarly, when a current flows through a copper coil wrapped around an iron core, the core becomes magnetic.

Faraday did experiment with running currents through multiple copper coils, but it was scientist and Irish priest Father Nicholas Callan who in 1836 discovered the underlying principal of many of the world’s transformers today. He found if two separate sets of copper wires were wound around each end of an iron core and an electrical current was passed through one of them (the primary winding) then a magnetic field is created that causes an electric current to flow in the secondary winding.

However, things change depending on how many times each wire is wound around the core. If there are more turns in the secondary winding than the primary one, then when a current is induced the voltage increases. When there are fewer turns in the secondary winding than the primary, the voltage decreases.

Callan's Induction Coil

Callan’s Induction Coil (1845)

Moreover, Father Callan discovered that the increase or decrease in voltage is directly proportional to the number of turns in the windings. So, theoretically, if an electrical current with a voltage of 5v is passed through a primary winding with 10 turns and creates a current in a secondary winding with 20 turns, the voltage will also double, in this case to 10v.

Father Callan’s invention is known as an induction coil, where the two sets of windings share a long, thick iron rod. Since then the transformer has undergone continual revision, optimisation and specialisation for different use cases. However, the underlying principal of using electromagnetic induction to increase and decrease voltage remains the same.

From homes to power stations

One of the most common types of transformers are distribution transformers – the kind often found on utility poles near homes. These transformers perform the final step down from local distribution systems to 230v as the electricity enters homes and businesses.

These often use an iron core that takes the form of a hollow square with windings wrapped around both ends. When a current passes through and magnetises the core it causes it to expand and contract in a process known as magnetostriction, which sometimes causes enough vibration to produce an audible hum.

A transformer being moved from Longannet to Cruachan Power Station in 2019.

A transformer being moved from Longannet to Cruachan Power Station in 2019.

In these type of transformers it’s safe for the current to be transferred through the air between the two windings, but when higher voltages are being used, such as at Cruachan Power Station – the biggest pumped storage facility in Scotland – different approaches are needed. Large power station-scale transformers are submerged in a special insulating oil inside a metal container. The oil provides electrical insulation to prevent short circuits while also cooling the core and windings, preventing damage and failure.

Even as the main sources of Great Britain’s electricity change from coal and nuclear power stations to wind farms and solar panels, transformers will remain an essential part of the grid, in getting the right amount of power to where we need it – fast.