Tag: investors

Great Britain is almost ready for coal-free summers

14 August 2018

Power generation

Every summer Great Britain uses less and less coal. This June the fossil fuel’s share of the electricity mix dipped below 1% for the first time ever – for 12 days it dropped all the way to zero.

Spurred on by the beginnings of an uncharacteristically dry, hot summer and a jump in solar generation, the possibility of the country going entirely coal-free for a full summer now looks more achievable than ever in modern times.

This is one of the key findings from Electric Insights, a quarterly report commissioned by Drax and written, independently, by researchers from Imperial College London. It found that across Q2 2018, there were as many coal-free hours as in the whole of 2016 and 2017 combined.

And while the report’s findings are hugely positive, they also hint at where development is still needed. What else does the performance of this quarter tell us about what we can expect in the power sector – in Great Britain and around the world?

Great Britain is slashing coal generation, the rest of the world needs to catch up

Great Britain has reduced its coal-fired power generation by four-fifths over the last five years. Last quarter the country’s coal fleet ran at just 3% of its 12.9 gigawatt (GW) capacity. Coal capacity is now lower than the capacity of solar PV panels (13.1 GW) installed nationwide, with the most recent decline resulting from Drax’s conversion of a fourth unit from coal to biomass.

When coal generation was running, it primarily provided system balancing services overnight in May and June rather than baseload electricity. However, this positive trend is not seen around the world.

The share of coal in national power systems during 2017

Globally, coal still provides 38% of the world’s electricity – the same amount it did 30 years ago. This comes despite efforts in Europe and North America to move away from coal, and growing investment into renewable generation and technologies.

Overall, Europe’s coal generation dropped from 39% to 22% over the last 30 years, despite some countries – such as Poland and Serbia – still drawing significant generation from the fossil fuel. The US has also reduced its coal generation from 57% to 31% over the past 30 years, as natural gas proves more economical, even in an era of pro-coal policies.

Coal train at rail station in India.

However, in the Middle East and Africa (which draw significant generation from their oil and gas reserves) and South America (where coal accounts for less than 3% of generation), total coal generation is growing. In fact, globally, only seven countries use less coal today than 30 years ago: Germany, Poland, Spain, Ukraine, the US, Great Britain and Canada.

Electric Insights attributes part of this global growth to the continued increase in demand for electricity, particularly in Asia. China, South Korea and Indonesia collectively burn 10 times more coal than they did 30 years ago. India’s coal habit has also increased over the past decade to account for 76% of its electricity generation, while Japan’s usage has grown from 15% to 34% in the same period.

As well as the stresses created by growing demand, this highlights a global disparity in the approach to decarbonising electricity systems, and a need for longer-term, environmentally and socially-conscious market-based initiatives that encourage meaningful movement to lower-carbon electricity sources, such as the UK and Canada’s Powering Past Coal Alliance.

Read the full articles here:

(Lack of) progress in global electricity generation

Britain edges closer to zero coal

Solar farm in South Wales

Decarbonisation is growing, but it’s going to get harder

Great Britain’s decline in coal use has rapidly accelerated its decarbonisation efforts. Annual coal power station emissions have shrunk over the past five years from 129 to 19 million tonnes of CO2 and helped reduce the average carbon intensity of electricity generation to a record low of 195 g/kWh last quarter.

However, this rapid pace of decarbonisation is unlikely to be sustained as growth in renewables faces a plateau, the country’s current nuclear capacity reaches retirement and the target of moving beyond coal by 2025 is completed.

Renewable sources now account for a steady 25% of annual electricity generation. These sources largely came onto the system through policies such as the government’s Renewables Obligation, which is now closed to entrants; Contracts for Differences, the future of which is uncertain for mature technologies like onshore wind and solar; and Feed-in Tariffs for roof-top solar installations which will close in April 2019. The end of these initiative paints a hazy picture of how future renewable capacity will be brought into the system.

Nuclear capacity also looks unlikely to expand at the rate needed to plug gaps in demand, with half of the country’s fleet expected to close for safety reasons by 2025. The Hinkley Point C nuclear power station, meanwhile, is only expected to come online at the end of that year.

Read the full article here:

Has Britain’s power sector decarbonisation stalled?

Ramsgate, Kent during summer 2018 heatwave

Weather will continue to play a major part in renewable generation

If the first quarter of 2018 was defined by low temperatures and heavy snowfall, the second quarter saw the impact of the opposite in weather conditions. From 23 June a heatwave set in around the country that saw temperatures increase by 3.3oC in a week, driving demand to jump 860 MW – the equivalent of an extra 2.5 million households, or an area the size of Scotland.

The increase in demand isn’t as drastic as when cold fronts hit, but if summers continue to get hotter this could change. Today, winter-time demand increases by 750 MW for every degree it drops below 14oC as electric heaters are plugged in to aid largely gas-based central-heating systems. When the mercury rises, however, demand increases by 350 MW for every degree rise over 20oC as businesses turn on air conditioning and the country’s refrigerators work harder.

These heatwave spikes are, at the moment, more easily dealt with than winter storms. While the Beast from the East saw demand reaching a peak of 53.3 GW, June’s topped out at 32.5 GW. The clear skies and long days of June also meant solar PV generation soared, making up for the ‘wind drought’ caused by the high-pressure weather. Wind output floated between 0.3 GW and 4.3 GW in June, far below its quarter peak to 13 GW. However, solar made up for this by peaking past 8 GW for 13 days in June and setting a new record of 9.39 GW at lunchtime on 27 June.

Read the full articles:

How the heat wave affects electricity demand

The summer wind drought and smashing solar

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

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

How the heatwave affects electricity demand

Iain Staffell, Imperial College London

27 July 2018

Opinion

16.5 degrees is the Goldilocks temperature for the Brits – not hot enough for air-con, not too cold to put the heating on. In March we saw how the Beast from the East caused a surge in demand, now the long summer heatwave is doing the same.

June 23rd marked the start of the heatwave, with daytime temperatures surpassing 30°C in Scotland and Wales. The last week of June was 3.3°C warmer than the previous week, and demand was 860 MW higher (see chart below). This rise is equivalent to power demand from an extra 2.5 million households.

This reflects the growing role of air conditioning and refrigeration in shops, and cooling for data centres. Global electricity demand from cooling is rising dramatically, and is seen as a ‘blind spot’ in the global energy system.  This will become more important as global temperatures, and more importantly, global incomes rise. However, it is easier to deal with than cold spells during winter because demand is low and solar PV output is high.

Below 14°C, demand increases by 750 MW for every degree it gets colder as buildings need more heating. Around a tenth of British homes have electric heating, as do half of commercial and public buildings. And while the UK is not synonymous with air conditioners, demand rises by 350 MW for each degree that temperature rises above 20°C.

This effect may well grow stronger in the coming years. National Grid expect that the peak load from air conditioners will triple in the coming decade. Perhaps events such as the current prolonged heatwave may spur more households to invest in air conditioning.

Read the press release

Explore power grid data during the heatwave beginning 23rd June

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

Half year results for the six months ended 30 June 2018

Investors
RNS Number :  5142V
Drax Group PLC
Six months ended 30 JuneH1 2018H1 2017
Key financial performance measures
EBITDA (£ million)(1)102121
Underlying earnings (£ million)(2)79
Underlying earnings per share (pence)(2)1.62.2
Interim dividends (pence per share)5.64.9
Net cash from operating activities (£ million)112197
Net debt (£ million)(3)366372
Statutory accounting measures
Operating profit/(loss) (£ million)12(61)
Loss before tax (£ million)(11)(104)
Reported basic loss per share (pence)(1)(21)

Financial and Operational Highlights

  • H1 EBITDA lower year on year due to two unplanned outages, other areas performing well
  • Statutory loss before tax includes lower level of H1 EBITDA and asset write off
  • Refinancing complete – swapped floating for fixed rate debt with 7.5-year maturity
  • Sustainable and growing dividend
    • Increase in 2018 interim dividend to £22.4 million (5.6 pence per share) (H1 2017: £20 million)
    • Expected 2018 full year dividend of £56 million
    • Ongoing £50 million share buy-back programme – £13 million at 30 June 2018

Good progress with strategic initiatives, on track to deliver long-term objectives

  • Third biomass pellet plant, LaSalle Bioenergy, commissioning ahead of plan – full capacity Q1 2019
  • Conversion of fourth biomass generating unit on schedule and budget, commissioning late summer
  • Programme for long-term reduction in biomass cost including sawmill co-location and rail spur investment
  • Confident in growing requirement for system support services over coming years
  • Development of options for future generation:
    • Coal-to-gas repowering – detailed planning application accepted for review June 2018
    • Four OCGTs(4) – two projects in next capacity market auction, planning applications accepted for review for remaining two projects
  • B2B Energy Supply delivering solid progress to grow number of customer meters

2018 outlook

  • Full year financial expectations unchanged
    • Generation – fourth biomass unit conversion, improved margins, on target availability and capacity payments
    • Continued growth in Pellet Production and B2B Energy Supply
  • Capital Markets Day, 13 November

Will Gardiner, Chief Executive of Drax Group plc, said:

“Drax continues to be at the heart of decarbonising UK energy, securing government support to convert a fourth unit to biomass and piloting a Bioenergy Carbon Capture and Storage project, supporting the UK Government’s carbon capture and storage ambitions.

“Full year EBITDA expectations remain unchanged. However, first half EBITDA was lower, principally due to two specific generation outages. We made excellent progress with our Pellet Production business, driving down costs while producing at record levels and our B2B Energy Supply business continues to increase customer numbers. We also remain on track with our investment projects: the conversion of a fourth unit to biomass, and the development of our OCGT and coal-to-gas repowering options.

“We remain focused on safe and efficient operations and returns to shareholders and expect to declare a full year dividend of £56 million for 2018.”

Group Financial Review

  • Increase to operating profit includes unrealised gains on derivative contracts of £24 million (2017: loss £86 million)
  • Decrease in underlying earnings per share – principally reflects lower EBITDA from biomass generation in H1 2018 vs H1 2017
  • Reported basic earnings per share – a loss of 1.0 pence, which includes write off of coal-specific assets (£27 million) following commencement of fourth biomass unit conversion, largely offset by unrealised gains on derivative contracts (£24 million)
  • Tax – tax credit reflecting benefit of Patent Box claims
  • Capital investment of £46 million, full year investment expectation unchanged at £100–£110 million
    • Core maintenance (£50 million), improvement and optimisation projects (£20-£30 million) and conversion of a fourth biomass unit (£30 million)
  • Net debt of £366 million (31 Dec 2017: £367 million), including cash on hand of £245 million

Operational Review

Pellet Production – Good quality pellets at lowest cost

  • EBITDA up £14 million to £10 million
    • 80% increase in pellet production to 0.7 million tonnes (H1 2017: 0.4 million tonnes)
    • 12% reduction in cost per tonne
  • LaSalle Bioenergy (LaSalle) commissioning complete, full capacity Q1 2019
  • Biomass cost reduction initiatives
    • Co-location and offtake agreement with Hunt Forest Products for low-cost sawmill residues at LaSalle
    • Investment in LaSalle rail spur (£11 million) – reduced transport cost to Baton Rouge port facility

Power Generation – Optimisation of existing assets and decarbonisation projects

  • EBITDA down £49 million to £88 million
    • Rail unloading building outage restricted operation of two ROC(5) units (January 2018)
    • Generator outage on one ROC(5) unit (February 2018)
    • System support and flexibility £36 million (H1 2017: £48 million) – lower due to specific Black Start contract (Q1 2017)
    • Offset by 2016 insurance proceeds and lower carbon cost following decision to convert a fourth unit to biomass
  • Electricity output (net sales) down 17% to 8.9TWh (H1 2017: 10.7TWh)
    • Two unplanned outages on ROC(5) units in Q1 and reduced coal generation
    • High biomass availability in Q2
  • 71% of generation from biomass (H1 2017: 68%)
  • Commenced Bioenergy Carbon Capture and Storage (BECCS) pilot project, £0.4 million cost

B2B Energy Supply – Profitable business with growth in customer meters

  • EBITDA up £4 million to £16 million
    • 9% increase in customer meter points to 387,000 (H1 2017: 356,000)
    • Increase in bad debt reflecting challenging business environment for some customers
  • Strong renewable proposition – 59% of sales renewable
  • Continued investment in next generation IT systems
  • Development of flexibility and system support market

Notes:

  1. EBITDA is defined as earnings before interest, tax, depreciation, amortisation and material one-off items that do not reflect the underlying trading performance of the business.
  2. Underlying earnings exclude unrealised gains on derivative contracts of £24m (H1 2017: unrealised losses of £86m) and material one-off items that do not reflect the underlying performance of the business (finance costs of £7m (2017: £24m), acquisition and restructuring costs of £3m (2017: £6m), write off of coal-specific assets of £27m (H1 2017: £Nil), and the associated tax effect.
  3. Borrowings less cash and cash equivalents.
  4. Open Cycle Gas Turbine.
  5. Renewable Obligation Certificate.

View complete half year report

View analyst presentation

Notice of half year results announcement

17 July 2018

Investors
RNS Number : 9363U
Drax Group PLC

Drax Group plc (“Drax”) confirms that it will be announcing its Half Year Results for the six months ended 30 June 2018 on Tuesday 24 July 2018.

Information regarding the results presentation meeting and webcast is detailed below.

Results presentation meeting and webcast arrangements

Management will host a presentation for analysts and investors at 9:00am (UK Time), Tuesday 24 July 2018, at JP Morgan, 60 Victoria Embankment, London, EC4Y 0JP. 

Would anyone wishing to attend please confirm by e-mailing [email protected] or calling Christopher Laing at FTI Consulting on +44 (0)20 3319 5650. 

The meeting can also be accessed remotely via a live webcast, as detailed below. After the meeting, the webcast will be made available and access details of this recording are also set out below.

A copy of the presentation will be made available from 7:00am (UK time) on Tuesday 24 July 2018 for download at: www.drax.com/uk>>investors>>results-reports-agm>> #investor-relations-presentations or use the link https://www.drax.com/uk/investors/results-reports-agm/#investor-relations-presentations

Event Title:

Drax Group plc: Half Year Results

Event Date:

Tuesday 24 July 2018

Event Time:

9:00am (UK time)

Webcast Live Event Link:

https://cache.merchantcantos.com/webcast/webcaster/4000/7464/16531/105055/Lobby/default.htm

Start Date:

Tuesday 24 July 2018

Delete Date:

Monday 15 July 2019

Archive Link:

https://cache.merchantcantos.com/webcast/webcaster/4000/7464/16531/105055/Lobby/default.htm

For further information please contact Christopher Laing on +44 (0)20 3319 5650.

Website:

www.drax.com/uk

                                                                                                                                    

Balancing for the renewable future

6 July 2018

Power generation

It’s not news to say Great Britain’s electricity system is changing. Low carbon electricity sources are on course to go from 22% of national generation in 2010 to 58% by 2020 as installation of wind and solar systems continue to grow.

But while there has been much change in the sources fuelling electricity generation, the system itself is still adapting to this transformation.

When the national grid was first established in the 1920s, it was designed with coal and big spinning turbines in mind. It meant that just about every megawatt coming onto the system was generated by thermal power plants. As a result, the mechanisms keeping the entire system stable – from the way frequency and voltage is managed to how to start up the country after a mass black out – relied on the same technology. These ‘ancillary services’ – those that stabilise the system – are crucial to maintaining a balanced electricity system.

“Ancillary services are needed to make sure demand is met by generation, and that generation gets from one place to the next with no interruptions,” explains Ian Foy, Head of Ancillary Services at Drax. “Because what’s important is that all demand must be met instantaneously.”

In today’s power system, however, weather dependent technology like offshore wind and home solar panels are increasingly making up the country’s electricity generation. Their intermittency or variability is, in turn, impacting both the stability of the grid and how ancillary services are provided.

Running a large power system with as much as 85% intermittent generation – for example on a very windy, clear, sunny day – is thought to be achievable. It isn’t a scenario anticipated for the large island of Great Britain. But to deal with the fast-pace of change on its power system which recently managed to briefly achieve  47% wind in its fuel mix, there is a need to develop new techniques, technologies and ways of working to change how the country’s grid is balanced.

New storage tech takes on balancing services

One of the technologies that’s expected to provide an increasing amount of balancing services is grid-scale batteries. One stabilisation function offered by batteries (and other electricity storage options) is to provide reserve  at times when demand peaks or troughs. This matches electricity demand and generation.

Combined with their ability to respond quickly to changes in frequency, batteries can be a significant source of frequency response.

Batteries can also absorb and generate reactive power, which can then be deployed to push voltage up or down when it starts to creep too far from the 400kV or 275kV target (depending on the powerlines the electricity is travelling along) needed to safely move electricity around the grid.

The challenge with batteries is that the quantity of megawatt hours (MWh) required to compensate for intermittency is very large. The difference between the peak and trough on any day may be more than 20 GW for several hours (see for yourself at Electric Insights).

The significant price reductions in battery storage apply to technologies with short duration (or low volume MWhs). These are the technologies which have been developed at scale recently but will probably struggle to make up in any large quantity any shortfalls in generation resulting from prolonged periods of low intermittent generation.

A challenge currently being addressed relates to maintenance of battery state of charge. This is a consequence of battery storage having a cycle efficiency of less than 100%. This means that losses from continuous charging and recharging will have to be replenished from the available generation to avoid batteries going empty and being unavailable for grid services.

Ultra-low carbon advances

Rather than relying on batteries to provide ancillary services to support intermittent generation, technical advancements are allowing the wind and solar facilities – which are generating more and more of the country’s electricity – to do so themselves.

The traditional photovoltaic (PV) inverters found on solar arrays were initially designed to push out as much active, or real, power as possible. However, new smart PV inverters are capable of providing or absorbing reactive power when it is needed to help control voltage, as well as continuing to provide active power.

The major advantage of smart inverters is the limited equipment update required to existing solar farms to allow them to offer reactive power control. The challenge here is that PV is embedded in distribution systems and therefore reactive services they provide may not cure all the problems on the transmission system.

Similarly, existing wind installations have traditionally focused on getting the greatest amount of megawatts from the available resources, but with fewer thermal power stations on the grid, ways of balancing the system with wind turbines are also being developed.

Inertia is the force that comes from heavy spinning generators and acts as a damper on the system to limit the rate of change of frequency fluctuations. While wind turbines have massive rotating equipment, they are not connected to the grid in a way that they automatically provide inertia, however, research is exploring what’s known as ‘inertial response emulation’ that may allow wind turbines to offer faster frequency response.

This works through an algorithm that measures grid frequency and controls the power output of a wind turbine or whole farm to compensate for frequency deviations or quickly provide increases or decreases in power on the system. Inertial response emulation cannot be a complete substitute for inertia but can reduce the minimum required inertia on the system.

Even in a future where the majority of the country’s electricity comes from renewable sources, thermal generators may still be able to provide benefits to the system by running in ‘synchronous compensation’ mode i.e. producing or consuming reactive power without real power.

However, what is vitally important for the future of balancing services in Great Britain is a healthy, transparent and investable market for generators, demand side response and storage, whether connected on the transmission or distribution networks.

A market for the future grid

One of the primary needs of balancing service providers is greater transparency into how National Grid procures and pays for services. Currently, National Grid does not pay for inertia. With it becoming more important to grid stability, incentive is needed to encourage generators with the capability to provide it. Those technologies that can’t provide inertia, could be encouraged to research and develop ways they could do so in the future.

Standardising the services needed will help ensure providers deliver balancing products to the same level needed to support the grid. It would also benefit from fixed requirements and timings for such services. Bundling related products, such as reserve and frequency control, and active power and voltage management, will also offer operational and cost efficiencies to the providers.

Driving investment in balancing services for the future, ultimately, requires the availability of longer-term contracts to offer financial certainty for the providers and their investors.

 

Bridge to the future

The energy mix -- table showing services which can be provided by different power technologies

Click to view larger graphic.

For the challenges of decarbonisation to be met in a socially responsible way, Great Britain’s power system must be operated at as low a cost as possible to consumers.

With new technologies, almost anything could be possible. But operating them has to be affordable. In many cases, it may take time for costs of long duration batteries to come down – as it has with the most recent offshore wind projects to take Contracts for Difference (CfDs) and Drax’s Unit 4 coal-to-biomass conversion under the Renewables Obligation (RO) scheme.

Thermal power technologies such as gas that has proven capabilities in ancillary services markets can at least be used in a transitional period over the coming decades until a low carbon solution is developed.

Biomass will continue to be an important source of flexible power. This summer, at Drax, biomass units are helping to balance the system. It is the only low carbon option which can displace the services provided by coal or gas entirely.


Drax Power Station’s control room. Viewing on a computer? Click above and drag. On a phone or tablet – just move your device.

In the past the race to decarbonisation was largely based around building as great a renewable capacity as possible. This approach has succeeded in significantly scaling up carbon-free electricity’s role on Great Britain’s electricity network. However, for the grid to remain stable in the wake of this influx, all parties must adapt to provide the balancing services needed.

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 start, system inertia, frequency response, reactive power 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 Maintaining electricity grid stability during rapid decarbonisation.

Appointment of new non-executive director

20 June 2018

Investors
RNS Number : 9248R
Drax Group PLC
(Symbol: DRX)

The Board of Drax Group plc (“Drax”) is pleased to announce that Vanessa Simms is to be appointed as a Non-Executive Director, with effect from 19 June 2018.

Vanessa is Chief Financial Officer at Grainger plc (1) and has a strong background in listed businesses, with more than 20 years experience working in senior leadership roles at Unite Group plc, SEGRO plc, Stryker Corp and Vodafone Group plc.  She has particular expertise in leading and implementing strategic change.

Philip Cox, Chairman of Drax, said: “The directors are delighted to welcome Vanessa to the Board. Her financial and commercial experience from a broad range of companies and industries will provide real value as Drax delivers on its purpose to help change the way energy is generated, supplied and used for a better future.”

Vanessa added: “I’m looking forward to joining the Board of Drax at this key time for sustainable energy in the UK.”

Vanessa has been appointed as a member of the Company’s Audit Committee.  She will work closely with the current Audit Chair, David Lindsell, in anticipation of her succeeding David when he steps down in 2019.

She has also been appointed as a member of the Company’s Nomination and Remuneration committees.

Enquiries:

Drax Investor Relations: Mark Strafford

+44 (0) 1757 612 491

Media:

Drax Media Relations: Ali Lewis

+44 (0) 1757 612 165

Website: www.drax.com/uk

Notes

  1. Grainger plc is the UK’s largest listed residential landlord.

 

END

Joined at the volts: what role will interconnectors play in Great Britain’s electricity future?

14 June 2018

Power generation

For more than 50 years Great Britain has been electrically connected to Europe. The first under-sea interconnector between British shores and the continent was installed in 1961 and could transmit 160 megawatts (MW) of power. Today there is 4 gigawatts (GW) in interconnector capacity between Great Britain, France, Ireland and the Netherlands – and there’s more on the way.

By the mid-2020s some estimates suggest interconnector capacity will reach 18 GW thanks to new connections with Germany, Denmark and Norway. The government expects imports to account for 22% of electricity supply by 2025, up from 6% in 2017.

This increased connectivity is often held up as a means of securing electricity supply and while this is largely true, it doesn’t tell the full story.

In fact, this plan could risk creating a dependency on imported electricity at a time when flexibility and diversity of power sources are key to meeting demand in an increasingly decentralised, decarbonising system.

Great Britain needs to be connected and have a close relationship with its European neighbours, but this should not come at the expense of its power supply, power price or ongoing decarbonisation efforts. Yet these are all at risk with too great a reliance on interconnection.

To secure a long term, stable power system tomorrow, these issues need to be addressed today.

Unfair advantage

At their simplest, interconnectors are good for the power system. They connect the relatively small British Isles to a significant network of electricity generators and consumers. This is good for both helping secure supply and for broadening the market for domestic power, but the system in which interconnectors operate isn’t working.

Since 2015 interconnectors have had the right to bid against domestic generators in the government’s capacity market auctions.

The government uses these auctions to award contracts to generators that can provide electricity to the grid through existing or proposed facilities. The original intention was also to allow foreign generators to participate. As an interim step, the transmission equipment used to supply foreign generators’ power into the GB market – interconnectors – have been allowed to take part. In practice, interconnectors end up with an economic advantage over other electricity producers.

Firstly, interconnectors are not required to pay to use the national transmission system like domestic generators are. This charge is paid to National Grid to cover the cost of installation and maintenance of the substations, pylons, poles and cables that make up the transmission network. Plus the cost of system support services keeping the grid stable. Interconnectors are exempt from paying these despite the fact imported electricity must be transported and balanced within England, Scotland and Wales in the same way as domestic electricity.

Secondly, interconnectors don’t pay carbon tax in the GB energy market. The Carbon Price Floor is one of the cornerstones of Great Britain’s decarbonisation efforts and has enabled the country’s electricity system to become the seventh least carbon-intense of the world’s most power intensive systems in 2016, up from 20th in 2012.

Interconnectors themselves do not emit carbon dioxide (CO2) in Great Britain, but this does not mean they are emission-free. France’s baseload electricity comes largely from its low-carbon nuclear fleet, but the Netherlands and Ireland are still largely dependent on fossil fuels for power. Because the European grid is so interconnected even countries which don’t yet have a direct link to Great Britain, such as Germany with its high carbon lignite power stations, also contribute to the European grid’s supply. The Neuconnect link is planned to connect Germany and GB in the late 2020s.

Not being subject to the UK’s carbon tax – only to the European Union’s Emissions Trading System (EU ETS) which puts a much lower price on CO2 – imported power can be offered cheaper than domestic, lower-carbon power. This not only puts Great Britain at risk of importing higher carbon electricity in some cases, but also exporting carbon emissions to our neighbours when their power price is higher to that in the GB market..

This prevents domestic generators from winning contracts to add capacity or develop new projects that would secure a longer-term, stable future for Great Britain. In fact, introducing more interconnectivity could in some cases end up leading to supply shortages, be they natural or market induced.

Under peak pressure

The contracts awarded to interconnectors in the capacity market auctions treat purchased electricity as guaranteed. But, any power station can break down – any intermittent renewable can stop generating at short notice. Supply from neighbouring countries is just the same.

Research by Aurora found that historically, interconnectors have often delivered less power than the system operator assumed they would and on occasion exported power at times of peak demand. This happened recently during the Beast of the East, when low temperatures across the continent drove electricity demand soaring.

This European-wide cold spell meant Ireland and France (which has a largely electrified heating system) experienced huge electricity demand spikes, driving power prices up.

As a result, for much of the time between 27 and 28 February Great Britain exported electricity to France to capitalise on its high prices. This not only led to more fossil fuels being burned domestically, but it meant less power was available domestically at a time when our own demand was exceptionally high. Even when the interconnectors do flow in our direction they cannot provide crucial grid services like inertia so our large thermal power stations are often still needed.

It is difficult to say for certain how interconnectors will function during times of high demand in the future due to a lack of long-term data, but that which we do know and have seen suggests they don’t always play to the country’s best interests.

There is still an important role for interconnectors on the Great Britain grid, but to deliver genuine value the system needs to be fairer so they don’t skew the market.

Where interconnectors fit into the future

Interconnectors bring multiple benefits to our power system. They can help with security of supply by bringing in more power at times of systems stress, with the right system in place they can help reduce the need to rely on domestic fossil fuels and enable more renewable installation, and if electricity is being generated cheaper abroad, they can also create opportunities to reduce costs for consumers.

However, the correct framework must be put in place for interconnectors to bring such benefits while allowing for domestic projects that can help secure the country’s electricity supply.

As a start, interconnectors should be reclassified – known as de-rating – to compete with technologies on an equal footing.

Drax’s proposed OCGT plants, which can very quickly start up and provide the grid with the power and balancing services it needs, before switching off again, could offer a more reliable route to grid stability than such overwhelming dependence on interconnectors will. In addition, the coal-to-gas and battery plans at Drax Power Station, would prove to be a highly flexible national asset.

New gas and interconnectors should be able to compete fairly with one another. Policymakers should facilitate a system that allows competing technologies to exist in a cost beneficial way. Both interconnectors and domestic thermal power generators can play their part in creating stability, transitioning towards a decarbonised economy and fitting within the UK’s industrial strategy.

In 1961, when the first interconnector was switched on it marked a new age of continental co-operation. Five decades on we should not forget this goal. In an ever more complex grid, what we need is different technologies, systems and countries working together to achieve a flexible, stable and cleaner power system for everyone.

Keeping the electricity system’s voltage stable

15 May 2018

Power generation
Electricity high voltage sign

In day-to-day life, the electricity system normally plays a consistent, unfluctuating role, powering the same things, in the same way. However, behind the scenes electricity generation is a constant balancing act to keep the grid stable.

Power stations themselves are like living animals, in need of continuous adjustment. Transmission networks need continual maintenance and keeping the whole grid at a frequency of 50 Hz takes careful monitoring and fine-tuning.

One of the other constant challenges for Great Britain’s electricity system is keeping voltage under control.

Keeping the volts in check

Voltage is a way of expressing the potential difference in charge between two points in an electrical field. In more simplistic terms, it acts as the pressure that pushes charged electrons (known as the current) through an electric circuit. 

Great Britain’s National Grid system runs at a voltage of 400 kilovolts (kV) and 275kV (Scotland also uses 132kV). It is then reduced in a series of steps by transformers to levels suitable for supply to customers, for example 11kV for heavy industrial or 230 volts (V) when delivered to homes by regional distribution networks.

UK electricity voltage system

Keeping the voltage steady requires careful management. A deviation as small as 5% above or below can lead to increased wear and tear of equipment – and additional maintenance costs. Or even large-scale blackouts. Power stations such as Drax can control the voltage level through what’s known as reactive power.

“If voltage is high, absorbing reactive power back into the generator reduces it,” says Drax Lead Engineer Gary Preece. “By contrast, generating reactive power increases the voltage.”

Reactive power is made in an electricity generator alongside ‘active power’ (the electricity that powers our lights and devices) and National Grid can request generators such as Drax to either absorb or produce more of it as it’s needed to control voltage.

So how is a generator spinning at 3,000 rpm switched from producing to absorbing reactive power? All it takes is the turn of a tap.

Absorbing reactive power

Taps along a transformer allow a certain portion of the winding – which make up a transformer’s active part with the core – to be selected or unselected. This allows the transformer to alter what’s known as the ‘phase angle’, which refers to the relationship between apparent power (made up of reactive power and active power) and active power. This change in the phase angle regulates the ‘power factor’.

Power factor is measured between 0 and 1. Between 1 and 0 lagging means a generator is producing reactive power and increasing overall voltage, whereas between 1 and 0 leading means it is absorbing reactive power and reducing voltage.

That absorbed reactive power doesn’t just disappear, rather it transfers to heat at the back end of the power station’s generator. “Temperatures can be in excess of 60 degree Celsius,” says Preece. “There’s also a lot of vibration caused by the changes in flux at the end of the generator, this can cause long term damage to the winding.”

As the generators continue to produce active power while absorbing reactive power the conditions begin to reduce efficiency and, if prolonged, begin to damage the machines. Drax’s advantage here is that it operates six turbines, all of which are capable of switching between delivering or absorbing reactive power, or vice versa, in under two minutes.

UK electricity grid

Voltage management in a changing grid

The changing nature of Great Britain’s energy supply means voltage management is trickier than ever. Voltage creeps up when power lines are lightly loaded. The increase of decentralised generation – such as solar panels and small-scale onshore wind farms operating to directly supply specific localities or a number of customers embedded on regional electricity networks –  means this is becoming more common around the grid. This creates a greater demand for the kind of reactive power absorption and voltage management that Drax Power Station carries out.

Grid-scale batteries are being increasingly developed as a means of storing power from weather dependent renewable sources. This power can then be pumped onto the grid when demand is high. In a similar manner, these storage systems can also absorb reactive power when there’s too much on the system and discharge it when it’s needed – bringing the voltage down and up respectively.

Electricity storage

“The trouble is, grid-scale battery storage systems need to be absolutely huge, and a 100 MW facility would be close to the size of football field and double stacked,” explains Preece. “They are also not synchronised to the grid as a thermal turbine generator would be.” Subsequently there is no contribution to inertia.

As Great Britain’s power system continues to evolve, maintaining its stability also needs to adapt. Where once the challenge lay in keeping voltage high and enough reactive power on the grid, today it’s absorbing reactive power and keeping voltage down. It highlights the need for thermal generators that are designed to quickly switch between generating and absorbing to support the wider network.

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 reserve power, system inertia, black start, reactive power and frequency response. 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 and Maintaining electricity grid stability during rapid decarbonisation.