Tag: coal

End of coal generation at Drax Power Station

27 February 2020

Investors
Coal picker, Drax Power Station, 2016

Drax Group plc
(“Drax” or the “Group”; Symbol:DRX)
RNS Number : 2747E

Following a comprehensive review of operations and discussions with National Grid, Ofgem and the UK Government, the Board of Drax has determined to end commercial coal generation at Drax Power Station in 2021 – ahead of the UK’s 2025 deadline.

Commercial coal generation is expected to end in March 2021, with formal closure of the coal units in September 2022 at the end of existing Capacity Market obligations.

Will Gardiner, Drax Group CEO, said:

“Ending the use of coal at Drax is a landmark in our continued efforts to transform the business and become a world-leading carbon negative company by 2030. Drax’s move away from coal began some years ago and I’m proud to say we’re going to finish the job well ahead of the Government’s 2025 deadline.

“By using sustainable biomass we have not only continued generating the secure power millions of homes and businesses rely on, we have also played a significant role in enabling the UK’s power system to decarbonise faster than any other in the world.

“Having pioneered ground-breaking biomass technology, we’re now planning to go further by using bioenergy with carbon capture and storage (BECCS) to achieve our ambition of being carbon negative by 2030, making an even greater contribution to global efforts to tackle the climate crisis.

“Stopping using coal is the right decision for our business, our communities and the environment, but it will have an impact on some of our employees, which will be difficult for them and their families.

“In making the decision to stop using coal and to decarbonise the economy, it’s vital that the impact on people across the North is recognised and steps are taken to ensure that people have the skills needed for the new jobs of the future.”

Coal in front of biomass storage domes at Drax Power Station, 2016

Coal in front of biomass storage domes at Drax Power Station, 2016

Drax will shortly commence a consultation process with employees and trade unions with a view to ending coal operations. Under these proposals, commercial generation from coal will end in March 2021 but the two coal units will remain available to meet Capacity Market obligations until September 2022.

The closure of the two coal units is expected to involve one-off closure costs in the region of £25-35 million in the period to closure and to result in a reduction in operating costs at Drax Power Station of £25-35 million per year once complete. Drax also expects a reduction in jobs of between 200 and 230 from April 2021.

The carrying value of the fixed assets affected by closure was £240 million, in addition to £103 million of inventory at 31 December 2019, which Drax intends to use in the period up to 31 March 2021. The Group expects to treat all closure costs and any asset obsolescence charges as exceptional items in the Group’s financial statements. A further update on these items will be provided in the Group’s interim financial statements for the first half of 2020.

As part of the proposed coal closure programme the Group is implementing a broader review of operations at Drax Power Station. This review aims to support a safe, efficient and lower cost operating model which, alongside a reduction in biomass cost, positions Drax for long-term biomass generation following the end of the current renewable support mechanisms in March 2027.

While previously being an integral part of the Drax Power Station site and offering flexibility to the Group’s trading and operational performance, the long-term economics of coal generation remain challenging and in 2019 represented only three percent of the Group’s electricity production. In January 2020, Drax did not take a Capacity Market agreement for the period beyond September 2022 given the low clearing price.

Enquiries

Drax Investor Relations:
Mark Strafford
+44 (0) 7730 763 949

Media

Drax External Communications:
Ali Lewis
+44 (0) 7712 670 888

 

Website: www.drax.com

END

Capacity Market agreements for existing assets and review of coal generation

31 January 2020

Investors
Drax's Kendoon Power Station, Galloway Hydro Scheme, Scotland

RNS Number : 6536B

T-3 Auction Provisional Results

Drax confirms that it has provisionally secured agreements to provide a total of 2,562MW of capacity (de-rated 2,333MW) from its existing gas, pumped storage and hydro assets(1). The agreements are for the delivery period October 2022 to September 2023, at a price of £6.44/kW(2) and are worth £15 million in that period. These are in addition to existing agreements which extend to September 2022.

Drax did not accept agreements for its two coal units(3) at Drax Power Station or the small Combined Cycle Gas Turbine (CCGT) at Blackburn Mill(4) and will now assess options for these assets, alongside discussions with National Grid, Ofgem and the UK Government.

A new-build CCGT at Damhead Creek and four new-build Open Cycle Gas Turbine projects participated in the auction but exited above the clearing price and did not accept agreements.

T-4 Auction

Drax has prequalified its existing assets(5) and options for the development of new gas generation to participate in the T-4 auction, which takes place in March 2020. The auction covers the delivery period from October 2023.

CCGTs at Drax Power Station

Following confirmation that a Judicial Review will now proceed against the Government, regarding the decision to grant planning approval for new CCGTs at Drax Power Station, Drax does not intend to take a Capacity Market agreement in the forthcoming T-4 auction. This project will not participate in future Capacity Market auctions until the outcome of the Judicial Review is known.

Enquiries:

Drax Investor Relations
Mark Strafford
+44 (0) 7730 763 949

Media:

Drax External Communications
Matt Willey
+44 (0) 0771 137 6087

Photo caption: Drax’s Kendoon Power Station, Galloway Hydro Scheme, Scotland

Website: www.drax.com

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

Iain Staffell, Imperial College London

23 July 2019

Opinion
Drax EI header

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

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

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

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

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

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

Going below 100 grams

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

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

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

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

Going above 50% renewables

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

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

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

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

Heading towards fossil-free electricity

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Can Great Britain keep breaking renewable records?

15 February 2019

Power generation

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

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

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

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

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

The highs and lows of 2018

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

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

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

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

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

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

How the generation mix has changed

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

 

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

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

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

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

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

2019: a year of unpredictability

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

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

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

Sizewell B Nuclear Power Station

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

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

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

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

A price worth paying? Why the Treasury should maintain a higher carbon price

25 October 2018

Power generation

Last week it was Green GB Week, a nationwide campaign supported by the UK government, showcasing the country’s green credentials and progress in transitioning towards a low carbon world. It is therefore timely that ahead of the Autumn Budget, the energy industry should be speaking about measures, such as the Carbon Price Support mechanism, which are within the power of government to help keep Great Britain on track in meeting its decarbonisation goals.

Aurora Energy Research, a leading energy research and analytics firm, has produced fresh analysis that suggests that maintaining a higher carbon price is key to phasing out coal power generation and decarbonising the UK electricity sector in a timely, cost-effective manner. 

Is the carbon price at risk?

In April 2013, HM Treasury introduced the ‘Carbon Price Support’ – a tax paid by coal and gas generators in Great Britain. In part, this was a response to low costs in the European ‘Emissions Trading System’ which requires generators to buy certificates against their emissions. At the time, the UK Government felt that these certificates were too cheap and wanted to impose a higher carbon price to drive a more modern, low-carbon energy mix.

This Carbon Price Support has had a huge impact, particularly on coal. Prior to its introduction, coal represented 50% of power generation but since it has fallen to record lows. 2017 saw the first day without any coal on the power system since the industrial revolution. Records continue to be broken throughout 2018, with coal generation falling to 1% during summer months.

However, 2018 has also seen prices within the Emissions Trading System surge. Prices started this year at €8/tonne and now seem to be steadying at roughly €20/tonne. This has created uncertainty over the future of the UK Carbon Price Support scheme. Many in energy, from power generators to environmental campaign groups are worried that the Treasury might respond to rising European prices by slashing the Carbon Price Support in this year’s Autumn Budget, which could threaten to undo the success the UK has had in decarbonising its energy mix.

The carbon price is needed to keep coal at bay

Aurora has tested the impacts of different trajectories for the carbon price going forward to 2040 and the implications are significant, particularly for coal.

Aurora’s analysis shows that if government maintains the current Carbon Price Support rate of £18/tonne, then at current EU ETS futures levels, coal should come off the GB power system in 2021-22. By contrast, the same analysis suggests that if Chancellor Philip Hammond were to reduce the Carbon Price Support to £7/tonne, then coal power stations would stay on the system until 2025 and increase generation during that time, as illustrated below.

Source: Aurora Energy Research

This would make it difficult for the UK to meet its carbon targets. The UK government has committed to reducing greenhouse gas emissions in line with 5-yearly ‘carbon budgets.’ Cutting the Carbon Price Support rate to £7/tonne would result in 29 million tonnes of additional carbon dioxide (CO2) during the 4th carbon budget period, which runs from 2023-27. This is an increase of almost 20% on total power sector emissions – against a carbon budget that the UK is currently on track to miss.

The cost of the carbon price

A higher carbon price raises electricity prices slightly, but the mechanics of this are complex and the rising price of electricity is somewhat offset by lower subsidy payments to low carbon generators. Comparing a ‘status quo’ scenario to one where the Carbon Price Support falls to £7/tonne raises annual power system costs by £700 million (average over 2021-40), which translates to roughly £9 a year on the average household’s electricity bill.

Source: Aurora Energy Research

Decarbonisation affects not just the future of GB’s power system, but also its international reputation and progress in meeting climate change targets. The Carbon Price Support has helped to make GB’s power system a success story in reducing carbon emissions while keeping costs reasonable.

There are always trade-offs to be made in policy but cutting the carbon price would threaten the progress Great Britain has made in decarbonising its energy mix, making it harder to meet emissions targets.

Download the report: Carbon Pricing Options to Deliver Clean Growth

Aurora’s press release: Clarity on carbon pricing is needed in Autumn Budget – a cut risks a resurgence of coal

Drax Power CEO Andy Koss’ comments on the Aurora report report 

Coal comeback pushes up UK’s carbon emissions

Iain Staffell, Imperial College London

17 September 2018

Opinion
UK coal production

10-year high gas prices1 have prompted a resurgence in coal-fired power across Britain – and with it a 15% increase in carbon emissions from electricity generation.

If coal-fired electricity remains cheaper than gas-fired (as analysts predict), we could see the first year-on-year rise in carbon emissions from Britain’s power sector in six years. This highlights the importance of retaining a strong carbon price if we are to ensure the successful decarbonisation of the power system is not reversed.

After dropping to a historic low of just 0.2 GW during June and July, Britain’s coal power generation doubled in August, and has shot up to 2 GW during the first week of September.  The last time coal output was this high was during the Beast from the East, when temperatures plummeted in March.

With these coal power stations running instead of more efficient gas plants, Britain is producing an extra 1,000 tonnes of carbon dioxide (CO2) every hour.2  Carbon emissions from electricity generation are up 15% as a result.  These coal plants are not running solely because they are needed to meet peak demand, but because gas prices have risen sharply and carbon prices have not kept up, making coal power stations more economic to run than gas-fired ones.

It became cheaper to generate power from coal than from gas (see thick lines, chart below) in late August.  Even though carbon prices now double the cost of generating electricity from coal,3 coal plants are consistently “in the money” at the moment, meaning they can generate power profitably all day and night.

Estimated cost of generating electricity from coal and gas in Quarter 3 (thick lines), and the output from coal power stations in Britain (thin line)

Estimated cost of generating electricity from coal and gas in Quarter 3 (thick lines), and the output from coal power stations in Britain (thin line)

The cost of emitting CO2 has increased sharply, up 45% so far this year due to the ongoing rally in European Emissions Trading Scheme (EU ETS) prices.  Rising carbon prices should make gas more economical to burn as it emits less than half the CO2 of coal.

However, wholesale gas prices have also risen 40% since the start of the year, as supplies and storage are squeezed in the run up to winter.  Gas prices are at a ten-year high, currently 14% above their previous quarterly-average peak back in 2013 (see chart below).  These rising costs are feeding through into wholesale power prices, which have risen by a third over the past year to hit £60/MWh.

The cost of generating electricity and carbon cost

The estimated cost of generating electricity from fossil fuels over the last 20 years, along with the cost of emitting CO2.

Britain’s carbon price strengthened dramatically through 2014–15 due to the government implementing a Carbon Price Support scheme.  This caused gas to become competitive against coal for power generation, leading to carbon emissions from the power sector halving.  Unless Britain’s carbon price can once again make up the gap between coal and gas prices, we risk rolling back some of the world-leading gains made on cleaning up our electricity system.

The Committee on Climate Change has made it clear that power is the only sector that is pulling its weight when it comes to decarbonising the UK.  Clean electricity could power low-carbon vehicles and heating, but this opportunity will be wasted if the electricity comes from high-carbon coal.

UK electricity system

So what can be done?  The sharp rise in gas prices hints at a lack of flexibility in the energy system.  Britain came uncomfortably close to gas shortages in March, in part due to the closure of the country’s largest gas storage site.  With nearly half of the electricity generated in Britain coming from gas, plus five-sixths of household heat, diversifying into other – cleaner – energy sources would help insulate consumers and businesses from price spikes.

No one country has the power to determine international fuel prices.  Several factors have come together to push up gas prices, including a lack of transmission capacity, depleted stores of gas after the long hot summer and a lack of wind power increased output from gas-fired stations. Suppliers which don’t wish to be caught short after the Beast from the East, are also stocking up on gas.

Any knee-jerk reaction to try and lower the cost of electricity (for example, slashing the cost of carbon emissions) may only have a short-term impact, and could easily lead to longer-term damage (such as the resurgence of coal) which would require further interventions in the future.

Britain does have control over its carbon price. Its power stations and industry currently pay the Emissions Trading System price (determined on the Europe-wide market) which has fluctuated wildly over the past week between €25 (£22) and €19 (£17) per tonne, plus £18 per tonne in Carbon Price Support which goes to the Treasury.  This needs to be maintained or strengthened further to save the power system from backsliding, and to show strong climate leadership on the international stage.

Explore this data live on the Electric Insights website

View Drax Power CEO Andy Koss’ comment

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.

[1] The three-month average cost of generating electricity from gas exceeded £60/MWh for the first time since 2009.  Short-term price spikes have been higher than this, such as the first week of March during the Beast from the East.↩

[2] Extra generation from coal reduces the output from gas plants, which are their main competitors, as nuclear, wind and solar already run as much as possible.  Calculation based on 1934 MW of coal generation (the average during the first week of September) emitting 937 gCO2 per kWh (1812 tonnes per hour) instead of gas generation which would have emitted 394 gCO2 per kWh (762 tonnes per hour).↩

[3] The coal that must be burnt to produce 1 MWh of electricity now costs around £31, and the CO2 pollution costs an extra £31 on top.  For comparison, producing 1 MWh of electricity from gas costs £50 for the fuel and £15 for the CO2.↩

How to switch a power station off coal

22 August 2018

Sustainable bioenergy
Turbine hall at Drax Power Station

In 2003, the UK’s biggest coal power station took its first steps away from the fossil fuel which defined electricity generation for more than a century. It was in that year that Drax Power Station began co-firing biomass as a renewable alternative to coal.

It symbolised the beginnings of the power station’s ambitious transformation from fossil-fuel stalwart to the country’s largest single-site renewable electricity generator. This plan presented a massive engineering challenge for Drax, with significant amounts of new knowledge quickly needed.

Fifteen years later, three of its generating units now run entirely on compressed wood pellets, a form of biomass, while coal has been relegated to stepping in only to cover spikes in demand and improve system stability.

Now Drax has converted a fourth unit from coal to biomass. This development represents the passing of a two thirds marker for the power station’s coal-free ambitions and adds 600-plus megawatts (MW) of renewable electricity to Great Britain’s national transmission system.

Building on the past

Drax first converted a coal unit to biomass in 2013, with two more following in 2014 and 2016. This put Drax in an interesting position going into a new conversion: on one hand, it is one of the most experienced generators in the world when it comes to dealing with and upgrading to biomass. On the other, it’s still relatively new to the low carbon fuel compared with its dealings with coal.

Adam Nicholson

“We’ve decades of understanding of how to use coal, but we’ve only been operating with biomass since we started the full conversion trials in 2011,” says Adam Nicholson, Section Head for Process Performance at Drax Power. “We’ve got few running hours under our belts with the new fuel versus the hundreds of man years of coal knowledge and operation all around the country.”

When converting a generating unit, the steam turbine and generator itself remain the same. The difference is all in the material being delivered, stored, crushed and blown into the boiler and burned to heat up water and create steam. And because biomass can be a volatile substance – much more so than coal – this process must be a careful one.

Drax could build on the learnings and equipment it had already developed for biomass such as specially built trains and pulverising mills, but storage proved a bigger issue. The giant biomass domes at Drax that make up the EcoStore are advanced technological structures carefully attuned to storing biomass, but for Unit 4, they were off limits.

Instead Drax engineers had to come up with another solution.

The journey of a pellet through the power station

Normally wood pellets are brought into Drax by train, unloaded and stored in the biomass domes before travelling through the power station to the mills and then boilers. Unit 4, however, sits in the second half of the station – built 12 years after the first. This slight change in location presented a problem.

“There’s no link from the eco store to Unit 4 at all,” explains Nicholson. “You can’t use the storage domes and that whole infrastructure to get anything to Unit 4.”

Drax engineers set about designing a new conveyor system that could connect the domes to the mills and boiler that powers Unit 4. After weeks of design, the team had a theoretical plan to connect the two locations with one problem: it was entirely uneconomical.

Rail unloading building 1 and storage silos

“If we were building a new plant it would be relatively easy, because you could plan properly and wouldn’t have existing equipment in the way,” says Nicholson.

“We had to plan around it and make use of the pre-existing plant.”

Within that pre-existing plant though were vital pieces of equipment, some of which had laid dormant since Drax stopped fuelling its boilers with a mixture of coal and biomass and opted instead for full unit conversions.

Drax began cofiring across all six units in 2003, using two different materials – a mix of around 5% biomass and 95% coal. A direct injection facility was added in 2005. It involved blowing crushed wood pellets into coal fuel lines from two of the power station’s 60 mills.

Then, the amount of renewable power Drax was able to generate roughly doubled in the summer of 2010 when a 400 MW co-firing facility became operational.

Back to the present day, it’s fortunate for the Unit 4 conversion that the co-firing facility includes its own rail unloading building (RUB 1) and storage silos. They are located much closer to the unit than the bigger RUB 2 and the massive biomass domes.

This solved the problem of storage but moving the required volumes of biomass through the plant without significant transport construction still posed a challenge.

Rail unloading building 1 and storage silos for Unit 4 [left], EcoStore biomass domes for units 1-3 [right]

To tackle this the team modified a pneumatic transport system, previously tested during co-firing, to have the capability to blow entire pellets from the storage facilities around the power station at speeds of more than 20 metres per second. The success of this system proved key – it was the final piece necessary to make the conversion of Unit 4 economical.

The post-coal future

Andy Koss

For now, Drax’s fifth and sixth generating unit remain coal-powered, but are called upon less frequently. With Great Britain set to go completely coal-free by 2025, there are plans to convert these too, but as part of a system of combined cycle gas turbines and giant batteries rather than biomass powered units.

It’s an opportunity for Drax to again leverage its pre-existing plant and provide the grid with a fast acting-source of lower-carbon electricity. As with converting to biomass, it will pose a complex new engineering challenge – one that will prepare Drax to meet the future needs of grid as it continues to change and demand greater flexibility from generators.

“The speed at which the Unit 4 project has been delivered is testament to the engineering expertise, skill and ingenuity we continue to see at Drax. We’re nimble and innovative enough to meet future challenges,” says Andy Koss, Chief Executive, Drax Power.

“We may look very different in 10 or 20 years’ time, but the ethos of that innovation and agility is something that will persist.”

Repowering the remaining coal plant with gas and up to 200 MW of batteries will sit alongside research into areas such as carbon capture, use and storage (CCuS) that is all geared towards expanding Drax Power beyond a single site generator into a portfolio of flexible power production facilities.

Unit 4’s conversion is more than just a step beyond halfway for the power station’s decarbonisation, but a significant step towards becoming entirely coal-free.

Find out more about Unit 4.

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.

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.

The companies making coal history

26 June 2018

Power generation

Coal has been the backbone of electricity generation for well over a century – but times have changed. A growing understanding of fossil fuels’ contribution to pollution and global climate change means more energy companies around the world now realise their long-term success depends on moving away from coal. As a result, between 2015 and last year, construction of new coal-powered plants dropped by 73%.

The Powering Past Coal Alliance is an initiative helping facilitate this move. It brings together those working  moving completely away from coal, and is comprised of a number of governments, businesses and energy companies – including Drax. However, it isn’t the only initiative of its type – nor is Drax the only electricity generator fast moving away from coal.

Here we look at some of the other companies giving coal the cold shoulder. 

Avedøre is a high efficiency, multi-fuel combined heat and power plant in Denmark operated by Ørsted. Source: Ørsted

Ørsted

Denmark’s partly state-owned, global energy firm (once called DONG, an acronym for Danish Oil and Natural Gas) is one of the largest of the Alliance’s members leading the charge away from coal. The company is at the forefront of the energy sector’s transformation towards renewables.

It is the global leader in offshore wind, having installed more than one quarter of the world’s total offshore wind capacity.

More recently the company changed its name to Ørsted after the Danish scientist who first discovered that electric currents create magnetic fields.

The name change reflects the company’s move away from fossil fuels, including coal. The company has slashed its coal usage from 6.2 million tonnes in 2006 to 1.1 million last year, and aims to reach zero by 2023, as well as cutting its CO2 emissions by 96%.

This is thanks largely to the massive growth in Ørsted’s offshore wind farm business, as well as the conversion of six of Ørsted’s Danish coal-fired power stations to biomass. The company aims to have enough wind capacity by 2020 to supply 16 million people in Europe.

Xcel Energy

Coal is something of a controversial topic in the US these days. However, forward-thinking electricity generators in the country are quickly moving from contentious fossil fuels to renewables.

Mid-west-based Xcel Energy is laying out a timeline to switch the majority of its generation from coal to carbon-free sources. The company plans to retire 20 of its coal units between 2005 and 2026 – 40% of its total coal capacity – and expand its renewable portfolio in its place.

Xcel’s ambitions are perhaps clearest in Colorado, where it recently announced it will bring forward the closure of about a third of its coal fleet by a decade.

Alongside these coal closures, the company plans to construct 1,131 megawatts (MW) of new wind capacity, 707 MW of new solar power and 275 MW of battery storage in the state. Nationwide, Xcel says it is on course to hit a 50% reduction of its 2005 carbon emissions levels by 2022. 

Enel Generación Chile

Italian electricity giant Enel’s Chilean arm is one of the companies signed up to the Chilean government’s target of generating 70% of its electricity by renewable sources by 2050. In a positive move towards this, the firm recently closed a deal to build 242 MW of new solar, wind and geothermal generation, adding to its already growing roster of renewables.

Last year, Enel Green Power Chile and ENAP opened the Cerro Pabellón geothermal plant in the country’s Atacama Desert. Located 4,500 meters above sea level, it is the first facility of its kind in South America and uses Chile’s volcanic landscape to produce 340 GWh per year.

It comes as a part of Enel’s wider push to become carbon neutral by 2050. Chile’s energy ministry and the electricity power generators’ association have pledged to build no new coal power stations unless they are fitted with carbon capture technology.

Like Drax Group and the UK, companies and countries are quickly moving beyond unabated coal-fired power generation.