Tag: investors

The power system’s super subs

5 February 2018

Power generation

Every day we flick on lights, load dishwashers and boil kettles but few of us pause and think of the stress this can cause for the electricity system. We certainly don’t call National Grid in advance to let them know when we plan to do laundry.

But when any number of the 25.8 million households in Great Britain turn on a washing machine, the grid needs to be ready for it. Fortunately, these spikes in demand are often predictable.

“We are creatures of habit,” says Ian Foy, Drax Head of Ancillary Services.

“We all tend to come home from work at the same time and turn on similar appliances, and this keeps the shape of daily electricity demand much the same.”

National Grid, the operator of Great Britain’s high voltage power transmission system, uses this consistent demand to plan when and how much electricity will be needed for the coming days, and agrees contracts with generators to meet it.

However, there are times when the unexpected can happen – an unseasonable cold spell or a power station breakdown – causing sudden imbalances in supply and demand. To plan for this, the grid carries ‘reserve power’, which is used to fill these short-term gaps.

Delivering this doesn’t just mean keeping additional power stations running to deliver last minute electricity. Instead, it involves a range of services coming from different types of providers, technologies and timescales.

In Great Britain, there are four primary ways this is delivered.

  1. Frequency response

The fastest form of reserve is frequency response. It is an automatic change in either electricity generation or demand in response to the system frequency deviating from the target 50Hz.

Generation and demand must be kept balanced within tight limits, second by second. Failure to do so could lead to the whole system becoming unstable, leading to the risk of blackouts. This is why, every second of the day, National Grid has power generators operating in Frequency Response mode. These power stations effectively connect their steam governor or fuel valves to a frequency signal. If frequency falls, generation increases. If frequency rises, generation is reduced.

An issue which has arisen over the past few years is a reduction in system inertia. The inertial forces in a spinning generator help slow the rate of frequency change, acting like dampers on car suspension. Some small power generation technologies, along with some demand, are sensitive to the rate of change of frequency – too high a rate can cause it to disconnect from the system and this unplanned activity can lead to system instability.

Some forms of generation such as wind and solar along with high voltage, direct current (HVDC) interconnectors between Great Britain and the rest of Europe do not provide inertia. As these electricity sources grow on the system, the system operator must find ways to accommodate them. Reducing the size of the largest credible loss, e.g. reducing interconnector load, buying faster frequency response or running conventional generation out of merit are the usual approaches.

  1. Spinning reserve

The next quickest and most common reserve source, spinning reserve, can jump into action and start delivering electricity in just two minutes. This reserve, both positive and negative, is carried on multiple generating units often running at a part load position (for example, if Drax’s biomass Unit 3 is running at 350 MW of a possible 645 MW). Typical delivery rates are 10 to 20 MW per minute.

This type of reserve responds to unexpected short-term changes in power demand or changes in power generation either in size or timing. For example, during a major TV event or if a generator changes output unexpectedly.

During television ad breaks, the millions of people watching may switch on kettles or flick on lights, sending demand soaring. If a programme or sporting event does not end at the scheduled time, National Grid has to quickly change the generation schedule by sending an electronic dispatch to a generator who responds by quickly ramping up or down.

Thermal power stations such as Drax along with hydro and pumped storage, which can increase or decrease output on demand, are the most common providers of this form of reserve, but  newer technologies such as batteries will also be able to offer the speed required.

  1. Short term operating reserve (STOR)

A slightly slower cousin to spinning reserve, STOR is contracted months in advance by National Grid. It is designed to be available within 20 minutes’ notice.

Around 2 gigawatts (GW) of capacity can provide reserves against exceptionally large losses or demand spikes. STOR capacity tends to be plant which cannot make a living in the energy market because it has a high marginal cost. Traditionally STOR has been supplied by low efficiency aeroderivative turbines or diesel engines but a wider variety of technologies from batteries to demand reduction are increasingly being contracted.

  1. Demand turn up

Managing reserve power isn’t just about finding extra generation to meet demand. Sometimes it’s about quickly addressing too much generation.

High levels of generation coming onto the grid without an equally high demand can overload power lines and networks, causing instability and frequency imbalances, which can lead to blackouts. This might happen in the summer months, when the weather allows for lots of intermittent renewable generation (such as wind and solar), but low levels of demand due to factors like warmer weather and longer daylight hours.

To restore balance, the grid is beginning to ask intensive commercial or industrial electricity users to increase consumption or turn off any of their own generation in favour of grid-provided power. In the case of generating units at Drax Power Station, the response starts less than a second from the initial frequency deviation to help slow the rate of frequency change and minimises large frequency swings.

Reserve in a changing energy system

Planning for the unexpected has long been a staple of the electricity system, but as the shape of that system changes, reserve and response delivery is having to change too.

“Carrying reserve is easier on conventional plants because you know what the plant is capable of generating,” says Foy.

“Wind and solar are subject to the weather, which changes over time. The certainty you get with conventional generation you don’t necessarily get with the intermittency of weather-dependant renewables.”

Add to that the way we use electricity, everything from high efficiency lighting, electric vehicles through to smart appliances and we can see the challenges will grow.

As more variable renewables hits the system, storage technologies will become more important in providing a fast-acting source of short term reserve and response. Smart appliance technology too will play a bigger role in spreading demand across the day and reducing the size of demand peaks and troughs which require rapid changes in generation.

Industry has a role to play too. Some of the biggest users of electricity are expected to play an increasingly important role in support of the system operator. National Grid told members of Parliament in 2016, that ‘it is our ambition to have 30-50% of our balancing capacity supplied by demand side measures by 2020.’

Artist’s impression of a Drax rapid-response gas power station (OCGT) with planning permission

Until these technologies and market mechanisms are widespread and implemented at scale across the grid, however, it will fall to thermal power stations such as biomass, gas turbines such as the planned Progress Power in Suffolk and, on occasion, coal to ensure there is the required reserve power available.

This short story is adapted from 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, and reactive power. View a summary at The great balancing act: what it takes to keep the power grid stable and find out what lies ahead by reading Balancing for the renewable future and Maintaining electricity grid stability during rapid decarbonisation.

The shape of electricity use in 2018

31 January 2018

Power generation

In homes and offices, on streets and in shops, there are more electronic devices than ever. However, for all the phones, washing machines and TVs British consumers are plugging in, our electricity consumption has been on a downward tick – and has been since the middle of the last decade.

At the same time, an increasing percentage of our demand is being met by renewable and low-carbon energy sources. By 2016, greenhouse gas emissions from electricity had dropped to 62% below 1990 levels, helping the UK get close to meeting its third carbon budget target.

It’s the power sector that has seen the biggest reductions through the decline of coal, the greater use of gas and the rise of renewables. There are still big strides to make in the economy as a whole – particularly in sectors such as heat, transport and buildings. But there are positive signs of transformation that could help the country reach its fifth carbon budget goal of lowering emissions by 57% between 1990 and 2030.

Will 2018 prove to be another milestone year for Great Britain’s electricity system? And could the electrification of the economy help other sectors step-up their own decarbonisation?

The efficiency transformation

Reduced demand for electricity comes, in part, as a result of the decline in energy-intensive, manufacturing and heavy industry. However, in the domestic sector the decline has been equally significant. Since 2002, energy consumption in the home has fallen 19% from 52,229 ktoe (Kilotonne of Oil Equivalent) to 42,486 ktoe. As well as electricity, this includes gas, solid fuels such as coal and more.

This drop comes despite a growing population, economic growth, an increase in the number of households and a rising number of consumer devices and appliances. So, what exactly is bringing down energy consumption?

One cause is the increased efficiency of electronics and appliances. The phasing out of incandescent lightbulbs – which had hardly changed since Edison’s day – in favour of energy-saving models such as LEDs has reduced electricity used to light homes by a third since 1997. As well as the improved efficiency of large appliances, like fridge freezers, there is also a greater consumer awareness of electricity saving habits, such as washing clothes at lower temperatures.

The increase in small, battery-powered devices, such as smartphones, tablets and laptops on the other hand, means we’re spending less time using higher-powered equipment that constantly pulls from the grid, such as TVs and hi-fis.

What this can lead to, however, is a change in the shape of electricity demand (the ‘shape’ of power demand can be explored in Electric Insights). For example, overnight when many people choose to charge those battery-powered appliances. Such changes in demand present a challenge to forecasters at in National Grid’s control room, who predict ahead when, where and how much power will be needed from the country’s electricity grid.

Shifting demand spikes

Today’s peak electricity demand times remain relatively unchanged from the 20th century. People still come home and turn on lights, kettles and washing machines at around 5pm and 6pm.

But as artificial intelligence makes its way into more and more home appliances, these spikes are likely to level out across the day. Connected devices will aim to predict peak times and, where such tariffs are provided by energy suppliers, only run when overall demand costs are lower.

At the same time, lifestyles have changed, affecting electricity demand even further. In the past some of the biggest surges in UK electrical history came in the immediate aftermath of big TV moments, when people across the country switched on kettles, opened fridges and went to the toilet.


Now the proliferation of on-demand and online TV has reduced the need for National Grid to keep power stations on standby during major televised moments, as people choose to watch at their leisure rather than when they are broadcast.

Sports, however, remains one of the things that still attracts large numbers of live viewers. This June’s football World Cup means the National Grid will be braced for any surges in post-penalty shootout tea breaks.

Combined with a Royal Wedding – the last of which caused a significant spike – summer 2018 could see a few rare moments when mass TV viewing shunts electricity demand enough for it to be noticeable.

Cleaner power

But while 2018 may see some instances where demand surges, it’s likely power generation will continue to grow cleaner. The Department for Business, Energy and Industrial Strategy (BEIS) has released projections suggesting installed renewable electricity capacity could reach 36 gigawatts (GW) by 2030 – building on a 900% increase between 2007 and 2017.

It is, of course, important we continue to use electricity more efficiently. In 15 years from now, it’s predicted that power generation could begin to rise significantly and so decarbonising the production of power is arguably just as important as saving it.

This year will see another, flexible 600+ megawatt (MW) coal unit converted to sustainable biomass at Drax Power Station in Yorkshire and the first of 84 offshore wind turbines turned on as part of the 588MW Beatrice project in the Outer Moray Firth. These developments will quicken the pace of decarbonisation in Great Britain’s electricity network, meaning that positive trend that will continue.

This is the second story in a series on electricity demand through the ages, the first of which looked at the 1970s.

How do you keep a 1.2 tonne steel ball in prime condition?

18 January 2018

Power generation

There are 600 giant balls at Drax Power Station. Each one weighs 1.2 tonnes – roughly the same as a saloon car – and is designed for one simple, but very specific, purpose: to pulverise.

Every day thousands of tonnes of biomass and coal are delivered to the power station to fuel its generators. But before this fuel can be combusted, it must be ground into a powder in pulverising mills so it burns quicker and more efficiently. It’s the giant balls that do the grinding.

And although these balls may be incredibly durable, the constant smashing, crushing and pulverising they go through on a daily basis can take its toll. Maintaining the 600 balls across the power station’s 60 mills is a vital part of keeping the plant running as effectively as possible.

Surviving the pulveriser

Each of the six generating units at Drax (three biomass and three coal) has up to 10 mills that feed it fuel, all of which operate at extreme conditions. Inside each one, 10 metal balls rotate 37 times a minute at roughly 3 mph, exerting 80 tonnes of pressure, crushing all fuel in its path.

Air is then blasted in at 190 degrees Celsius to dry the crushed fuel and blow it into the boiler at a rate of 40 tonnes per hour. To survive these extremities, the balls must be tough.

Drax works with a local foundry in Scunthorpe, Lincolnshire to manufacture them. First, they are cast as hollow orbs of nickel steel or chrome iron and then smoothed to within one millimetre of being perfectly spherical.

After 8,000 hours of use, engineers check how rapidly they’re wearing down by measuring their thickness using ultrasound equipment and, if deemed to be too thin (which usually occurs after about 50,000 hours of use), replace them.

For this, they must first remove the top of the mill – including the grinding top ring – and then individually lift out and replace each massive ball. Those that are removed are typically shipped back to Scunthorpe to be recycled.

Transforming for a decarbonised future

When Drax Power Station was first built in the 1970s, the mills were designed to only crush coal, but since it was upgraded to run primarily on biomass, in the form of sustainable wood pellets, they have been adapted to work with the new fuel.

For the most part, this requires only minor changes – the primary difference is that coal is harder to fully pulverise. Coal typically does not get entirely ground down in the first cycle, so a classifier is needed in the mill to separate the heavier particles and recirculate them for further grinding.

The process of switching one mill from biomass to coal takes about seven days and nights. This work was carried out on Unit 4’s mills ahead of this winter, following biomass trials in the spring and summer of 2017. Now that the decision has been made to permanently upgrade that fourth power generation unit, converting one of its 10 mills from coal to biomass later in 2018 will take about twice as long.

Using the same essential equipment and process for both fuels helps to quicken the pace of decarbonisation at Drax Power Station as the UK moves to end the production of unabated coal-fired electricity by 2025. Come seven years from now, one thing will remain consistent at the huge site near Selby, North Yorkshire: the giant pulveriser mills will continue their tireless, heavy-duty work.

Fourth biomass unit conversion

17 January 2018

Investors
RNS Number : 1114C
Drax Group PLC

Drax welcomes the UK Government response to the consultation on cost control for further biomass conversions under the Renewable Obligation scheme, which will enable Drax to convert a fourth unit to biomass.

The response proposes that, rather than imposing a cap on ROC(1) support for any future biomass unit conversions, a cap would be applied at the power station level across all ROC(1) units. This would protect existing converted units and limit the amount of incremental ROCs attributable to additional unit conversions to 125,000 per annum.

The response would enable Drax to optimise its power generation from biomass across its three ROC units under the cap, whilst supporting the Government’s objective of controlling costs under the Renewable Obligation scheme.

Drax will now continue its work to deliver the low cost conversion of a fourth biomass unit, accelerating the removal of coal-fired generation from the UK electricity system, whilst supporting security of supply.

Drax plans to complete the work on this unit as part of a major planned outage in the second half of 2018, before returning to service in late 2018. The capital cost is significantly below the level of previous conversions, re-purposing the existing co-firing facility on site to deliver biomass to the unit.

The unit will likely operate with lower availability than the three existing converted units, but the intention is for it to run at periods of higher demand, which are often those of higher carbon intensity, allowing optimisation of ROC(1) generation across three ROC(1) accredited units. The CfD(2) unit remains unaffected.

Will Gardiner, Chief Executive of Drax Group, commented:

“We welcome the Government’s support for further sustainable biomass generation at Drax, which will allow us to accelerate the removal of coal from the electricity system, replacing it with flexible low carbon renewable electricity.”

“We look forward to implementing a cost-effective solution for our fourth biomass unit at Drax.”

Enquiries:

Investor Relations:

Mark Strafford

+44 (0) 1757 612 491

Media:

Ali Lewis

+44 (0) 1757 612 165

 

Website: www.drax.com

Notes

  1. Renewable Obligation Certificate
  2. Contract for Difference

END

 

 

Can electricity power heavy-duty vehicles?

3 January 2018

Electrification

On a blacked-out stage, a blast of white light appears. Smoke floods out, music blares and an excited crowd surges forward, smartphones held aloft. It’s a moment of rapture – but this is not a theatrical or musical performance. This is the launch of an electric car.

Specifically, the launch of Tesla’s new electric roadster – which claims to be the fastest production car ever made. And while the sportscar may have been the undoubted star of the event, it wasn’t the only one unveiled. Tesla also launched an electric-powered articulated lorry – the Semi.

With governments around the world setting ambitious plans to ban the sale of petrol-and-diesel-only cars, the introduction of electric-powered utility vehicles – like Tesla’s truck – in a range of industries will be essential to a truly decarbonised transport system.

Disrupting trucking

Tesla’s heavy goods vehicle (HGV) highlights the growing capabilities of electric vehicles (EVs) to deliver more than just short, urban journeys. It claims its Semi will be able to travel 500 miles on a single charge (enough to get you from London to Edinburgh comfortably) and tow 40 tonnes of cargo.

Tesla isn’t the only player with electric big rig concepts – Los Angeles-based Thor Trucks, Daimler and Volkswagen have unveiled their own – but its ambitious 2019 production target makes it a more immediate possibility than any other in the space.

Despite media coverage claiming the Semi’s mega-charging capability breaks the laws of physics, big business is taking a sunny view of Elon Musk’s latest innovation. Walmart, which has been taking strides to reduce its emissions, has already pre-ordered 15 of the Semis. Delivery firm UPS has used small electric trucks in major cities for some years already – it has placed the largest order so far, for 125.

Electrifying emergency response

In the world of emergency services, quick response is vital. EVs, then, which have fast acceleration and are quick off the mark, are ideal candidates to deliver – especially as battery technology becomes more reliable and durable.

Health services in Nottingham have already been trialling electric-powered fast response vehicles, while in Japan, Nissan has unveiled an all-electric ambulance that carries a lithium-ion auxiliary battery to power medical equipment on board.

This on-board power supply is a further advantage of EVs, and one not just restricted to emergency services. Electric pickup truck maker Havelaar, for example, offers power outlets on its Bison vehicle for electric tools.

The future of battery farming

Out in the countryside, EVs are making waves in farming. John Deere has unveiled plans for fully electric tractors, claiming they require less maintenance and have a longer lifecycle than combustion engines.

With more than a third of UK farms generating their own power from solar, wind and even anaerobic digestion using farm by-products, there’s potential for farmers to charge tractors renewably and cut their fuel and charging costs.

More than just helping cut emissions and costs, there can also be performance benefits. Given their acceleration abilities, electric tractors are well suited to heavy pulling without revving up engines and churning up ground.

Joining HGVs and tractors in their ability to apply almost instant torque to heavy industrial jobs are e-Dumper trucks. The Komatsu quarry truck weighs in at almost 45 tonnes and claims to be the biggest EV in the world.

The economic advantage of electrification

Air pollution and greenhouse gas emissions are the main driving force behind many anti-fossil fuel regulations. However, research suggests decarbonising transport systems also have economic advantages for businesses.

A report by financial services firm Hitachi Capital found that switching vans and heavy goods vehicles (HGVs) to electric or other alternative fuels could save British businesses as much as £14 billion a year.

It claims EVs run at 13p cheaper per mile than diesel-fuelled vans, while HGVs are reported to be 38p cheaper. That adds up to total savings of £13.7 billion a year if all Britain’s commercial vehicles were switched.

The move to a fully electrified transport system is already underway. The number of registered electric cars increased by 280% in the UK over the past four years, according to the Hitachi report. The Chinese city of Shenzhen’s entire fleet of 16,359 buses has gone electric – a transition that began in 2009 and has been assisted by an 80% drop in the cost of a lithium-ion battery pack. According to Bloomberg New Energy Finance, China’s need for electric bus batteries is almost on a par to that of all global EV battery demand. China could be said to be driving the market.

EVs are undoubtedly cleaner when it comes to road-side pollution. However, the exponential increase in EVs will only benefit the fight against man made climate change if countries’ entire energy systems continue to decarbonise. Emissions-free vehicles will need to be powered predominantly by low carbon electricity for a more electric future to be a sustainable one.

Trading update

12 December 2017

Investors
RNS Number: 0238Z
DRAX GROUP PLC
(Symbol: DRX) 

Trading and Operational Performance

Since publishing its half year results on 19 July 2017, trading conditions in the markets in which Drax operates have remained in line with expectations.

Generation

A major planned outage on the CfD(1) unit was completed in November 2017 and the unit has now returned to service. Both biomass and coal operations are currently performing well.

Retail

Retail operations remain in line with expectations, with the integration of Opus Energy progressing well and continued improvement in profitability at Haven Power.

US biomass self-supply

At the Morehouse and Amite pellet plants, the installation of a further 150K tonnes of capacity – allowing access to incrementally cheaper local wood residues – as part of the previously announced plans to optimise operations, is now complete.

The third pellet plant at LaSalle began commissioning in November 2017, with pellets now being produced and an increase in production scheduled through 2018.

Taking these factors into account and based on good operational availability for the remainder of the year, our expectations remain unchanged.

Contracted Power Sales for 2017 and 2018

As at 7 December 2017, the power sales contracted for 2017 and 2018 were as follows:

20172018
Power sales (TWh) comprising:20.116.8
– Fixed price power sales (TWh)20.115.9
at an average achieved price (per MWh)
at £46.9at £44.1
– Gas hedges (TWh)(2)-0.9
at an achieved price (per therm)
-44.4p

Strategy Update

Drax continues to develop options for 1.2GW of new Open Cycle Gas Turbine (OCGT) capacity, providing peaking power and system support services to the grid. The first two projects – Progress Power and Hirwaun Power – will participate in the next capacity market auction in February 2018. Negotiations for engineering and construction contracts are progressing well, with competitive tenders received from a number of providers.

If developed, these projects would be underpinned by a fifteen year, index-linked capacity market contract, extending earnings visibility into the 2030s.

Drax also continues to develop options for its remaining coal assets, including further low cost biomass and coal-to-gas conversions, the latter of which is progressing through a public planning consultation.

Through these options for growth and improved earnings Drax continues its transformation, helping change the way energy is generated, supplied and used for a better future.

Other matters

As part of its core market focus Drax completed the sale of BBE(3) to AMPH(4) in October 2017. Drax retains an equity holding in AMPH(4).

Drax will announce its full year results for the year ending 31 December 2017 on 27 February 2018.

Enquiries

Drax Investor Relations:

Mark Strafford

+44 (0) 1757 612 491

Media

Drax External Communications

Matt Willey

+44 (0) 1757 612 285

Ali Lewis

+44 (0) 1757 612 165

Website: www.drax.com

Notes:

  1. Contract for Difference.
  2. Structured power sales (and equivalents) include forward gas sales, providing additional liquidity for forward sales, highly correlated to the power market and acting as a substitute for forward power sales.
  3. Billington Bioenergy.
  4. Aggregated Micro Power Holdings.

END

Refurbishing a 300-tonne generator core within the heart of a power station

6 December 2017

Power generation
Electricity generator

At the centre of Drax Power Station, in a corner of the cavernous turbine hall, is a white box. The inside of this box is spotlessly clean. Not only are its white walls free of dirt, they are free of even dust. But there is one outlier inside this sterile environment: a 300-tonne chunk of industrial equipment.

This equipment is a generator core – the central component for converting the mechanical energy to electrical power.

Electricity generator core

The core is driven by the steam turbine. Ninety tonnes of generator rotor spinning at 3,000 rpm with just millimetres of clearance from the core produce 660 megawatts (MW) of electricity. That’s enough – 645 MW when exported from Drax into the National Grid – to power a city the size of Sheffield.

The generator is a serious piece of industrial machinery. And despite the pristine conditions, this white box is the site of serious engineering.

A process normally done by large-scale manufacturers in dedicated factories, ‘rewinding’ a generator core – as the process is called – is a major operation.

No other UK facility is capable of doing this complex job. So it’s here, in a white box, in the middle of an operational power station in North Yorkshire, that a team of engineers is undertaking work that will secure the generator’s use for decades. This is the Drax rewinding facility.

Turbine structure

How a generator works

A generator consists of two main components, a spinning rotor and a stationary stator. The rotor, which is directly connected to the main turbine and spins 50 times every second, sits inside the stator. Both the stator and the rotor contain a large number of copper coils known as windings. These windings are what carry the electrical current.

The rotor acts like a very strong electromagnet, which, when a voltage is applied, produces a strong magnetic field. Because the rotor sits inside the stator, this magnetic field intersects the copper windings of the stator and induces a voltage in these windings, allowing current to flow.  This voltage is then brought out of the stator and passed through a step-up transformer, where it is increased to a level suitable for transmission through the National Grid.

The stator core is made from many elements with hundreds of thousands of laminations, 84 water-cooled insulated copper bars, each 11 metres long and weighing 200kg forming the windings, various insulating materials, blocks, packing, wedges and condition monitoring equipment.

Generator stators can operate for decades without fault.

DIY at Drax

In 2016, a team of engineers at Drax embarked on a project to construct a facility to rewind the stator on site. This required cross-company collaborative working to design and construct this huge purpose built facility.

Contamination can cause operational problems, so the team built a sterile, white room within the turbine hall – one of just two places within the power station with foundations strong enough to support the incredible 450 tonnes required for the rewind facility. Designed to hold the stator core and the conductor bars, air is forced out of the room to limit the possibility of contamination to the core during the rewind.

“When the unit is in service it becomes magnetic, so any metallic particles left in the space will be attracted to the core,” explains Drax electrical engineer Thomas Walker. “Once magnetised, any metal particles could be drawn in, burrowing into the insulation and core lamination.”

This is the kind of event that an electricity generator wants to avoid – but when it happens, be prepared to fix it.

Roll with it

When Drax’s stators were manufactured in the 1980s, completing their construction relied on manual handling techniques. Modern day facilities, however, rotate the core to minimise human contact.

It took just six months for a partnership involving Drax, Siemens and ENSER to manufacture what could be the largest stator rollers in the world and within that time, ship them from the US to North Yorkshire.

With the rollers installed, the next step was to move in the core. Two of the turbine hall’s cranes, each capable of lifting 150 tonnes, were combined to lift it, hoisting the core onto the mechanical ‘roller’ within the rewind facility.

Once in place, the roller rotates the core, allowing for the copper conductor bars to be safely removed and inserted. Despite this mechanical help, the removing and replacing of each one is still at its heart a human job.

“We still need 10 men to physically move the conductor bars with lifting aids, which makes it not an easy process,” says Walker. Using this method, the bars weighing 200kg each can be safely and precisely fitted into the core.

Electricity turbine generator at Drax

Opting for in-house

Rewinding a stator is a complex process. However, when the time, logistics and costs of shipping the core to Siemens – the German-based manufacturers – was factored in, the decision to do the work at Drax Power Station was an easy one.

“A 300-tonne core is not easy to transport and the Highways Agency do not like things like that on the roads. They’d want us to use waterways” says Drax lead engineer Mark Rowbottom. “Logistically it just wasn’t worth it. It’s too much money to move and ship that weight to Germany. So, we looked at what we could do onsite.”

More than just an economical and logistical decision and with the UK’s diminishing manufacturing facilities, Drax is now equipped to support generator rewinds for many years to come. Building and operating the rewind facility was a project that leveraged the engineering abilities of Drax employees. They are increasingly doing engineering traditionally outsourced to equipment manufacturers.

“The experience we have gained and the close working relationship we have established with Siemens enables us to support the generator for the remaining life of the station,” says Rowbottom.

“To see the core in that many pieces and stripped down to this level is very rare,” says Walker, who began working at the plant as an apprentice. Of the 84 conductor bars, half have been fitted, and the team is scheduled to complete the stator rewind in early 2018. “I never thought I’d do anything like this but am proud to say that I’ve done it.”

What will happen to the carbon price after 2020?

21 November 2017

Power generation

Great Britain’s electricity is cleaner than ever. As wind, solar, biomass and hydro continue to make up more and more of our energy mix, the power system edges ever closer to being entirely decarbonised. The GB power system has leapt up the big economies’ low carbon league table from 20th in 2012 to seventh in 2016.

But this shift to lower-carbon power isn’t owed only to growing renewable electricity capacity. A fall in gas prices has helped and importantly, government policy has ensured coal power generation has become increasingly uneconomical vs electricity produced with gas (gas and coal compete for contracts to supply power to the National Grid).

Introduced in 2013, Great Britain’s Carbon Price Floor sets the minimum price on carbon emissions. A stricter policy than the EU’s volatile EU Emissions Trading System (EU ETS) which puts a much lower price on carbon dioxide (CO2) emissions, the Carbon Price Support as the British policy is also known tops up the EU ETS. Together, they have had a significant impact. According to Aurora Energy Research, the Carbon Price Floor is a major factor in coal generation emissions falling.

In Great Britain, the Carbon Price Floor (CPF) is currently capped at £18 per tonne of CO2 and the EU ETS sits at around £5 t/CO2 – meaning power generators and heavy industry pay around £23 t/CO2 altogether. When initially formulated by the coalition government in 2010, it was intended the CPF would reach £30 per tonne by 2020 and £70 per tonne by 2030. However, the EU ETS has since fallen therefore the UK government chose to cap the carbon price support at £18 per tonne until 2020.

Now, as we reach the end of the decade, questions remain as to what will happen to this crucial mechanism post-2020. Will the government price coal off the system once and for all or will the fossil fuel make an unlikely comeback?

Four visions of carbon pricing’s future

In its research, Aurora has identified four potential future scenarios for the UK’s carbon pricing strategy.

Status Quo: If the UK chooses to continue supporting the phase-out of coal and promotes low-carbon investment, the Carbon Price Floor will steadily increase post-2020, reaching an estimated £52 per tonne by 2040. In this scenario the UK’s carbon pricing structure remains about £18 per tonne higher than the EU ETS which is currently around £5 per tonne.

Catch-up: In the post-Brexit landscape (whatever it may look like) the UK may choose to seek parity with the EU over decarbonisation. In this scenario, the total UK carbon price remains flat with EU ETS, which rises until convergence. In this scenario the UK and EU’s price per tonne of carbon reaches £35 by 2040.

Low Priced Carbon: In the event that the UK government removes the carbon price from 2021 and the EU ETS never recovers beyond its 2017 level, the short-term effects could be a drop in the price of coal power and cheaper energy bills. CO2 emissions increase in the UK as demand for power rises in the late 2020s and beyond (as recently witnessed in the Netherlands where coal generation has increased, in part, due to a low EU ETS). The expected price per tonne of carbon could be as low as £6 by 2040 and investment in lower carbon and renewable forms of power generation stalls.

High Priced Carbon: In order to meet the UK’s fourth and fifth carbon budgets set by the Committee on Climate Change, this scenario sees the electricity system decarbonise more quickly, with coal removed as an energy source. The carbon price rises dramatically over the next two decades to hit £153 per tonne by 2040.

Stopping the coal comeback

Of these four scenarios, the steadily increasing prices of the Status Quo scenario could see the UK meet its power sector target within the fourth carbon budget of 100 g CO2-eq/kWh  – achieving a 51% reduction from 1990 emission levels by 2030. But Aurora found that keeping things as they are could see a radical swing the other way, some years earlier in its scenario: coal could make a comeback in the early 2020s.

In July this year, coal accounted for just 2% of electricity generation in Great Britain and in 2016 as a whole it accounted for 9%, producing the lowest amount of electricity since the start of World War II. Without solid growth of the Carbon Price Floor it could become a much more competitive fuel. This potential is further increased by a predicted rise in natural gas prices post-2020, when the current surplus of liquefied natural gas (LNG) is set to end.

If the government chooses not to set tough prices on carbon emissions, Aurora predicts that on average coal will account for 9% of electricity generation between 2021 and 2025 – a change in the declining coal power trend seen in recent years. A Low Carbon Price future would see coal grow to almost 12% of the total electricity generation mix during the same period.

By contrast, in the High Carbon Price scenario, coal is almost completely driven out of the energy system, accounting for an estimated 2% of electricity generation between 2021 and 2025.

Signalling to the future

What is crucial for British power generators at this stage is clarity beyond 2020, when the £18 per tonne cap ends. This can allow the industry to react to future carbon pricing and prepare for whatever future scenario the government is most likely to adopt.

If the government chooses to continue decarbonising the energy system in a significant way – as it should do – coal facilities can be converted to renewable or lower-carbon units, such as biomass or gas. New interconnectors, renewable sources, storage facilities and demand-side response will also need to be installed at a greater capacity to meet the energy system’s demands.

As the amount of low carbon generation continues to grow, it will increasingly be the marginal generator. This means that power stations such as Drax’s biomass units, which run with an 87% lower carbon footprint compared to coal across their entire supply chain, could be used to meet the last megawatt hour (MWh) of demand – and this would see the carbon price having a diminishing impact on the wholesale price of power.

As has already been shown, the Carbon Price Floor is one of the most effective ways to reduce Great Britain’s electricity emissions. But to continue this impressive progress, the government needs to use it appropriately to set a path towards a decarbonised future.

In October, Drax joined British energy company SSE, climate NGO Sandbag and others to write to Chancellor Philip Hammond, calling on him to back the Carbon Price Floor beyond 2020 and in doing so, provide certainty for businesses investing in lower carbon and renewable capacity. Read the letter here. 

What happened to Great Britain’s electricity over summer 2017

15 November 2017

Power generation

What a difference four years can make. Back in 2012 the carbon intensity of Great Britain’s electricity production was almost 600g per kWh (kilowatt hour). Jump forward to 2016 and this has halved to make Britain one of the least carbon-intense power systems in the world.

This good news comes from Electric Insights, a quarterly research paper on Britain’s power system, commissioned by Drax and written by Imperial College London academics. The latest report’s key finding is just how much Britain’s energy system has decarbonised compared to other nations.

Here is what the data from Q3 2017 tell us about Great Britain’s energy system today and how it will continue to change into the future.

 Climbing the low carbon league tables

Comparing the electricity mix and carbon intensity of nations producing more than 100 TWh (terawatt hours) a year, the report has established a ‘league table’ that tracks the progress (or regress) of countries’ efforts. It shows Britain’s energy system has decarbonised at a greater pace than any other nation.

In 2012 Britain was ranked 20th, sitting mid-table alongside Italy and Saudi Arabia. But in the four years following, Britain rocketed up to become the seventh least-carbon intense energy system in the world in 2016.

The 47% drop in carbon intensity is the biggest change of any of the countries analysed, and puts Britain just behind Norway and Sweden, which have the resources to support substantial hydropower generation, as well as nuclear-dependent France.

The most any other country moved was eight places – in the opposite direction to Britain. This was the Netherlands where new coal power stations were built at a time when use of coal across England, Scotland and Wales combined reduced by around 80%. The additional coal capacity and power generated from that fuel in the Netherlands led to a dramatic increase in carbon emissions.

A major force in helping drive Britain’s rapid move away from coal is the Carbon Price Floor. This currently sits at £18 per tonne of carbon dioxide (CO2) emitted, on top of just £5 per tonne in the rest of Europe.

Read the full analysis at The low carbon electricity league table and view full chart here.

Importing problems?

Imports are making up an increasing amount of the UK’s electricity mix, and in July and August they reached an all-time high of 9%. The majority (60%) of these imports in Q3 2017 came from France, while 30% was from the Netherlands and 10% from Ireland.

However, while importing electricity from overseas has become crucial in helping meeting demand and maintaining a flexible grid, questions remain around the practice’s carbon intensity.

France generates much of its electricity from low-carbon nuclear sources, however, Irish and Dutch exports rely heavily on fossil fuels. As a result, the electricity Britain imported had a 30% higher carbon intensity than that generated domestically – 314 vs 245 g/kWh over the last 12 months.

Over the next five years 7 GW (gigawatts) of new interconnectors are planned for construction (including with France, Norway and Denmark), which could increase electricity imports to provide as much as 10-24% of the country’s electricity. As these continue to play a bigger role in our electricity mix, it is important we ensure it comes from lower-carbon sources where possible and supports the continuing decarbonisation of electricity rather than ‘exporting emissions’.

Read two articles on the topic of interconnectors in Electric Insights:

Coal firmly relegated to the bench

The nose-dive of coal generation in Britain since 2012 highlights just how out-of-favour the carbon-intensive fossil fuel has become in the energy system. Now it occupies a role solely as a backup to low-carbon and renewable sources.

Over the summer months coal generation stayed at a historic low of 1.9% of total electricity generation. Between April and August Britain’s 14 GW of installed coal stations only produced 0.6 GW in an average hour. This follows a year of milestones in the decline of coal, most notably in April, when Britain saw its first day without burning any coal since 1882.

But this is not to say it has disappeared completely. As temperatures dropped in late summer, coal was called upon to meet sudden demand. On September 19th 40% of the coal fleet was called upon to produce 5.7 GW on average across that day, showing that even as coal capacity plummets – dropping from 28 GW in 2012 to 14 GW in 2016 – it still plays a necessary role in helping meet peaks in demand.

What’s clear, however, is that this role is only growing smaller and smaller as our power system continues to decarbonise and flexible energy technologies replace it.

Read the full article here: Coal output bottoms out

Explore the data in detail by visiting ElectricInsights.co.uk

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.