Insights into EV Charging, Vehicle to Grid and Time of Use Tariffs

INTERVIEW: Doug Stewart, Green Energy UK

Doug Stewart Green Energy UK photoJanet Wood talks to Doug Stewart about false starts on time of use tariffs, real-world trials on vehicle to grid, the fallout from Covid and why Ofgem’s plan to give customers back their credit balances is not about managing seasonality 


In 2017, when I interviewed Doug Stewart, chief executive of supplier Green Energy UK (GEUK), it was because the company was about to start offering a time of use (ToU) tariff. Now he says that was “a bit of purest optimism”.

My question then was about the industry ‘back-end’ -  how the company would manage ToU tariffs with customers settled not by the half hourly market periods used in the wholesale market but on an assumed profile of use that would not reflect reality (for a full explanation of this issue see here). But Stewart’s ToU problem was  much simpler: lack of smart meters.

He says, “We genuinely thought that the DCC would be operational by March 2017, because that was what we were being told. Rather unfortunately, the DCC was not ready then, meters were not widely available, second generation meters were still waiting to be defined, first generation meters had operability problems. The whole smart metering piece was an issue for us.”

He says he thought it was “the future that we had all been looking for,” with the start of smart consumers managing their consumption and “also a bit of demand side management”. But with a lack of meters and, he admits, a poor choice of installer partner (now out of business), the GEUK’s reputation began to suffer. “We were constantly fighting off cancelled appointments, meters that didn’t work, all of which is an outsourced activity but it reflected on us”. He says compensation payments (automatic for issues such as missed appointments) were “significant”, but he didn’t want to use the contract with licensed meter operatives as an excuse. “The supplier hub principle says we are responsible and we accept that responsibility.” But the company closed the tariff to new users and did not reintroduce it until now.

He says there was no shortage of potential users of the tariff – too many for the meter installer – and since most of them were EV users, the burgeoning EV market will raise interest now.

"if you cannot connect a smart meter to a mobile signal it isn’t very smart. There are lots and lots of meters where we just can’t get them to connect"

He says the relaunch is much smoother. “The biggest issue now is the [comms] network – if you cannot connect a smart meter to a mobile signal it isn’t very smart. There are lots and lots of meters where we just can’t get them to connect.”

‘Vehicle to grid’ on trial

The relaunch means Green Energy UK has been able to become one of four supplier partners in a ‘vehicle to grid’ trial spearheaded by WPD. Stewart says, “We have been promised V2G for a long time, and certain energy companies have been suggesting that it is here already, but it very much isn’t.”

“We have been promised V2G for a long time, and certain energy companies have been suggesting that it is here already, but it very much isn’t.”

He says the supplier choice aspect for the domestic participants is one attraction of the project because “it is a lot more like a real world trial”. Another attraction was participant Electric Nation, which did “ a fantastic piece of research a few years ago with two million charging hours to find out what people’s habits are”.

Stewart talks about the V2G potential in comparison with people’s petrol habits, often filling up when they get to the quarter-full level. But he says, “Most electric drivers go home, leave with a full charge every day and drive around with 75% charge because they never drive more than 25% of the capability of the battery, then go home and plug it back in again”. Habits should change he says, but also “peoples’ ability to store energy in their battery – that’s wasted”. He says we need more data and smarter use. “Do I need to charge my car for 200 miles to go 15 miles to work each day? Maybe I could charge it less or I could run my house on it during the day or the weekend. But data and analytics and computer power and all of the Internet of Things – all those things help us make better use of energy and will continue to improve our ability to smooth out peaks and troughs, which has to be good news. But we have to have the data, we have to have the car talking to the network.”

In this trial, “we have one view of it and the other three partners will have another  views and that is far more real-world than one energy supplier dealing with one trial.”

Who is entering the industry? 

A lot of what we are discussing relates closely to digital innovation in the energy industry. I ask about the best way to bring in more innovation in this space. Stewart says “I think we will partner with a whole lot  of specialists. Take the app approach to billing or managing demand: most people won’t have their own app developer.” He says “Our app has GEUK all over it and our tone of voice, but we partnered with someone else to do it.

“I think it will be about who your partners are and who you select. The market is going to be populated by a lot of different skills and a lot of diverse businesses.”

“The thing that differentiates us  from, say, the telecoms industry is that the system has to balance.”

He adds, “I think the supplier hub will remain for a considerable period of time … because the thing that differentiates us  from, say, the telecoms industry is that the system has to balance. If you overload the telephone system you can’t get a line but if you overload the electricity system the lights go out.”

Covid lessons

That brings us to the experience of the last year when demand and supply was dramatically affected by a huge reduction in business demand. I note that suppliers’ ability to forecast demand – something that is needed for settlements within the industry, at least until they are trued up on real readings up to 18monts later -  was among the issues that had to be managed.

Stewart says, “If I am honest about our own approach we hoped for the best, planned for the worst, and got something in between. We didn’t’ know how many of  our business customers would close and go home and never open again– and we still don’t. That is still an unknown for the industry. We didn’t know the level at which [domestic] consumption would go up because of Covid requirements working from home.”

Since the company  “we couldn’t really put a handle on how many of our business consumers were not going to consume anything, we got in touch with them all and asked whether they were open. If they weren’t we decided there was no point in sending a bill for electricity they were not going to consume.” Instead, they were  billed for standing charges and a small amount of baseload.

“If we had a business-only electricity business it would have been very difficult because the revenues fell off a cliff,  but they increased at a domestic level”

He adds, “If we had a business-only electricity business it would have been very difficult because the revenues fell off a cliff,  but they increased at a domestic level and the chancellor stepped in with the furlough scheme, which allowed people to pay their bills.

“If people hadn’t been paid to stay at home there wouldn’t have been any aggregate demand and people wouldn’t have been able to meet the costs of household bills. When we first went in there was anecdotal evidence that 50% of the population were one month away from bankruptcy.”

But as it stands, “We have not seen a significant downturn in people not paying their bills.

“We were asked by BEIS and Ofgem to be flexible and we have been, but  we see that as a credit issue not a loss issue. These people will pay their bills when they can afford to and we will allow them credit terms in order to pay them.

“But that is business as usual, because when people get into trouble with their bills we have to help them get out of that and we do that as a matter of course.”

Ofgem’s action on credit balances

We are speaking shortly after Ofgem announced plans to reduce suppliers’ credit balances. Stewart is keen to say  that those proposals will not affect consumers who ‘smooth’ their payments over the year.

“This isn’t about seasonality,” he says, “The reason £1.4B of debt is sitting on the balance sheet of suppliers is because they operate a money up-front payment system.”

He is referring to suppliers who ask their customers to pay in advance, “and they run their risk capital and their working capital off consumer deposits”.

He thinks consumers would not accept paying  a £100 deposit and £100 in upfront payments in other sectors, noting that his company (and the large legacy suppliers) bill in arrears. But he says since the measure is not being introduced until 2022, the other companies “have plenty of time to get their houses in order – they just have to find other lines of credit.  I am quite sure they are capable of doing that.”

A Plan(t) for the Future

A modern-day fairy tale for waste management technologies: how a WtE plant is involved in the life of its community.


A cosy living room, a small garden covered in snow, and plenty of time to spend with your loved ones sipping a cup of coffee. Or else an afternoon bike ride ending with a picnic at a park, while watching the sun go down surrounded by friends. Whatever you prefer – at home or out and about through the city – this is hygge: the Danish word that describes the feeling of happiness one can get thanks to the atmosphere and environment surrounding them, anywhere, anytime, and with anyone.

And speaking of unexpected places where hygge can happen, the city of Copenhagen hosts one of them: CopenHill, an atypical construction in the middle of the city, noticeable even by the most distracted pedestrian in the streets, and featuring some original characteristics.

A peculiar escape for city people

CopenHill (also known as Amager Bakke) was put in operation in 2017, redesigning the skyline of the city of Copenhagen.

Replacing the former 50-year old municipal waste management plant, it manages the non-recyclable waste of approximately 645,000 people and about 68,000 companies from Copenhagen and 4 other surrounding municipalities. In return, it provides electricity to 80.000 households and district heating to 90,000 apartments. But while its concrete heart is treating waste to supply the city, a lot more happens in the building.

As the name suggests, the plant looks like a small mountain in the otherwise flat Copenhagen landscape, standing out in the city’s background with its over 100m of height. But it is not only the looks; CopenHill resembles a mountain in other ways too, with features one would expect to find more in a village in the Alps rather than in an urbanised capital.

Indeed, it is possible to find a winter wonderland on Amager Bakke’s rooftop: a skiing dry slope was built on the top of the plant. This unusual leisure option for a city is very much appreciated by Copenhagen inhabitants and tourists alike – some of which even buy a year-long pass, taking advantage of the fact that skiing is possible in all seasons, with or without snow.

Just like in a real mountain, CopenHill also provides options for summer activities: the entire rooftop is covered with trees and plants that one could find on a mountain, in particular vegetation that is native to 100m of altitude – which creates an interesting surrounding for a hike. And for those who dare, one more surprise: CopenHill indeed hosts the tallest climbing wall of the world, with 80m of height. So either you are a skier, a hiker, or a climber in Copenhagen, be sure you can have your hilly escape just a metro or bus ride away.

CopenHill has managed to make something unique happen: offering activities that would otherwise not be possible in the city, setting the scene for sociable and fun hygge moments for its visitors while at the same moment treating its non-recyclable waste.

Is this what the future looks like? CopenHill and its holistic approach to decarbonisation

Copenhagen aims to become the first carbon-neutral city by 2025. An ambitious, daring challenge for the Danish capital, which is already a frontrunner in the global race for urban sustainability. CopenHill is, was, and will remain part of this journey towards carbon neutrality: by following strict standards and monitoring its operations, the plant complies with all the environmental requirements needed to be placed in an inhabited urban centre.

The plant manages the non-recyclable waste produced by households and industries around Copenhagen, contributing to the circular economy by offering an alternative to landfilling. When processing its hourly 25-35 tonnes of waste, the plant’s output can reach a production of up to 63MWh of electricity and 247MWh of district heating. In comparison to the former WtE plant Amager Forbrænding which Amager Bakke replaced, Amager Bakke cuts 100,000 tonnes of CO2 emissions a year.

What may come as a surprise: that other benefits come along too. Copenhagen is the second-best city in Europe in terms of air quality, and the plant makes sure to respect such a score with all the flue gas leaving the chimneys going through a state-of-the-art filtering process. The plant also plays a major role in material recovery, allowing the city of Copenhagen to recover up to 90% of the metals found in the treated waste.

But CopenHill aims to go one step further: if the right regulatory framework and funding scheme is set up by the Danish Parliament, by 2025 it will be ready to integrate Carbon Capture and Storage/Utilisation in its operations. Thanks to such technology, CopenHill will be able to actively collect nearly the totality of its CO2 emissions – between 90 and 95%- and eg. store them in phased-out oil fields. That is equivalent to 500,000 tonnes of CO2. In the long run, it will also be possible to use the captured CO2 for other purposes such as PtX (production of synthetic fuels). The project complies with the objectives of the SET-Plan and is tailored to cost-effectiveness, making the price of every CO2 tonne stored lower than the socio-economic price of a tonne emitted.

Denmark scores first place on the Environmental Performance Index, which ranks national economies according to their efforts on implementing sustainable policies. The case of CopenHill embodies the proactive attitude of the country towards sustainability, where multiple issues are tackled at once making the most of what is available. And looking at the bigger picture, Denmark’s Waste-to-Energy will also contribute to the European strategy to reduce dependency on fossil fuels by 2025 – complying with the Green Deal requirements.

Source: ESWET

Development of CCS in Fortum Oslo Varme

The EU’s 27 members will need to find a way to deal with 142 million tonnes of residual waste by 2035. That’s assuming they hit their own targets under the bloc’s Circular Economy Action Plan. 

For now, the UK is still signed up to that target as part of the Brexit deal struck last December. 

At the moment, there is enough waste-to-energy capacity in the EU to deal with 100 million tonnes of residual waste, material that can’t be recycled or reused. So the EU will need to increase incineration capacity to cope with an additional 40mt by the 2035 deadline. That means EU countries will need to build more waste-to-energy plants over the next ten years. 

At the same time, the UK is aiming to reduce its carbon emissions by 68% by 2030 (the EU’s goal is a reduction of 55%) and net zero emissions by 2050. 

Fortum Oslo Varme offers a way to achieve these two ambitious goals. We are ready to fit our waste-to-energy plant on the outskirts of Oslo with technology that would capture 90% of the CO2 emissions from the plant. Once the project is running, about 400,000 tonnes of liquefied CO2 will be taken by zero emission trucks to the harbour. From there the CO2 will be taken over by the Northern Lights project and transported by ship to a terminal on the west coast of Norway. There it will be pumped into rock formations 3,000 meters below the seabed in the North Sea for safe storage.   

Our Oslo waste-to-energy plant has been operating for over thirty years and annually deals with 400,000 tonnes of residual waste from Oslo, the surrounding area and the UK. The energy generated by the plant is used to produce electricity and district heating for around 200,000 people in the city. 

Equipping the plant with CCS capacity will cut Oslo’s CO2 emissions by 14% by itself. The project is essential for the city’s plans to cut emissions by 95% by 2030.  

The Norwegian state has already pledged funding for the transport and storage of the carbon and has agreed to pay around half of the project’s start-up and running costs for 10 years. Fortum Oslo Varme has applied to the EU’s Innovation Fund for energy and decarbonisation solutions for the remaining funding. 

At Fortum Oslo Varme, we believe that this project is essential if the EU and its partners are going to achieve net zero emissions by 2050. The CCS technology can be rolled out to around 500 similar waste-to-energy plants across the EU that will also need to cut their emissions over the next ten years. It can also be used for the extra 100 plants of the size of Fortum Oslo Varme that the EU will need to deal with the 40 million tonnes of residual waste it faces as more and more landfill sites are closed. 

It is important to be aware that incineration does not compete with reuse and recycling. Even if Norway and the EU achieve the ambitious targets for reuse and recycling there will still be waste that we cannot dispose of any other way. Much of this is from biological sources so if we use CCS technology we are actually removing CO2 from the atmosphere. 

We have to deal with the climate challenges with the tools we have at hand today –  and that includes incineration of residual waste and CCS. We can’t wait for miracle solutions that may never be invented or considered good enough. 

At Fortum Oslo Varme we strongly believe this project could be a blueprint for cities on how to best deal with non-recyclable waste, while producing heat and electricity for city inhabitants and meeting ambitious greenhouse-gas emission reduction targets in the coming decades. 

Fortum Oslo Varme (FOV) AS is owned 50/50 by the City of Oslo and Fortum Participation Ltd. Oslo and the surrounding region, one of the most prosperous regions in Europe, have a population of more than 1.2 million.

Oslo is aiming to be a fossil-fuel-free city by 2050.

Launching the carbon capture and storage project at the waste-to-energy plant is an important steppingstone towards meeting this goal.

Fortum, founded in 1998, is the world's fourth largest heat supplier and has a number of combined heat and power (CHP) plants as well as biomass plants for energy recovery and district heating.

Circular use of resources, recycling, district heating and overall sustainable waste management are key features of Fortum's business.

With the vision “for a cleaner world” Fortum aims to be at the forefront of developing both the industry, technology and new green jobs.

With approximately 19,000 professionals and a combined balance sheet of approximately €69 billion, we have the scale, competence and resources to grow and to drive the energy transition forward. Fortum's share is listed on Nasdaq Helsinki.

By Jannicke Gerner Bjerkås, Director Carbon Capture and Storage, Fortum Oslo Varme AS

Government has ‘no plan’ for net zero, critiques Commons Select Committee

As much as 62% of future emissions reductions will rely on individual choices.

As much as 62% of future emissions reductions will rely on individual choices.

The Government still has “no plan” for achieving net zero by 2050, the Public Accounts Committee has said in a new report.

Despite the target being legally set almost two years ago, a lack of coordinated plan with clear milestones is holding back the country’s efforts and making it difficult to gauge the progress made.

Government departments do not sufficiently consider the impact of net zero when taking forward projects and programmes. While the Treasury has changed the guidance on policy appraisal so that departments put greater emphasis on the environments of their programmes, it has not set out how this will work in practice.

Additionally, it is not ensuring that its activities do not simply shift emissions creation overseas, undermining global climate change efforts.

The Public Account Committee said that as much as 62% of future emissions reductions will rely on individual choices – both through everyday behaviours, and through larger purchases such as switching to a heat pump or an electric vehicle – but the Government has not engaged with the public substantially on these points.

Some initial inroads have begun to be made, with the Committee pointing to the Parliamentary select committee’s Climate Assembly UK in 2020. But the Government needs to go further in encouraging a shift to net zero, and putting in place structural economic changes to support it.

The lack of progress is particularly significant given the UK is set to host the COP26 climate conference in Glasgow in November. This will mean “the eyes of the world, its scientists and policymakers are on the UK - big promises full of fine words won’t stand up," said Meg Hillier MP, chair of the Public Accounts Committee.

Ahead of the event, the Government "intends to publish a plethora of strategies this year" setting out how it will reduce emissions in different sectors, but a clearer plan is still required.

Hillier said the Government had set itself a “huge test” through its Net Zero commitment, but has shown few signs it "understands how to get there”.

“Our response to climate change must be as joined up and integrated as the ecosystems we are trying to protect. We must see a clear path plotted, with interim goals set and reached - it will not do to dump our emissions on poorer countries to hit UK targets. Our new international trade deals, the levelling up agenda - all must fit in the plan to reach net zero.

The damning critique follows just days after the Chancellor presented his Budget for 2021/22 to the nation, itself drawing criticism for a lack of green pledges. While there were a few points welcomed, it has largely been seen as a ‘missed opportunity’ by those in the energy sector, while others have criticised the fuel duty freeze while there was no support within the financial statement for transitioning to electric vehicles.

Drax drops plan for Europe’s largest new gas plant as it turns its back on fossil fuels

Image: Drax.

Image: Drax.

Drax has dropped plans to develop any new gas plants, including its plans to build Europe's biggest CCGT plant as it moves to turn its back on fossil fuels.

In the company’s full year results for 2020, it set out its plans for carbon neutrality, committing to no new gas generation and the end of commercial coal in March 2021.

“Our focus is on renewable power,” said Will Gardiner, CEO of Drax Group. “Our carbon intensity is one of the lowest of all European power generators. We aim to be carbon negative by 2030 and are continuing to make progress. We are announcing today that we will not develop new gas fired power at Drax. This builds on our decision to end commercial coal generation and the recent sale of our existing gas power stations.”

Drax sold four of its CCGTs to VPI Holdings in December as part of its sale of Drax Generation Enterprise for £193.3 million. The company retained its pumped storage and hydro assets, stating it was to focus on flexible and renewable power.

Since it was first announced in 2017, there have been continued protests against the company’s plans for a 3.6GW plant in north Yorkshire, including a legal challenge from ClientEarth. Sam Hunter Jones, a lawyer with the company, said the decision to scrap the development was a “massive win for the UK and the climate".

“In opposing this controversial project since its inception, we warned that it risked the UK’s net zero target and risked locking in huge long-term subsidies. And the government’s planning authority agreed when it recommended refusing planning consent.

“Just as the coal era is long gone, what Drax’s statement today makes clear is that time is up for building any new large scale gas power plants in the UK.”

Instead Drax will focus on progressing its biomass strategy, including its proposed acquisition of biomass pellet manufacturer Pinnacle Renewable Energy. It is also expecting to invest £190-210 million in 2021 to expand its LaSalle and Amite pellet plants, and continue development of bioenergy with carbon capture and storage.

“The proposed acquisition of Pinnacle Renewable Energy will position Drax as the world’s leading sustainable biomass generation and supply business, paving the way for us to develop bioenergy with carbon capture and storage (BECCS) – taking us even further in our decarbonisation,” added Gardiner.

Drax made an operating loss of £156 million in 2020, with obsolescence charges racking up to £239. This was principally made up of coal charges, but also includes £13 million associated with deciding not to develop the North Yorkshire asset.

Coal closure cost £34 million through redundancy, pension and site reparation payments, however the run-rate saving once Drax’s two units are closed next month is expected to be c.£30-35 million it noted. The company announced it would shutter the units in February 2020, with generation to stop a full four years ahead of the government’s deadline and the units to be formally closed in September 2022 when their existing Capacity Market obligations end.

Drax’s net debt continued to be high, at £776 million including cash and cash equivalents of £290 million. This is a small drop from its 2019 results, which saw debt jump significantly to £841 million.

Its adjusted EBITDA loss was £39 million, compared to £17 million in profit the year before. This was largely driven by the impact of COVID-19, causing a £60 million loss from reduced demand and increased bad debt.

“Drax has supported its customers, communities and employees throughout the COVID-19 pandemic and I want to thank colleagues across the Group for their commitment and hard work over the last year,” finished Gardiner. “We have delivered strong results, a growing dividend for shareholders and excellent progress against our business strategy.”

Brexit has reduced trading with Ireland sending power prices ‘rocketing’

Image: Getty.

Image: Getty.

With the end of the Brexit transition period, Great Britain left the internal energy market of the European Union (IEM). As part of the Northern Ireland protocol, though, the single electricity market (SEM) of the island of Ireland has remained intact.

Brexit has led to a decrease in the use of the SEM’s interconnectors with Britain however, with the average utilisation in January falling 150MW.

Image: EnAppSys.

Image: EnAppSys.

Phil Hewitt, director of EnAppSys, explained that before Brexit, two interconnectors coupled the SEM with the IEM, using a common day-ahead auction that ran at 11AM.

“This ensured that if prices were higher in the SEM than in GB, energy would flow from GB to the SEM to reduce prices for consumers in the SEM and vice versa.”

The decoupling due to Brexit meant that in January 2021, utilisation on interconnectors with Ireland fell to around 350MW compared with 500MW before Britain’s exit from the EU.

This lower level of usage led to an increase in the frequency of extreme prices due to liquidity decreasing, according to EnAppSys.

This was true in both markets, continued Hewitt, adding that “for the 11AM day-ahead auction, 11 of the 14 highest prices ever seen have occurred since Britain left the IEM with the peak value being €500/MWh equivalent to 50c per kWh unit".

“Also, because there is less volume than capacity in the IDA1 and IDA2 intraday auctions, which now are the only auctions that determine the interconnector flows between GB and the SEM, this means that the interconnectors are utilised less. In turn, this means that the SEM needs access to more indigenous generation which may be more expensive than in GB. In addition, when it is windy in Ireland there is less opportunity to push this excess wind energy over the interconnector to GB.”

Image: EnAppSys.

Image: EnAppSys.

Cold weather and low winds caused particularly tumultuous power prices through the first month of 2021 in the IEM, with new records set both in the day ahead market and the imbalance price. This was further impacted by the decoupling from Single Day-Ahead Coupling (SDAC), which uses the EUphemia algorithm.

“It’s likely that the reduction in the ability to bring in cheaper power from GB or export cheaper power to GB will result in more extreme prices in the future,” finished Hewitt. “The current situation with lower-than-usual dispatch on the interconnectors will continue until SEM market participants increase their use of the IDA1 and IDA2 auctions. This also requires more participation on the GB side.”

Image: EnAppSys.

Image: EnAppSys.

McKinsey: Power consumption to double by 2050 as COVID-19 helps pull back fossil fuel peak

Image: Getty.

Image: Getty.

Power consumption is set to more than double by 2050 as electrification increases, according to new research from McKinsey.

The consultancy found that the share of electricity in energy consumption will grow to 30% by 2050, up from 19% today. Renewables will be dominating this from 2030, with cost reductions over the next decade resulting in the technology becoming cheaper than existing fossil fuel plants.

This is to trigger a sharp uptake in the installed capacity of solar and onshore and offshore wind, with 5TW of new solar and wind capacity installed by 2035 and over 50% of global power power generation coming from renewables the same year.

The consultancy is also predicting that the aggregate fossil fuel demand peak will be brought forward to 2027 partially as a result of COVID-19’s impact on energy demand.

It found that while global coal demand has already peaked, oil and gas are now not far behind, falling in 2029 and 2037 respectively.

In McKinsey's report The Global Energy Perspective 2021, it discusses how the pandemic has resulted in a significant reduction in energy demand, which it will likely take between one and four years to recover from. Additionally, the company expects that electricity and gas demand will bounce back quicker than demand for oil, and that demand for fossil fuels overall will never return to its pre-pandemic growth curve.

However, McKinsey did state that over the long-term, the impacts of behavioural shifts due to COVID-19 are minor compared to more known long-term shifts such as decreasing car ownership, growing fuel efficiencies and a trend towards electric vehicles, whose impact is estimated to be three-to-nine times higher than the pandemic’s by 2050.

Despite the earlier peak of hydrocarbon demand resulting in a substantial reduction in forecast carbon emissions, the report continues to state that the world remains significantly off of the 1.5ºC pathway.

This is detailed in particular in the Reference Case scenario, one of four modelled by McKinsey, which saw more than half of all global energy demand continuing to be met by fossil fuels by 2050. This scenario is McKinsey’s outlook on the continuation of existing trends, examining its expectations of how current technologies can evolve, and is compared against a 1.5 ºC pathway, a delayed transition where the societal focus is on economic recovery post-COVID-19 and an accelerated transition.

Christer Tryggestad, senior partner at McKinsey, said that there is still “a long way to go” to avert substantial global climate change, with annual emissions needing to be around 50% lower in 2030 and 85% lower by 2050 than current trends predict.

Tryggestad added that many governments need to translate "ambitious targets into specific actions", with the focus of stimulus packages for COVID-19 to "play a key role in shaping energy systems in the decades to com

Has Brexit created higher electricity prices? A look at the impact of decoupling from EUphemia

National Grid ESO has issued two Electricity Margin Notices (EMN) – one for Wednesday evening and one for Friday evening – as the cold weather and lower generation cut into its safety buffer, putting the security of supply at risk.

The tight margins led to dramatic peaks in intraday trading and Balancing Mechanism (BM) prices. Power prices in the N2EX auction hit £1,000.04/MWh for the period 17:00 to 18:00 on Wednesday 6 January, the highest hourly price seen on the auction. During the same period EDF’s CCGT plant West Burton B was called on at £3,000/MWh in the Balancing Mechanism.

Following on from the EMN issued for Friday, West Burton B2 and B3 had offers accepted at £4,000/MWh in the BM, while Uniper’s Connahs Quay 3 CCGT plant was accepted at £2,750/MWh.

An additional factor that drove up the N2EX auction price was the decoupling of the markets as Alastair Martin, founder and chief strategy officer at Flexitricity, explained: “The two main day-ahead auctions (operated by Nordpool and EPEX-Spot) are no longer linked, which means they can clear at different prices. Most of the time, they come out very close to one another, but yesterday the divergence was large. This is probably a market inefficiency, and it remains to be seen how it will be resolved.”

Decoupling and confusion: Leaving EUphemia

While much of the price volatility seen this week was driven by the changing nature of the nation’s electricity, with more intermittent renewables taking over from baseload coal stretching periods of high demand, there is now also the additional impact of Brexit and this decoupling of Great Britain’s auctions from EUphemia (EU + Pan-European Hybrid Electricity Market Integration Algorithm).

“All of the EU’s electricity markets are linked at the day ahead in a big algorithm called Euphemia,” explained EnAppSys’s director Phil Hewitt, describing it as "one of the crown jewels of the internal electricity market".

“At noon Central European Time – so that’s 11am GB, Irish and Portuguese time, and 1pm over in eastern Europe – what happens is that all of the auctions in each country are linked to their neighbours. This results in the automatic flow of power from less expensive regions to more expensive regions. So if, for example, it was tight in GB, then the power would flow across from France, Belgium and the Netherlands automatically. So, now, because we've left the European Union and the transition period has ended, we're no longer in that market arrangement; we have decoupled. Not only that but the two auctions in GB have decoupled from each other, causing more price confusion.”


Now GB has decoupled, it is running two auctions- Nord Pool and EPEX, as well as participating in the European auction. This creates more liquidity, and with it the potential for higher and lower prices.

Whilst leaving EUphemia doesn’t in itself increase energy prices, it does complicate trading which is likely to lead to higher prices for the GB market.

“Before you had a single auction, so if you were an interconnector capacity holder there was little risk to scheduling those flows,” expanded Adam Lewis, partner at market insight company Hartree Solutions. “There was a low risk methodology of optimising those flows to ensure that they flowed in the best way. Whereas now because of Brexit, we've decoupled and the UK has now decided to go on to have two auctions in the morning, which creates more confusion, volatility, uncertainty and risk. We believe the market would benefit from a single coupled UK auction.”

Does Brexit mean we’ll see more price volatility?

It seems likely that there will be more power price volatility going forward, especially if the UK sees continued cold weather as well as low wind generation. This is more a mark of the changing makeup of the nation’s energy mix than the impact of Brexit however, with that more a secondary aspect.

“The current system was designed to create peaky prices, reflective of the stress on the system at the time,” pointed out Martin. “The idea was that electricity suppliers and wind farm operators would put more effort into forecasting, and thermal generators would put more effort into reliability if the consequences of getting it wrong at the wrong moment were more unpleasant.

“Since then, renewable generation has continued to grow, and the electricity system looks quite different. So, we may see a revision to the pricing mechanism at the extremes. Whether that calms down prices, or re-directs the peakiness to different types of event remains to be seen.”

Additionally, it is worth noting that price spikes are not entirely negative as they can help keep power stations that might ordinarily struggle to compete in auctions running and encourage increased expansion.

“The high prices encourage people to enter the market, so they're not necessarily a bad thing,” argued Hewitt. “A power station that’s marginal is going to make reasonable money in periods of high prices, which might mean it will decide to stick around for another year or maybe somebody who’s developing battery projects or developing gas peakers or maybe even CCGTs is going to look at these high prices and say, ‘well, there we go, I can make money in this market'. So they're going to be more encouraged to build."

Balancing Mechanism price jumps to highest level since 2001, hitting £4,000/MWh

Image: Getty.

Image: Getty.

The imbalance price reached a high of £4,000/MWh on Friday evening, capping off a dramatic week in the energy market.

For the price periods 39-40 – between 19:30 and 20:30 on 8 January – the imbalance price soared to a high equivalent to 400p a unit, the like of which hasn’t been seen since 2001.

It followed a dramatic jump during price period 35 as well on Friday, hitting £2,750/MWh. At the time, this was the highest seen for nearly two decades but this was beaten just two and a half hours later.

The first week of 2021 was particularly volatile for the energy markets, as tight margins and low temperatures pushed National Grid ESO, leading it to issue two Electricity Margin Notices (EMN). Both were followed by periods of high prices in the Balancing Mechanism, with prices jumping to £3,000MWh on Wednesday 6 January as EDF’s West Burton B was called on, allowing NGESO to cancel the first EMN.

The second ENM was issued for Friday evening, and although it was subsequently cancelled, it led to EDF’s West Burton B2 and B3 successfully having their bids accepted at £4,000/MWh on Friday.

For the previous high period on Friday, Uniper’s Connahs Quay 3 CCGT plant was accepted at £2,750/MWh.

The last time prices were as high as they have been in Great Britain’s Balancing Mechanism was in 2001, when the New Electricity Trading Arrangements (NETA) were first introduced. The NETA Go-Live on 27 March that year created a new wholesale market, with a number of minor problems with the simplicity of the algorithm used for the Balancing Mechanism leading to two records being set that year that have yet to be broken.

On 5 May 2001, during period 32 the price soared to £4,993.88/MWh, before this record was broken on 19 June 2001 during period 32 with a price of £5,003.33/MWh, according to EnAppSys.

These high prices can be seen as a positive according to Phil Hewitt, director of EnAppSys, as “they encourage the building of new assets and the development of innovations such as demand response that allow the electricity system to decarbonise".

“In the future prices will become more extreme at certain points – either super-high prices like this week or super-low prices when renewables are running at maximum output and this will encourage solutions via the market to smooth generation and demand.”

Price volatility is likely to become increasingly common, as Great Britain relies increasingly on intermittent generation such as offshore wind. Additional factors that have driven high prices so far in 2021 also include the BritNed interconnector with the Netherlands remaining down, as well as the decoupling of the UK’s electricity markets with EUphemia – a consequence of Brexit that has added a level of complexity to energy trading.

As well as driving up prices in the Balancing Mechanism these also led to record N2EX auctions prices last Wednesday, when it hit £1,000.04/MWh for the period 17:00 to 18:00 on 6 January, the highest hourly price seen on the auction.

“Looking at the demand/supply stack for UK power moving forward, we see limited baseload generation coming online so this tightness is likely to be more acute in future years,” expanded VEST Energy’s Aaron Lally.

In order to manage it, more flexible assets such as battery storage will need to be integrated into the mainstream power system, he continued. “The highest prices we have seen in the BM for decades on Friday could have been avoided if GWs of flexible assets were confident that making themselves available in the Balancing Mechanism would have led them being dispatched by the TSO.

“This is really a competition issue; large plants exercising market power because the current market framework does not allow smaller (more dynamic) assets to participate. This needs to change.”