This is an extract from the full report, which also looks at biodiversity, the generation mix needed to get to net zero and the heating conundrum. Download it here.
Over the past few weeks we’ve witnessed at first hand just how difficult balancing up the energy system can be. Most consumers take for granted that electricity and heating is only the flick of a switch away. Yet soaring wholesale gas prices – 10 times more than in June 2020 – plus a lack of wind, damaged interconnectors and ageing nuclear power stations out of service for maintenance, have combined to create a crisis. Matching supply and demand has forced National Grid Electricity Systems Operator (ESO) to once again fire up two coal-fired power stations. Even that was not enough to stop two industrial plants making fertiliser from closing down because of sky high prices creating a knock-on interruption to food production. Yet just last year ESO was reporting a 68-day stretch without needing to call on the black stuff.
For all the UK’s undoubted successes on the transitioning path to zero-carbon generation, these recent events have highlighted just how far there is to go in ensuring a resilient and workable energy system as we move towards 2050. There have been a number of factors that have come together to create the 15-year high surge in gas prices, including restriction in supply from Russia and countries returning to pre-pandemic levels of industrial demand and prioritising gas over coal to reduce carbon footprints.
Prime minster Boris Johnson has argued that as we become less reliant on imported gas, energy prices should become more stable. On the other hand, taking coal and then gas out of the generation equation leaves ESO having to find reserves elsewhere. A rise in demand for electricity to provide power for transport and heat makes the challenge of maintaining sufficient flexibility in the system tougher still.
A recent report from Imperial College London forecast that by 2050 the UK could be generating 150GW of offshore wind. But as Dr Jeff Hardy, senior research fellow at the Grantham Institute, Imperial College London, observes: “If the wind isn’t blowing that leaves a big hole in electricity – and demonstrates just how important having flexibility to call on will be.”
As demand for power increases and more distributed generation assets like electric vehicles (EVs) are connected to the system there is also another dimension to flexibility to think about.
This is ensuring that the capacity of the network to deliver greater demands for power will also be met affordably. In the past as demand grew, it would be fed by installing more cables; but now, to make it economical, networks are being asked to manage extra demand in a smart way, levelling peak demand through local flexibility. That will mean networks won’t need to invest to the same degree in upgrading infrastructure.
This “flexibility first” approach will be a key plank of the network’s forthcoming ED2 business plans.
Andy Huthwaite, director of ED2 programme at Scottish and Southern Electricity Networks (SSEN) Distribution, explains how the network has been responding to the changing landscape: “For quite a number of years now we’ve been taking a flexibility first approach. So if someone wants a new connection which could trigger the need for reinforcement, irrespective of whether that was demand or generation, we’ve put a range of things in our system that allows us to present flexible options to them.
“In our Scottish Highlands distribution network, for example, we’ve introduced active network management. That has allowed people to participate and connect to the network without us having to do five years of reinforcement at x million pounds.”
However, moving to a more flexible system will still require networks to invest in technology to monitor the network, analyse data and improve communications, says Huthwaite.
The levels of local flexibility contracted by the network operators in 2021 are already 38 per cent higher than the total for the whole of the last year, comments Randolph Brazier, director of innovation and electricity systems at the Energy Networks Association. At the moment, flexibility is contracted typically through an aggregator or directly with industrial and commercial customers, says Brazier, but it could develop more widely. “The local flexibility markets only started in the back half of 2018 from scratch and don’t exist anywhere else in the world. The reason why we are ahead of the pack is that policies and regulation are in place to drive adoption.” He cites the ban on sales of combustion engine vehicles, the RIIO model which incentivises networks to be innovative, and the research and development allowance, which allows innovations to be trialled and tested.
If we’re going to hit our net zero ambitions then the deployment of flexibility is going to be absolutely critical
Huthwaite points to SSEN Distribution’s ambitious plans for flexibility in ED2, the next price control, and is looking to increase its flexible connections up to about 3.75GW and within that is hoping to precure around 5GW of flexible services from 600MW currently. “That’s a step change for us, but as a country if we’re going to hit our net zero ambitions then the deployment of flexibility is going to be absolutely critical,” he says.
In terms of balancing supply there are broadly four types of flexibility ESO can consider:
- Flexible generation – like biomass
- Electricity storage – like batteries, hydro power – compressed air
- Demand-side response – turning demand for energy up or down, on or off, such as industrial processes
- Interconnectors – importing electricity from the continent.
Hardy says this adds up to a diversity of options.
“Although demand-side response from the domestic side is currently negligible, you shouldn’t under-egg that – we could be looking at 35 million EVs and 20 million heat pumps, that’s a vast array of things that can be turned on or off,” he says.
Government is aware of the need to use EVs to boost flexibility. It is proposing phased legislation to ensure that all charge points are smart and in time wants to give powers to network operators to be able to delay battery charging for the benefit of the grid.
It’s current thinking on this was set out in a paper published in July: Electric Vehicle Smart Charging Government Response to the 2019 Consultation on Electric Vehicle Smart Charging.
Hardy acknowledges that the use of EVs and heat pumps doesn’t provide the answer to the huge variation in demand between summer and winter, but says it does provide a solution to those variations during the day. “However, there is no evidence yet to support what we can deliver this way because the system is not up and running yet.”
Meanwhile, Huthwaite says that SSEN will be looking at a range of options in its procurement of flexibility. “It could be aggregators, it could be demand-side response arrangements, it could be storage facilities, it could even start moving into vehicle-to-grid if we can get that enabled and open that more widely given the projections of EVs. It’s a whole sheet of options.”
Right now, flexibility supplied from EVs and heating is negligible and it is acknowledged that scaling this up will require significant consumer engagement. That amounts to a change of mindset in our relationship with energy and will require a number of levers to bring that change about. Ovo and Octopus have introduced a flexible EV charging tariff to move the demand during the night, but it is too early to see the overall value.
Maria Brucoli, smart energy systems manager at EDF, says that while there is huge opportunity to tap into EVs and heating devices in future, grid scale batteries have a big part to play with another 30GW of growth expected by 2050. “There is currently around 10GW of low carbon flexibility currently available to the UK power market. This includes 4GW of electricity storage (3GW pumped hydro storage and 1GW of lithium-ion batteries) and 6GW of electricity interconnectors,” she notes, adding: “There is a growing pipeline of energy storage and interconnector projects, but the final sum is short compared to the estimates from the latest Smart Systems Flexibility plan developed by BEIS together with Ofgem and published in July.”
Their report, Transitioning to a Net Zero Energy System: Smart Systems and Flexibility Plan 2021, suggests that to meet the net zero target set for 2050 by the sixth carbon budget, while at the same time operating a secure and efficient energy system, a total of 30GW of low carbon flexibility will be required by 2030 and 60GW by 2050.
However, if flexibility from batteries is to be ramped up, markets need to be developed that put a value on their services. In the past they may only serve one function, but to be commercially viable they need to offer a number of functions – or “value stack”, says Hardy, adding: “To make value stacking work the systems needs to know what assets are connected and assets need to realise the value of the action they take.”
Brucoli says that EDF is contributing by enabling commercial solutions for large-scale flexibility projects and providing asset owners a “route to market” service with a guaranteed minimum price for battery storage.
“EDF leads the way in offering ‘floor price’ contracts for battery storage projects, enabling developers to demonstrate returns on investment required to proceed with developing the assets,” she says. “EDF Renewables is also developing a battery storage portfolio through its acquisition of Pivot Power.”
For all the work going on in this field, government and the industry is yet to get to grips with the scale of flexibility needed in the system, says Dr Keith MacLean, managing director of Providence Policy. MacLean, along with Dr Grant Wilson and Noah Godfrey of the Energy Informatics Group at the Birmingham Energy Institute, have been looking at the flexibility challenge of replacing natural gas. They published their findings in September in a paper Net Zero – Keeping the Energy System Balanced.
Says MacLean: “At the moment, the heavy lifting in balancing Great Britain’s electricity and heat sectors is done by natural gas, capable of contributing 3-4TWh towards managing imbalance daily, and over 100TWh seasonally.
“We did some work to check on the orders of magnitude of balancing needed in the future. It will be basically the storage capacity that we have with natural gas.”
At the moment, the heavy lifting in balancing Great Britain’s electricity and heat sectors is done by natural gas
As MacLean points out, that’s a fuel that can be stored and transported and used when and where it’s needed and that enables the difference in needs between summer and winter to be bridged, especially for heat.
“We need to understand that heat in particular imposes a seasonal variation and a seasonal imbalance in what we need that requires tens of terawatt-hours’ worth of capacity.”
MacLean adds: “For shorter scale lower energy applications you can use batteries, pump storage and demand-side management, but they don’t solve the key challenge that we have which is the longer time scales. And when we talk about the flexibility that domestic consumers can offer, that is on the intraday level – which means shifting something from the morning to the afternoon, or from the rush hour to the quiet times. We have got a bit myopic and preoccupied with the intraday stuff, and without a clear idea of the bigger challenge.
“Most batteries in the UK are working in a time scale of up to one or possibly two hours, but what we need to balance the system are things capable of working over many days, over seasons and in some instances over years, and that’s what natural gas, previously coal, oil or wood have allowed us to do. “
While this might suggest that having more nuclear power in the system could be the answer, MacLean says that’s not the case because nuclear can’t be turned up or down to respond to fluctuating demand. “Our research shows that you need more balancing capability in a pure nuclear system then you do in a pure renewable system. Wind, in particular, is actually well correlated to heat; people tend to need more heat at a time when the wind is blowing more and vice versa. Solar does the opposite because the sun tends to shine in the summer when we don’t need heat, and it hardly shines at all in the winter when we do.
“Therefore, adding solar into the mix for heat makes the imbalance worse – you’re actually better eliminating solar completely. These are the sorts of topics that you only uncover if you look at the actual challenge over the longer term, and that’s what we’ve done in our research, and I think it’s certainly raised a number of questions we weren’t expecting to come out,” he says.
For MacLean, the finger points to hydrogen as the obvious solution “because it is another chemical fuel which may not be as energy dense as natural gas, but it’s not far off. And moving and storing hydrogen is much cheaper and easier to do than moving and storing electricity”.
MacLean says that because of the duration and flexibility that hydrogen can provide, it makes sense to set up an electricity system to produce hydrogen, and then use that hydrogen to transport and store the energy for use when it’s needed.
There is not yet anywhere near a consensus on the role hydrogen can play in the energy mix as we discuss in the next chapter. Certainly, making hydrogen the heavy lifter of flexibility would be expensive, MacLean acknowledges that – but there is not a solution at the level required that isn’t, he says. “It will cost a few trillion pounds to build a system with batteries.”
With diverging opinion on levels of flexibility and the use of hydrogen, how we can pay for it and what technologies to back, this is a transition issue that will continue to vex minds for some time to come.