In April to June this year near-term electricity prices tumbled down so far that for periods they were negative. Generators had to pay to export power on to the network.
In fact, negative wholesale prices were not unknown in the past, but in the quarter they were a persistent feature. Why? All types of renewables were highly productive during the quarter, with high winds, good input from the fast-increasing number of solar PV facilities in Europe and high water levels in Nordic hydropower reservoirs. Market data company EnAppSys said the three months had more periods of negative pricing than would usually be expected; system prices dropped as low as -£155.20/MWh in May and there were negative prices in several consecutive days. It was referring to the spot market – for immediate dispatch – but it said prices in the ‘day ahead’ markets also dropped below zero on several occasions during periods of high renewable generation.
Sometimes if one generator over-produces, the system operator can sell the surplus. What happens at times of negative prices is that the system operator, which has to balance the system, has no customer. Instead it either has to pay for surplus energy to be consumed or pay power plants to switch off.
This type of price volatility is a feature – not a bug – of a decarbonised electricity system. If the system is set up well, it will allow energy users to feast on cheap power at times when there is an energy glut. That is implicit in the negative prices. The other side of the challenge, only partly solved at the moment, is to make it easy to store the excess – or manage demand – so that it is available at times of scarcity. If the suppliers and users of electricity can work together to achieve that, it should lower prices for everybody.
At the moment, some energy industry companies are doing the heavy lifting on managing volatile power prices. They invested to acquire assets with two roles in the system, such as pumped storage hydro plants or batteries, on the grounds that their services – storing energy when there is oversupply and releasing it when there is scarcity – would be required. Now they are being well-rewarded for it. For example, Drax Power saw earnings from its Cruachan pumped storage hydro plant in Scotland triple this year (earnings were £154 million in H1 2023, compared with £53 million in H1 2022, including relatively small contributions from two other hydro projects that do not have the ability to pump water up). Gresham House Energy Storage Fund, which invests in battery storage, saw earnings increase by over 20% in 2022, to £48 million, thanks to rising prices and increased market volatility.
VOLATILITY MOVES IN TO THE OPEN
It should be remembered that volatility is not new to the electricity industry. Demand and supply have always gone up and down, whether by time of day, temperature, fuel price or other factors – but the industry has always managed that volatility internally.
Sometimes that management has been done by sharing. The first interconnector between GB and France was built in 1986, to take advantage of the fact that the time difference means peak hours between the two markets differ. At other times, the electricity system operator has managed variation itself, with actions such as running power plants ‘in neutral’ (incidentally burning coal or gas), bringing them into operation if and when they are needed. The cost of all this was wrapped into bills and was largely invisible to the bill payers.
In a decarbonised system, volatility is growing dramatically, both in the price variation and in the amount of energy involved. That could continue to be a pot of gold for the companies like those above, which own assets designed to smooth out the volatility. But with advanced meters and upcoming changes in industry data flows, the volatile prices will be visible to users. That opens the door to a new way of operating: using different types of flexibility that are hidden in the system and, often, under customer control. Government and industry both believe that this will be cheaper overall and, crucially, will allow the reward for flexibility to flow to end users, rather than electricity companies.
HOW CAN YOU BENEFIT?
There are already several ways that an energy customer can help manage demand and supply and be rewarded for it. They give a hint of where gains are likely to be made for users.
Some tariff options follow supply levels across the whole market, offering cheaper prices when there is excess (others also depend on location; see below). At this stage most do not shadow the wholesale prices exactly, because the energy industry’s smart metering and settlement systems are still being rolled out, so true wholesale reflectivity is seldom possible. Some tariffs such as Octopus Agile do reflect negative prices for smart meter owners but more often suppliers aim to reduce the risk of consumers being out of pocket (and, of course, any risk to the company) by offering ‘peak’ and ‘off peak’ price periods that are fixed, with much in common with previous overnight tariffs like ‘Economy 7’. Vehicle owners are seeing the options first, because charging an EV requires a substantial amount of energy. It is in both suppliers’ and users’ interest to ensure the cars are charged at the cheapest time. Most suppliers offer cheap periods for EV drivers who charge at their home or site.
In the USA, this has already moved further: John R Hanger, a former member of Pennsylvania’s Public Utility Commission, recently tweeted that “Free EV charging is possible in many US markets, where substantial renewable energy plus nuclear push prices low or negative for hours. It’s available in Texas.”
There is another issue to add to the question of how electricity is being generated that is already giving rise to new cheap or negative tariffs. Can the energy be transported to users? Electricity transmission relies on an electricity network – and one with wires in the right place and of the right size. Again, this has always been the case. In the past our energy sources were coal mines. Generating plants were as close as possible to the coal supply (electricity transfer being more efficient than coal transport) and the network was designed to transfer power to cities and industries, with weaker links to more remote places.
Now we are taking advantage of different natural assets – wind and solar – and they are not in the same place. Building or upgrading the necessary connections is a slower process, and while it happens there can be excess renewable energy being generated in one place, discarded because of ‘traffic jams’ on the network.
Of particular concern is the so-called ‘B6 boundary’ where there is often a jam on the limited network running roughly along the border between Scotland and England. The anticipated growth in renewable generation in Scotland is increasing power transfer across the Scottish boundaries, which are forecast to increase constraints at or above the B6 boundary, and ultimately costs to the end consumer.
This year, Great Britain’s national system operator (NGESO) has introduced some products that try to stop renewable energy being discarded, which it has named the ‘local constraint market’. NGESO describes this as ‘a new marketplace that could divert surplus power into local assets at times when southward flows are at capacity.’
It ran a competition in May and signed contracts to pay two flexibility service providers - Orange Power and CUB UK – to ‘turn up’ demand use an extra 3.3MWh north of the constrained connection between Scotland and England. The two companies will use the extra power to boost heat pumps, EVs and electric heating. NGESO says that will ‘help bring operating costs down for critical transmission grid balancing and redirect money back to customers at a time of high energy prices.’
It is looking for more customers in the right locations. The system operator is also learning from its experience during the Covid summer of lockdown, which gave it a window on how a future system with a high proportion of renewables would behave. That period saw extremely low industrial and commercial demand, but once again, it saw plenty of generation from wind and solar power. The abundance of low-cost renewables displaced gas plant, whose physical inertia helped keep the system within its frequency and voltage limits. To ease the situation, the system operator introduced a payment for companies that could increase their demand. That is expected to make a reappearance in some form, as the system operator has increasingly to manage periods of low demand, in the same way it has always managed periods of high demand.
These location-based tariffs do have a negative price component, but they are aimed at businesses, rather than domestic consumers.
LOCAL OPTIONS
As has been seen, suppliers and the national system operator are developing ways of using customers to help manage the system in time and in location. The same is true of the so-called distribution network operators (DNOs) that manage low-voltage networks. They too can defray the cost of upgrading the network if they invite companies to switch their use to cheaper – and less constrained – off-peak periods. And they too can help keep voltage and frequency within bounds by including customers in the mix.
All of the DNOs are offering new flexibility options that can reduce costs or even pay back for business customers. UK Power Networks (UKPN) said that in the period to 2025 “We are seeking flexibility across our network – from generators connected at 132kV to portfolios of domestic assets.” The company says past tenders have seen payments as high as £600/MWh for turning down demand at periods set by UKPN.
It is also looking at options for soaking up excess power generation. Because the network expects more solar PV to be installed, it says: “for the first time we’ll be seeking demand turn-up as well as demand turn-down. This is a great opportunity for demand or battery storage to get paid for absorbing locally-generated, green electrons that would otherwise be lost.”
UKPN adds that small assets can be aggregated and the minimum requirement is just 10kW per constraint area, ‘lower than any other system operator’.
It may seem alien for companies to actively participate in managing their electricity supply, but previous experience of the advent of the capacity market has shown that with suitable incentives they will respond (see also box, p19). Companies that have flexibility about varying their usage in location, as well as in time, have twice the opportunity (see also box, left).
Both domestic and business customers should benefit from increasing energy market volatility and from negative prices – if they have a sharp eye for their own usage, and the ability to be flexible.
BOX: THE CAPACITY MARKET NEARS 10 YEARS
Becoming an active energy consumer used to be an alien concept for companies, but in fact many have been participating in the market for years. Many large companies dipped into the energy sector via payments from the government’s ‘capacity market’ (CM). The CM is just approaching a decade in operation and its aim is to ensure the country’s winter electricity needs are covered. In that market, consumers pay power asset owners to guarantee availability in winter months. This applies not only to large power stations but to small onsite generators, including such options as back-up generators as small as 1MW. The CM’s reach has expanded over the decade to include more companies. That is first because so-called ‘aggregators’ have provided a route for even smaller assets that can be bid into the CM as a group, and second because companies that can reduce their energy use for a few hours can participate as ‘demand side response’ even if they do not have generation assets.
BOX: THE DATA CENTRE EXAMPLE
Global data centre energy use now represents nearly 1% of final electricity demand worldwide and it is still growing. But data centre operators are able to shift computing jobs and associated power loads both in time (via scheduling of flexible work) and by location between data centres.
A new study found that shifting computing activities and associated power loads in both time and location improves the efficiency and affordability of carbon-free electricity by up to 34%
(see www.is.gd/uvupel). The study was supported by Google. In a previous study, the authors focused on a large range of European companies from the corporate and industrial sectors and found that many have some degree of flexibility in their electricity consumption – generally in time rather than location, although clearly commercial companies with many locations (such as supermarkets or EV charging network owners) may have both options. See also www.is.gd/acewec.
BOX: CASE STUDY: HOSPITAL UPGRADE
Finland’s largest hospital area has modernised switchgear equipment for its power supply. The Meilahti Hospital Area in Helsinki, which is operated by Hospital District of Helsinki and Uusimaa (HUS), upgraded its electrical system to maximise uptime, eliminating the use of SF6, a potent greenhouse gas, in the medium-voltage (MV) switchgear, and extending the life of electrical equipment.
The Meilahti Hospital Area uses the same amount of electricity as a small town, and delivers healthcare to more than half a million patients annually.
The upgrades included a turnkey MV circuit breaker retrofit, where SF6-insulated models have been replaced with VD4 vacuum circuit breakers. These new devices clear potentially harmful short-circuit faults in tens of milliseconds, thereby preventing severe damage to the hospital’s electrical infrastructure and minimising the risk of downtime.
The aging relays in the switchgear were also replaced with ABB REF615 protection relays. Here, arc fault protection is now ensured with ABB’s REA 101 modules. The protection is based on optical arc flash detection with fibre-optic light sensors, tripping at arc faults in milliseconds.
Sixten Holm, business development manager at ABB in Finland, said: “For service providers such as HUS, one of the greatest opportunities for improving reliability and reducing carbon and costs is by modernising outdated components, rather than replacing the entire switchgear. Replacing aging circuit breakers and protection relays can also be done quickly with minimal downtime.”
ABB Ability Energy and Asset Manager was installed to facilitate remote monitoring and provide real-time information on the condition of equipment, such as temperatures, with alarms from devices alerting them instantly by text message. In addition, specific condition monitoring for the MV switchgear is now available, based on real-time data from ABB’s SWICOM diagnostics system.