Will Britain keep the lights on?
UK Energy - Policies and Prices →
Each winter brings warnings of potential blackouts in the UK. Old power stations are closing regularly, and as a result, Britain’s electricity supply-demand balance is now tighter than it has been for many years.
However, National Grid has a suite of measures to make up for shortfalls, and the UK capacity market has been brought forward to winter 2017/18 to further bolster supply. The lights are therefore expected to stay on, but questions remain about how to achieve this as cheaply and cleanly as possible.
Supply shortages: myth or reality?
A 'capacity margin' is the difference between available power plant capacity and peak winter demand. Last winter, margins were tighter than they have been for some years, with the winter of 2016-17 expected to be largely unchanged as reserve measures are implemented.
During 2016, around 4 GW of coal-fired capacity has closed, including Longannet, Ferrybridge and Rugely, largely due to age and unfavourable economics. Other coal plants at Eggborough and Fiddler’s Ferry have also exited the market but are being held in reserve over the winter.
The closure of old power stations has become increasing regular in recent years. Coal-fired units have increasingly been running at a loss due to growing maintenance costs, the carbon floor price and low wholesale prices caused by cheap natural gas and increased renewable generation. Meanwhile, nuclear reactors are reaching the end of their lifetimes and closing sequentially.
Most remaining coal and oil-fired plants must either close or be converted to more environmentally friendly generation by 2018 to comply with European Union regulations. Additionally, the UK’s ongoing coal phase-out will render any remaining unabated coal plants obsolete by 2025, although many are closing earlier.
Britain’s power demand is also gradually falling as a result of investment in efficiency and a continuing shift to a service-based economy. Peak demand is expected to fall from 53-56 gigawatts (GW) in 2015-16 to 52-55GW in 2017-18.
Total installed capacity is rising, from an expected 71-75GW in 2015-16 to 75-79GW in 2017-18. But much of this capacity is in the form of solar panels and wind farms, whose generation is variable.
When calculating capacity margins, National Grid uses the concept of ‘de-rating’ to account for the fact that no generator is available all of the time. Solar farms for example generate about 10% of the time, while hydro, nuclear, biomass and fossil fuels will be around 80-90%, with wind somewhere in the middle. National Grid expects a de-rated capacity of 54.7 GW for this coming winter, compared to a 52.7 GW peak demand.
How does the National Grid balance supply and demand?
The National Grid has to balance electricity demand and supply. If supply falls below demand, the initial impact is that the frequency of the grid falls below 50Hz. This can damage equipment and lead to power cuts if it is not managed.
First, all large operating generators can automatically change their output within seconds of a frequency change, called frequency response. Second, over a period of minutes, the National Grid can call up additional power output from fast start-up generators, called the fast reserve. And third, over a period of minutes to hours, it can call up additional generation, or ask big energy users to cut demand, under a short-term operating reserve (STOR).
Given increasingly tight margins, the National Grid and Ofgem introduced in 2014 two new tools to balance the grid, under a Contingency Balancing Reserve (CBR).
- A Demand Side Balancing Reserve (DSBR), which contracts in advance big energy users on standby, to cut demand if needed, at peak times defined as 4-8pm on winter weekday evenings.
- A strategic power plant reserve, called the Supplemental Balancing Reserve (SBR), under which power plants that would otherwise be closed, mothballed or unavailable to the market can be used as a last resort.
The National Grid used the DSBR in full for the first time on 4 November 2015 in response to a ‘Notice of Insufficient System Margin (NISM)’ - a declaration that the Grid had a lower margin between supply and demand than it felt comfortable with. The event was caused by the sudden and unexpected near-simultaneous failure of several coal-fired units. The SBR was not used.
The frequency of NISMs is at a historic low, with only two issued in the last 12 months. Both were due to unexpected simultaneous outages at ageing power stations and neither occurred during the critical winter peak period.
Looking forwards, the de-rated margin is expected to increase. Including reserve measures, the margin for winter 2016-17 is expected to remain unchanged on the year at 5.5%, before increasing in winter 2017-18 as the capacity market is introduced and new generators come online.
Generating companies face a problem due to increasing penetration of wind and solar assets in the grid. More renewable generation reduces the selling price of power while simultaneously hindering the hours at which conventional thermal generators are called on to run. Wind and solar have no fuel costs and so generate electricity at much lower cost than thermal plants, once built. Further, EU rules require that renewables have priority grid access, pushing other power plants further down the merit order which can reduce profitability.
This so-called ‘missing money’ problem is the reason that the UK decided to introduce a capacity market. Instead of paying generators for energy, it rewards them for being available, ensuring sufficient capacity to meet the winter peak. The market is only available to non-intermittent (‘dispatchable’) power, such as fossil fuels, hydropower and nuclear.
Auctions are held annually, with the first in 2014, for power delivered four years later (the T-4 auction). The government also holds a second auction, one year in advance (T-1), to fine tune the amount of capacity available. A third ‘transitional arrangements’ auction was introduced to give demand side response (DSR) an entry into the market, although proponents of DSR argue that the terms offered place it at a disadvantage to conventional generators.
Energy academics generally agree that some mechanism was needed to bridge the gap between the introduction of variable renewables and the time when storage, demand shifting, interconnectors and other technologies render variability of generation almost irrelevant.
But a number of criticisms have been levelled at the design of the capacity market:
- The inclusion of fossil fuel generators risks giving perverse incentives. As the then boss of Centrica pointed out in 2014, the government is paying through other mechanisms to phase out the use of coal and then gas, yet may be paying via the capacity market to keep coal and gas stations open
- The existing design offers a very tiny sliver of the market – 1.5%, in the 2014 auction – to DSR providers. These allow non-essential equipment to be turned off during demand peaks, thereby reducing the number of fossil fuel generating plants needed for energy security. This has been increased to 300 MW in the next transitional arrangement auction (for 2017-18)
- It allows ‘behind-the-meter’ diesel generators (called 'reciprocating engines') to bid as demand response providers, despite their highly polluting nature. The use of diesel engines is currently under review by Defra, while Ofgem are also carrying out a review into potentially unfair benefits of behind-the-meter generation.
- The capacity market is not so far incentivising the building of new gas-fired power stations that the government says it wants, and which some analysts believe are necessary for future energy security. To date, the auctions have cleared below market expectations – in part due to the volume of diesel generators bidding at low prices – good value for billpayers but not sufficient to attract investment into new infrastructure.
In addition, the award of a capacity contract for 2018 to Fiddler's Ferry power station did not prevent owners SSE from deciding to close it. In auctions from 2016 onwards, however, the penalty for non-delivery has been increased.
With or without a capacity market, Britain is expanding its network of interconnectors, from 4GW currently to 11GW by 2022. This could make a big difference to security of supply, as well as reducing bills, by delivering lower cost, largely renewable wind- and hydro-generated power from Ireland, Denmark and Norway. Interconnectors were initially excluded from bidding into the capacity market, but this position was reversed in the 2015 T-4 auction.
Trials of demand-shifting also indicate a much bigger potential to increase security of supply by reducing peak-time demand. DSR has the same effect on the supply-demand balance as increasing generation, and can be implemented at lower costs and on shorter timescales than building new plants.
The myth of ‘Blackout Britain’
In the 10 years to 2015, Britain experienced just one power outage related to insufficient generation (when two large power stations suffered unrelated faults within five minutes of each other). It was not severe, with customers left without power for about 20 minutes on average.
By contrast, there are about a quarter of a million outages each year across the country due to failures in transmission and distribution.
So the headlines warning of widespread blackouts that we have regularly seen over the last decade have not reflected reality. Even if supply does fall below demand in a coming winter, we would not expect disruption on a scale anything like that seen during the 1970s.