UK capacity margins slimmer than ever
The UK’s National Grid is having to enlist the support of standby generators and big consumers for the second year running
The situation could be tighter still next year, and while capacity market incentives are already in place, there is no sign so far of new, flexible gas-fired capacity additions the government is looking for. Longer term, technology may be the answer to the margin squeeze, with demand-side management, storage and decentralised grids all working together, but in the meantime it looks as though Grid will have to turn to more old coal and diesel back-up plants.
As forecast by the national energy regulator Ofgem in July, National Grid’s Winter Report has put the upcoming winter reserve margin – the difference between available power supply and expected peak demand – at 1.2%, the lowest since 2005-6, and down from 16.8% as recently as 2011-2012 (Chart 1). At this level the risk of “controlled disconnections”, in which customers’ power supplies are cut off, could be as high as a “one in one year” event – implying an incident would be expected at some point during the winter.
In response National Grid has enlisted an additional 2.4GW of aging backup oil, coal and gas plant, which lifts the margin to 5.1%. National Grid also said there was an "increased likelihood" that it would have to pay large businesses to cut consumption during peak weekday demand periods. Large consumers have signed up to take part in the voluntary scheme, in return for payment whether or not they are interrupted.
Last winter, when reserve margins stood at just over 4%, 780MW of balancing reserve capacity was put on standby, with another 319MW of potential demand reduction secured in the form of interruptible contracts – which were not used.
This winter the measures should be sufficient to ensure security of supply at an average cost of less than 50p/customer, National Grid said. “We expect electricity margins to be tight but manageable for this winter. We have procured our contingency balancing services which we may need to use in order to help us balance the system,” it said in its report. “We currently expect there to be sufficient generation and interconnector imports to meet even the tightest week,” it added.
But the problem is expected to get worse in coming years, as aging nuclear plants are closed and old fossil fuel plants are shut down in line with the UK’s emissions commitments. Installation of dependable replacement capacity is failing to keep pace, leading to growing concerns over the country’s security of supply. In its July report Ofgem said the grid's spare capacity could fall to between 0 and 4% by 2016/7, with the regulator anticipating the closure of nine power stations amounting to 7.4GW in 2016.
The UK government’s own plans indicate about 20-25GW of new flexible capacity will be required by 2025, and the government is thought to favour gas for most of this. The move towards renewables has done little to improve reserve margins, as all intermittent renewables require backup. The energy minister, Amber Rudd, said in her DECC blog in August that she favoured gas and that “lots of new low-carbon generation cannot be relied upon in the same way that gas-fired power stations can.”
But even with capacity market incentives, gas doesn’t make commercial sense any more, because the build-up of subsidised wind capacity has displaced gas from substantial periods of potential revenue generation. DECC suggests that a typical new gas plant would be expected to run as low as 27% capacity, filling in the gaps between renewable surges – making them far less commercially attractive. Gas demand from gas-fired generation this winter could be anything from 15m to 78m m³/d depending on renewable flow – a range of 63m m³/d, according to National Grid, creating huge uncertainty for investors.
“Last winter there was a bias towards coal over gas for power generation due to the price differential between gas and coal. This meant that gas took the role of the marginal source of generation, resulting in lower overall demands but with far greater within day demand volatility. This bias is expected to continue this winter,” said National Grid.
Estimates of the cost/MWh of new-build gas plant from DECC recently suggested that it would need a return of about £68/MWh to cover investment, well over 50% above current prices of around £40-45/MWh. A think tank, Policy Exchange, estimates that the last capacity auction at £19.40/MWh actually represented a ‘subsidy’ of only £4/MWh to a new gas plant - well below what would be required to make a gas plant work. Richard Howard, head of energy at Policy Exchange, said such plants might require guarantees of up to £40m in subsidies/year, for 15 years – roughly double the level currently on offer – in order to get built.
All the responsibility and none of the power
But while policy may be directing closures and failing to inspire investors, Rudd is placing the responsibility to meet demand squarely with National Grid: “Keeping the lights on is non-negotiable. National Grid has the right tools in place to manage the system this winter and we will ensure that they continue to do so in future.”
While National Grid is confident it can meet the challenge this year, things may get tougher in future years. Once this winter is over, Grid said, it wants to talk to power companies about what sort of new subsidy regime it needs to put in place to raise capacity margins. This consultation has been welcomed by Ofgem’s senior partner for markets, Rachel Fletcher. “There is also plenty of opportunity for generators and other market participants to continue to make more supplies available,” she added.
Clearly, there are concerns that costs to taxpayers and consumers will rise from heavy subsidies for both existing renewables and new gas-plant. But there could be alternatives. Many experts believe the demand-side option will fall in cost and expand dramatically thanks to smart grids and cloud technology, along with cheaper storage options.
National Grid’s chief executive Steve Holliday recently said: “The idea of baseload power is already outdated.” He said that while the industry used to be based on meeting demand, with “an extraordinary amount of capital tied up for an unusual set of circumstances: to ensure supply at any moment”, this had “now turned on its head. The future will be much more driven by availability of supply: by demand-side response and management which will enable the market to balance the price of supply and of demand. It’s how we balance these things that will determine the future shape of our business.”
The option is clearly cheaper and greener than building capacity, and is also seen by many as crucial in accommodating ever more intermittent renewables. “DSM technology is particularly essential in the UK, where it can help mitigate the growing concerns surrounding the predicted energy shortfall,” said the managing director of the European arm of global renewable energy company RES, Gordon MacDougall.
“Smart grid technologies show strong potential to optimise asset utilisation by shifting peak load to off-peak times,” said Marc Borret, CEO of Reactive Technologies, which provides demand-side management. “This type of demand management service can balance grid systems by using demand flexibility across hundreds of thousands of small devices… Surges in renewable power can be effectively utilized, which would avoid instances such as those seen in the UK recently, where the grid operator paid wind producers for not generating power during periods of low demand.”