Blackouts: the risks and reality

Emotive sound bites such as ‘Blackout Britain’ grab the headlines, but are they inadvertently driving up energy costs for consumers? Matthew Aylott investigates.

There is no getting away from the fact that, on paper, capacity margins are looking increasingly tight. But the government and National Grid need to avoid a knee-jerk reaction to media fear-mongering and weigh the risks against the likelihood of disconnections – otherwise we could all end up paying over the odds. But what is the reality of the risk of blackouts and is the response appropriate?

Peak winter electricity demand in the UK is about 60GW and there is currently around 86GW of generating capacity, plus up to 4GW from interconnectors to foreign electricity systems. This should provide plenty of spare capacity to keep the lights on, but if there is one thing you can rely on in Britain, it is the unreliability of the weather.

At the peak time on the peak day for electricity demand in winter 2010, there was almost no contribution to generation by wind or solar. Still, even if we take intermittent renewables out of the equation, there should still be sufficient thermal and hydro-electric capacity (65GW) to cover the peak in demand, assuming all of these plants are available.

Fire damage to the Ferrybridge and Ironbridge power stations has resulted in the loss of 0.8GW of generating capacity, while the closure of EDF’s Heysham 1 and Hartlepool nuclear reactors for safety checks recently removed a further 2.3GW. Although Heysham and Hartlepool are expected to restart generation shortly, this only underlines the vulnerability of the system to unexpected events.

As older power plants close and the contribution of renewable electricity is scaled up, tight capacity margins are likely to continue.

A future system with higher wind and solar capacity is expected to rely heavily on combined cycle gas turbine (CCGT) power plants to meet the net demand not met by renewables. CCGT power plants make up a large portion of the UK’s total generation capacity, at 29GW in 2013, and this is expected to increase to about 35GW by 2020.

On occasions when wind and solar output is low and demand is high, total CCGT output should be able to ramp up rapidly. However, the UK is increasingly reliant on imported gas, which makes it more vulnerable to external market influences. More storage facilities and linepack (volume of gas in pipelines) management should help to prevent physical gas supply shortages. However, price shock issues are another matter and will require not only greater storage capacity, but also alternatively fuelled power plants, interruptible power contracts and gas demand-side management.

We should also not ignore the effect of climate change on energy infrastructure resilience. Colder winters will increase demand for heating, while rising summer temperatures could lead to de-rating of transformers and cables and lower gas turbine efficiency.

Increased concentrated rainfall will raise the risk of flooding; estimates suggest a 79 per cent increase in the number of power stations at risk and a 21 per cent increase in the number of substations at risk by 2050. More severe winters will also increase the risk of ‘wet snow’ or icing of overhead lines and insulators, while more frequent high wind events could lead to mechanical failure of overhead lines or wind turbines.

It is a long list, and one that requires serious attention and forward planning.

The risks are manageable. That’s not to say margins will not be tight this winter, but in the event of a insufficiency, system operators have tools at their disposal before it becomes necessary to disconnect demand. These include interruption of demand on interruptible demand-side contracts; “maxgen” (where thermal generators operate at a higher than normal output for a short period); emergency measures on interconnectors to other countries (to reduce export or, if imports are not already at a maximum, to increase imports); and voltage reduction.

National Grid has introduced a supplemental balancing reserve and demand-side balancing to provide added capacity and manage demand in the short term, but this has yet to be stress-tested against an extreme cold spell, for example.

In the longer term, demand-side management is likely to become an important tool in managing peaks in demand. Under the proposed capacity mechanism, generators will not only receive an income from generation, but also from being ready to generate.

What is perhaps of greater importance is whether these measures offer value for money to the consumer. Concerns have been raised over the structure of the capacity market auction, which offers those developing new generation capacity contracts of up to 15 years, while those offering demand-side response options could at best secure a one-year contract. The design of the capacity market could encourage the construction of expensive new power stations at the expense of cheaper, greener alternatives.

Some will argue that the government has failed to support the market in keeping open gas-fired power stations to provide the necessary insurance policy against decreasing capacity margins. Others might suggest the market has taken advantage of the opportunity to mothball power stations and drive up the cost of electricity. But the problem is really about who has ownership of risk.

Government carries a political risk, distribution network operators are incentivised to reduce “customer interruptions” and “customer minutes lost”, while generators lose revenue if they fail to supply. But ultimately it is consumers who are most at risk, if not through disconnections then through increased energy bills.