The power source that used to provide the bulk of Britain’s electricity has become the mainstay of the country’s energy reserve system.
This is one of several key findings from a new report by North East energy market monitoring firm EnAppSys.
The study showed that coal’s share of the GB power mix fell to a Q1 record low 9.4% (8.13TWh) in the first quarter of 2018 – in sharp contrast to the 58.4% (40.33TWh) generated in Q1 2012.
However, there were instances when coal plants came to the rescue when there was a shortage of power from other sources. On Thursday March 1, National Grid issued a gas deficit warning to indicate a potential shortage of gas on the system while coal stepped into the breach, generating 10.5GW of power – effectively the highest possible level of coal output achievable at the time.
EnAppSys said coal had gone from being the dominant player in Britain’s power mix to a vital provider of reserves when the system needed additional supplies – in the case of March 1, due to a fuel supply rather than a capacity shortage.
Paul Verrill, director of EnAppSys, said: “The ability of the system to fall back on coal in this phase of the market has proven highly beneficial and marks a major strategic shift in the way coal plants are being used in GB power generation.
“The additional electricity that coal produced on March 1 helped reduce gas use, reducing the risk of gas interruption. This showed the value of having a diversified fuel supply in the GB energy mix and demonstrated the role coal could play as a back-up source of generation.
“With these plants set to close over the coming years, there is a risk that gas shortages endanger the ability to provide electricity to the market as required. The Capacity Mechanism has secured generating capacity into the future but 70% of this is gas-fired and 10% is from external countries that suffered their own gas shortages at the time we did.
“The closure of GB’s largest gas storage asset, Rough Storage, and the decline of GB gas reserves has made the Britain vulnerable to gas shortages arising from supply disruption. Following the March gas crunch, the Department for Business, Energy & industrial Strategy (BEIS) declined industry calls to look at support for the building of new storage, citing market forces as the sufficient driver. This seemed a strange response given their intervention in the power market to guarantee supply.”
The first three months of the year were also notable for record levels of wind generation and high gas prices, which pushed up overall power prices. Wind farms set new records for half hourly, daily, weekly, monthly and quarterly levels of generation, with 15.8TWh of power coming from wind sources during the period.
The strong performance of wind helped overall renewable output to hit 25.0TWh – the highest ever level recorded in a single quarter in Britain – which meant renewables were the second largest contributor to the GB power mix behind gas-fired plants.
The first quarter saw 37.3% of electricity generation come from gas-fired power stations, with renewable projects contributing 29.0% and nuclear plants 18.1%. Coal-fired power stations produced 9.4%, while 6.3% came from electricity imports.
Almost one fifth (18.3%) of the 29% share of renewables generation came from wind farms, 6.8% from biomass plants, 2.2% from solar farms and 1.7% from hydro plants.
Paul Verrill said: “The performance of renewables highlights just how important this electricity source – and particularly wind – has become to Britain’s power mix. With offshore wind farms a cheap and relatively uncontroversial source of power, levels of wind generation are expected to continue rising and this trend will be fast-tracked by the Western Link interconnector coming on stream later this year.
“Much of the onshore wind farm capacity within Britain is based in Scotland but there are relatively limited levels of export capacity down into the rest of Britain through northern England.
“The Western Link will move power from Scotland into England and this will reduce the likelihood of wind farms being paid to go offline due to transmission constraints.”
The EnAppSys study also showed that Q1 2018 was characterised by lower peak market prices than those seen in the corresponding period in 2017. This can be attributed mainly to the Capacity Mechanism, which has enabled power plants with a combined 3.5GW of additional capacity to trade commercially rather than simply remain on standby in the event of an unexpected plant shutdown or power outage.
This, however, has resulted in a fall in revenues. EnAppSys said the maximum levels of income achievable at flexible assets, from simple operation, declined from an estimated £57/kW for the six months to March 31 2017, to £22/kW for the corresponding six months in 2017-18.