UK shows value of CCGTs [NGW Magazine]
The recent price spikes in the GB power market cannot be blamed on low wind levels alone. Cold weather in Britain and in northwest Europe as well as unplanned maintenance works on the 1 GW BritNed power interconnector with the Netherlands – thus limiting cross-border electricity supply – also played a role.
The situation was exacerbated by the fact that two CCGT power stations – the 850-MW Severn Power Station in South Wales and the 850-MW Sutton Bridge plant in Lincolnshire were unavailable as its owner Calon Energy went into administration last summer and the plants were closed down in August, too early to enjoy a moment in the sun.
Grid operator National Grid warned of system tightness early January and called upon plant generators with capacity contracts to ready themselves to ramp up production if demand exceeded supply. Although blackouts were avoided, wholesale power prices peaked at levels as high as £1,000 ($1,360)/MWh for next-day delivery.
The combination of higher demand and lower supply from renewables altered Britain’s supply mix with more electricity produced by gas stepping in to fill the gaps. Gas-fired electricity generation increased from around 40% of total generation to close to 50% when comparing the average for December 2020 with the second week of January 2021. Coal-fired generation rose from around 2% to 6% while wind generation declined from around 22% to 15% and even going below 10% on occasion.
The need to call on gas-fired plants was exemplified by EDF’s West Burton plant in Nottinghamshire which secured a price of £4,000/MWh in the balancing market January 8. In that market, National Grid pays plant operators to supply the grid after gate closure in the daily auctions in order to balance demand and supply.
With Britain’s last coal-fired plants being phased out by October 2024 and its current nuclear fleet probably reaching the end of its lifespan by 2030, the need for new power plants is beginning to look urgent. Yet the business case for new CCGTs is looking questionable as investors are wary of betting on future prices for carbon allowances, electricity and fuels. The UK’s capacity market was designed to bolster investment in new CCGTs, but few new plants have been built since the first auctions in 2014.
“The government’s intention was that the GB capacity market would support new CCGTs, but it has failed to do so. Of the new CCGTs built since the capacity market’s inception, ESB’s Carrington and SSE’s Keadby plants had both taken FID before securing capacity contracts,” Kathryn Porter, an independent energy consultant with Watt-Logic told NGW. Keadby 2, due on stream in 2022, nevertheless secured a 15-year capacity contract in March last year once construction was well underway.
“The only exception is Centrica’s small King’s Lynn facility. The big winners in the capacity auctions have been diesel generators and OCGTs which are not great from an environmental perspective,” she said.
The 2024/25 capacity auction scheduled for March this year will bring more clarity as to whether investors are eyeing an opportunity to build CCGTs, particularly in the light of the recent power price spikes.
James BrabbenWholesale Manager at consultancy Cornwall Insight said there could be opportunities for new plants compared to previous years “owing to the need for capacity in the middle of the decade. This doesn’t necessarily mean new CCGT assets will be built, although the government’s Energy White Paper announcements last December, suggesting support for carbon capture use and storage (CCUS) projects that are linked to power stations, could provide new avenues for CCGT outside the capacity market too, he said.
The paper pledged support for gas-fired power plants with CCUS in order to complement increasing generation from renewables and to help reach the net-zero by 2050 target. For example, the zero-carbon Teesside industrial cluster in the north of England – a project fronted by UK BP, Italian Eni, Anglo-Dutch Shell, French Total and Norwegian Equinor – includes plans for a gas-fired power plant with carbon capture technologies.
The recent price spikes have also highlighted Britain’s increasing dependency on electricity imports from Europe. Interconnectors with France, Netherlands, Belgium and Ireland can meet around 10% of demand and Britain is usually a net importer although it also plans to increase exports on windy days as more onshore and offshore wind projects are being rolled out. The new IFA 2 interconnector between France and Britain is expected to be operational in the coming months and will increase border capacity from 2 GW now to around 3 GW. New interconnectors with Norway and Denmark are also underway, expected in 2021 and 2023 respectively.
But imports will not always be available when a cold spell hits Britain and northwest Europe simultaneously. On January 8, French TSO RTE asked consumers to reduce electricity consumption in the hours between 07.00 and 13.00 due to cold weather and system tightness. Temperatures were around 4.5 C below the seasonal norm.
Britain has been a net importer on the 1-GW NEMO interconnector with Belgium since it entered operations inJanuary 2019. However, Belgium plans to phase out its nuclear reactors by 2025 – half of the country’s generation capacity – and new CCGTs to fill this gap might not be built in time as the European Commission is investigating the country’s planned capacity construction. In other words, banking on imports from continental Europe to fill supply gaps may be riskier in the future than it appears now.
Brexit and the UK’s withdrawal from the EU’s internal energy market may also affect investor confidence in new power plants, be it CCGTs, nuclear power or other technologies. Britain holds separate interconnector auctions from the coupled northwest Europe electricity market. However, a new arrangement for market coupling – whereby trading of transmission capacity and electricity is bundled – is expected to begin next year. How this will work in practice remains to be seen, however.
“The price spikes are a function of market fundamentals rather than Brexit and de-coupling. However, the changes will mean less efficiency in allocating interconnector capacity in the future. We have already seen impacts for price divergence on the two GB day-ahead exchanges, N2EX and Epex,” said Brabben.
“At this stage, it is difficult to know if the lack of market coupling resulted in higher overall prices for consumers [in early January].”