Letter from London: UK thermal generation economics in a spin
The country’s move away from market-based to subsidy-driven mechanisms is undermining both existing and new conventional generation
The June appointment of administrators for the UK’s Severn Power and Sutton Bridge combined-cycle gas turbine (CCGT) power plants owned by independent power producer Calon Energy was, unfortunately, no great surprise. Even when Calon bought Sutton Bridge from France’s EdF seven years ago, its commercial assumptions were optimistic.
Calon plants may well have been negatively impacted by 2020’s UK power demand reduction due to the Covid-19 pandemic. It certainly would not have helped.
But the brutal truth is that the power market of the UK (or, more accurately, that of GB, as Northern Ireland sits within the All-Island Energy Market) has never justified optimism for conventional generators since the arrival of electricity market reform (EMR), back in 2013. Yet ‘magic economics’ are now being touted for a new generation of hydrogen-fuelled gas turbines.
In 2008, we saw the creation of the UK’s department of energy and climate change and a shift from market and demand-driven plant construction to an administered industry where ministers and civil servants, advised by lobby groups, made the choices about generation technologies. They decided that consumers should subsidise specific technologies to try to reduce the consumption of fossil fuels, thereby cutting carbon emissions.
‘Magic economics’ are now being touted for a new generation of hydrogen-fuelled gas turbines
The consequence has been that the overall grid connected capacity has risen by 4pc from 2008 to 2019, even while peak demand has fallen by 20pc over the same period. But installed thermal generation (excluding nuclear) has fallen by 34pc.
Increasing capacity while demand is falling and existing plants are being closed or mothballed is a difficult concept for power system economists. But this is only part of the story.
There are three types of plant. There are those that provide flexible power, as and when required. These are classified as ‘firm’ for the purposes of security of supply and are the plants that, in a market sense, price compete to operate.
The next tranche are plants that must run, when available, for technological or contractual reasons. They provide firm power but are not flexible and do not price compete. In the UK these are principally nuclear and biomass.
Thirdly, there are the intermittent plants that run when the wind blows and the sun shines or the river flows. These plants are contractual price takers and run whenever available unless paid not to.
In 2019, GB peak demand was 48.2GW. Capacity in excess of that was reported as 18.3GW, a margin of 38pc. But this figure has been downrated to take account of the intermittency of non-firm plants. Capacity is downrated to take account of intermittency over an annual cycle, but, in any one hour, 100pc of capacity may be available. Re-rating the non-firm capacity yields an installed excess capacity of 33GW at system peak demand and a plant margin of 68.7pc.
Installed must-take plant (nuclear, wind and solar) capacity in 2019 was 33GW, and average demand was 31.7GW. This means that, on an average hour with good renewables availability, the opportunity for firm flexible plants to run, and to set a market price, is incredibly limited. Furthermore, summer minimum demand was 18GW, so up to 15GW of must-take plants might then have been at risk of curtailment.
A lack of price-setting plant running damages the credibility of even the supposedly market-based mechanisms within EMR. Even contracts for difference—subsidies to new capacity that are supposed to be market-based— need a reliable underlying market, but this no longer exists.
And conventional thermal generation—coal, oil or gas—needs running hours to recover operating costs and make a contribution to capital. With demand yet to see any electrification bounce, the current levels of excess capacity undermine the economic argument to build any plants at all.
As for the future of both existing and new CCGTs—which qualify for no subsidy but may be needed by the country to keep the grid robust and, ultimately, the lights on—the outlook has never been bleaker.
Trevor Turner is a management consultant at CeTurn and a chartered electrical engineer, and was previously a director and senior manager in the UK power and gas sectors.