Western European power prices have surged lately, partly on the back of a review of French nuclear plants. But coal-fired power plants have failed to capitalize on the trend, given price rises also for seaborne coal.
As the Chief Executive of Uniper, Klaus Schäfer, told analysts this week, following the company’s Q3 earnings report: “A slight recovery in the price of baseload should not be overstated. Unfortunately, the spread between fuel costs and power prices haven’t moved very much, or actually in the wrong direction. Our power stations continue to face substantial margin pressures.”
Uniper is the former conventional generation business of European utility E.ON, and so is all too vulnerable to pressures on coal and gas power. Like many European utilities, Uniper is arguing for a new approach to remuneration, where power plants earn guaranteed payments to make capacity available—irrespective of whether they generate electricity—through so-called capacity markets.
The move has been prompted by the growth in variable renewables: electricity is dispatched to the grid on the basis of least-operating cost, and because wind and solar power have zero fuel costs, they are dispatched first. Their meteoric growth has pushed everything else down the so-called merit order, to the extent that coal and gas power plants may not be called upon at all.
Conventional utilities argue nonetheless that energy consumers need coal and gas power plants to keep the lights on during dark, windless days in winter, for example, when there is no wind and solar power. They say their gas and coal plants can provide this balancing service, but must be subsidized through capacity markets.
Various options are available for balancing variable renewables and guaranteeing security of electricity supply that include conventional power, baseload renewables, battery storage, demand response, greater efficiency and grid build-out. The mix is still open, making the debate over capacity markets, which favor gas and coal, a hot topic.
Some countries that have already introduced capacity markets—Spain, Britain, Italy—are “energy islands” with fewer cross-border connections to balance variable renewables. They may need more back-up. Britain also has quite a narrow adequacy margin, which is the gap between total supply and peak demand, as it shuts down more polluting coal power plants.
But Uniper argues that capacity markets also make economic sense in countries such as Germany, which is no energy island (it has massive cross-border interconnections) and has ample generating capacity.
Britain recently proposed introducing its capacity market one year earlier than planned, for delivery in 2017-18, to buy more capacity and to increase incentive levels to motivate new-build gas.
Last week, I met Uniper’s U.K. chairman, Felix Lerch, who is keen on supporting capacity price rises and wants Uniper’s 2.1GW Ratcliffe coal plant to benefit. Lerch’s idea is to have Ratcliffe stay open even beyond the U.K. coal phase-out date of 2025, and he says the reason for doing so is that it would lift security of supply. While the British government recently backed plans to phase out coal power by 2025, that was conditional on “no risks to the security of our electricity supplies.” While much has been invested in Ratcliffe to reduce nitrous-oxide emissions, but the power plant, built in 1968, is out of step with the times.
The Ratcliffe example shows how Uniper is pinning its hopes on capacity markets, going so far as to unabashedly argue for giving a half-century-old power plant a new lease on life.
The question for policymakers is whether it makes sense to do so as they seek to balance cost, security of supply, and carbon emissions. Do long-term, multi-year capacity payments aimed at supporting gas plants and eking more life out of old coal plants make sense? Or can newer, cleaner technologies, including hybrid combinations of digital, decentralized technologies, compete better in the new energy economy?
Gerard Wynn is an IEEFA energy finance consultant.
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