October 12th, 2015, Published in Articles: Energize, Featured: Energize

by Fereidoon Sioshansi, Menlo Energy Economics

 

Europe provides rich material for anyone interested in a study of the rapid metamorphosis of the power sector. While the worst may be over, the future looks bleak, especially for coal. Following decades of enjoying stable demand growth and healthy returns, large European power utilities went through a rough period in the past few years.

The decline in demand, following the 2008 global financial crisis, resulted in European power utilities’ investment in new thermal generation plants becoming uneconomical as a result of a fall in wholesale prices (Fig. 1) and the rapid growth of renewable generation.

Europe’s five largest power utilities: France’s EDF, GDF Suez, Italy’s Enel, and Germany’s E.ON and RWE, which collectively account for roughly 60% of generation in Europe, lost considerable value, measured in market capitalisation, between 2008 and 2013. How much? An estimated €100-billion, roughly 37% of their pre-2008 value. While economies of the Eurozone also took a dive during the same period, Germany’s stock market experienced an 18% rise in value over the same period. It has been an unpleasant experience for European utilities, to put it mildly.

The big five, plus every other power utility in Europe, have had to take drastic action to turn things around with E.ON taking the most drastic step to break itself into two companies, the new E.ON plus the old company, jokingly referred to as E.OFF. While the jury is still out on how their turnaround strategies will pan out, indications are that the massive down-turn experienced in 2008 to 2013 may indeed be over.

A recent report by Carbon Tracker [1], for example, suggests that a turnaround is already underway (Fig. 2), good news for stockholders and/or government treasuries – in cases where companies are partially or mostly state-owned, such as in France. Despite the apparent turnaround, it is premature to say that they are out of the woods yet. The market fundamentals are stacked against them. Demand remains sluggish due to rising retail tariffs – which in countries like Germany, Spain and Italy are heavily burdened with taxes and levies. Customer self-generation and energy efficiency are up, and the continued flood of renewables eats away the revenues of thermal generators.

In case of Germany (Fig. 3), the mid-day peak tariff, when thermal generators historically made good money, has all but disappeared due to the continued growth of renewables mandated by government decree. The same phenomenon is becoming pronounced in California, Australia and elsewhere as the rapid growth of renewables, energy efficiency and distributed generation is eating into the livelihood of incumbent thermal generators to different degrees. In the meantime, rising retail tariffs plus the falling cost of solar PV means that as time goes on more consumers will find rooftop PV to be a good investment, as illustrated in Fig. 4.

The future of power generation in Europe is even bleaker than the US for conventional thermal plants. According to the European Wind Energy Association (EWEA) [2], during the 2000 to 2013 period, there has been a net reduction in installed nuclear, coal and oil capacity (Fig. 5) with no indication that any of these trends will stop or reverse any time soon. In fact, most observers believe that coming out of the Paris COP this December, EU members will commit to further reductions in their greenhouse gas emissions, which means even less coal, oil and gas fired generation for the future.

Other indications are equally bleak for thermal generation, particularly coal, which is the most carbon intensive – the central message of the Carbon Tracker report and the source of the figures in this article. As elsewhere within OECD economies, electricity demand growth across Europe is on a decidedly downward trend
(Fig. 6) and no amount of wishful thinking is likely to turn that around. The simple explanation is the gradual decoupling of economic growth from energy intensive industry and manufacturing (Fig. 7). In this environment, thermal generators will increasingly be competing with renewables whose marginal cost is zero. Their role will increasingly evolve into one of balancing intermittent renewables – a highly valuable function but without significant remuneration under current market rules where generators get paid by volume.

Which is one reason for the current debate to introduce capacity payment mechanisms, which may very well be needed to keep thermal plants, especially those with rapid ramping capabilities, in the black. The situation is so serious that even nuclear plants, whose marginal fuel costs are virtually nil, are having a hard time, both in the US and in parts of Europe.

Bloomberg [3] recently reported that Electricite de France’s (EDF’s) sale of nuclear energy to its rivals, as dictated by regulation, for the second half of the year has fallen to a fraction of what it was in 2014, suggesting that even in France, nuclear energy may be losing competitiveness. According to Commission de Regulation de l’Energie (CRE), the state-controlled EDF sold a quarter of its output, roughly 4 TWh, to its competitors. The 12,3 TWh sold for the first half was also less than half the 34,6 TWh for the second half of 2014, according to Bloomberg.

These are among the challenges facing EDF’s new CEO, Jean-Bernard Levy, who is pushing for higher prices to help pay for tens of billions of euros of maintenance and safety upgrades on EDF’s aging fleet of nuclear reactors, which account for three-quarters of the country’s electricity production. EDF, the world’s biggest nuclear operator, is required to offer about a quarter of its annual nuclear output to rivals under a regulated system known as ARENH that’s aimed at increasing competition on the French domestic market. Under this scheme, rivals can buy power at the current price of €42/MWh or from the wholesale market if prices are lower.

French electricity is bought and sold in the market on a year-ahead basis for €38,15/MWh, or 9,2% below the ARENH price, according to Bloomberg. The government is reviewing how it calculates the rates charged for ARENH nuclear power. EDF has warned that selling at less than €42/MWh could eat into the company’s earnings. In October 2014, the energy regulator proposed that the ARENH rate should rise to €44/MWh this year and by 4,5% in 2016. The government is yet to decide on a revision. The rate should gradually increase to €55/MWh to reflect rising costs, EDF has argued. Elchin Mammadov, European utilities analyst at Bloomberg Intelligence, says that nuclear is having a hard time competing in the power market where there is a lot of renewables coming online, coal prices are falling and demand is weak. If nuclear is having a hard time, especially in nuclear-friendly France, one can surmise that fossil fuelled generators are having an even worse time.

References

[1]    Matthew Gray: “Coal: caught in the EU utility death spiral”, www.carbontracker.org/report/eu_utilities
[2]    European Wind Energy Association, www.ewea.org
[3]    www.bloomberg.com/news/articles/2015-06-10/edf-nuclear-power-struggles-to-compete-with-falling-market-price

Acknowledgement

This article was published in EEnergy Informer, August 2015, and is republished here with permission.

Contact Fereidoon Sioshansi, Menlo Energy Economics, fpsioshansi@aol.com

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