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Renewables face competitive test

image credit: Renewable energy projects face profitability issues amid falling power prices

Energy systems across the world suffered a shock as the Covid-19 health crises forced carbon-intensive industries, aviation and other transport, to a virtual standstill. The effects of the slowdown could result in a stiff test for renewables competitiveness, argues Juan Alario from GNE Finance


The pandemic caught EU countries by surprise. The lockdowns put in place to combat the spread of the virus have sharply reduced both energy demand and prices.

Fossil fuel prices, which were on a downward trajectory since before the pandemic, have sharply declined since end 2019 with gas, coal and oil falling 50%, 35% and 60%, respectively. Similarly, CO2 prices have also decreased by -40% on the back of lower greenhouse gas emissions. This means fossil fuels will become more competitive if the pandemic keeps fossil fuel prices at low levels for a long period, which seems likely.

The levelised cost of renewable electricity today is comparable to fossil fuels electricity in locations with good renewable resources. However, for variable renewables such as wind and solar, their levelised cost is not the right benchmark to assess their competitiveness, because they generate additional costs in order to cope with their intermittence. These costs increase when the share of renewables in the system rises.

The pandemic has increased the share of renewables on the grid because of the lower demand. Flexible resources, such as demand management, network interconnection and storage, aid renewables integration in the electricity system but add to the costs.

As most of the additional renewable capacity will be provided by solar and wind energy projects, the total electricity cost may increase in the medium term, even if the levelised cost of renewables decreases.

The higher cost might be significant: 25-35% when renewables’ share is 50% of the total electricity production and 75% for a 75-80% share, according to recent studies. This cost might be lower if flexible resources can be developed at low costs.


The way renewable energy projects are remunerated has considerably changed over time and varies across the EU. In the case of utility scale wind and solar projects, most EU countries adopted feed-in premiums, and a few apply Contract for Difference (CfD) systems. In the case of feed-in premiums, it receives an additional remuneration on top of the revenues from selling the electricity in the electricity market.

Therefore, if the electricity market prices decrease, because of the pandemic, profitability diminishes as well. A recent new development is corporate Power Purchase Agreements (PPAs) and merchant power plants that can operate out without financial support from the government. They account for a small part of the total. The revenues of those plants can come from selling to electricity consumers through Power Purchase Agreements (PPA) or from selling in the wholesale electricity market. But these projects are highly exposed to electricity price risks and thus the pandemic may affect them substantially, notably merchant power plants.

In principle, periods of low electricity prices should have been considered in the decision to develop a specific project. However, it is unlikely that the sector had foreseen a pandemic, and therefore it cannot be ruled out that some projects will need to restructure their debt or even go into default as a result of the pandemic.

Even if their competitiveness against fossil fuels is negatively affected by falling prices caused by Covid-19, renewables deserve to be supported by governments. It is quite likely that renewables will require more public support than expected before the pandemic, mainly via the electricity tariffs. This will test the commitment of EU governments to fight climate change.

The next challenge is to develop flexible resources at a low cost, if they want to remain consistently competitive.

The views expressed in this opinion are those of the author and do not necessarily reflect the position of FORESIGHT Climate & Energy

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T Conroy's picture
T Conroy on Jul 8, 2020

Well done; two comments:

1. I am interested in research supporting the statement: "The higher cost might be significant: 25-35% when renewables’ share is 50% of the total electricity production and 75% for a 75-80% share, according to recent studies."

2. I do wish the industry would get our terminology consistent. The old coal (and other historical) plants I started up were "intermittent"; they would shutdown ("trip offline") for a myriad of reasons within 300 ms or so. We built our grids to manage these largeoutput generation facility shutdowns. 

The problem we need to manage with wind and solar is "variability", in which output is changing constantly and the plants are not "dispatchable". Intermitency with wind and solar is a trivial or non-existent problem compared to variability.

Alario Juan's picture
Alario Juan on Jul 9, 2020

The source of this figures is Dominique Finon, Evaluer le coût des transitions énergétiques à base de renouvelables: du bon usage des modèles d'optimisation sectorielle. 11/2019 Chaire European Electricity Markets.  The additionnal costs varies depending on the electricity system within the European Union. It is not the same for the Iberian peninsula than for Nordel, for instance. This figures are more representative of the French electricity system.

Alario Juan's picture
Alario Juan on Jul 9, 2020

And thank you for your comments. Variability might be a more appropriate term for wind and solar energy. However, there are different opinions among experts on the best term to use.

T Conroy's picture
T Conroy on Jul 9, 2020

Thank you Alario. Unfortunately the paper does not seem to be available in English. I would have been directly interested. Best regards.

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