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Thermal power plants to limit EU power price falls

The European Commission's new EU power market design proposals intended to integrate ever bigger shares of low marginal cost renewables will not lead to a collapse in average EU day-ahead power prices, according to its own analysis.

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Instead, its modelling shows the spread between baseload and peak prices widening to 2050, with thermal plant remaining the marginal price setter for most hours of the year -- though under rather different market conditions from today. The rise and rise of renewables -- particularly renewable electricity -- over the last decade or so has been one of the clearest trends in the EU energy sector.

Watch our related video: EU's power market proposals aim to avoid price collapse by 2030

The EU set itself a ground-breaking binding target to source 20% of its final energy from renewables by 2020, split into 28 diverse binding national targets for each EU country. This, coupled with an overall fall in EU final energy demand, has helped boost renewable energy's share -- including in transport and heating -- from 9% in 2005 to an estimated 16.4% in 2015.

The share of renewables in final EU electricity demand is much higher, an estimated 28.3% in 2015, up from 14.9% in 2005, according to the European Environment Agency. EU power generators and grid operators expect it to reach around 35% by 2020, and around 45-50% by 2030, given the EU's slighter more ambitious 2030 energy and emission targets.

These include sourcing at least 27% of final EU energy demand from renewables by 2030 -- three percentage points above the 24% share expected under current policies.

The EC's new EU clean energy package, unveiled November 30, sets out draft legislation to help achieve this, including a new power market design focused on promoting intraday and balancing trading, more demand-side response, and abolishing wholesale power price caps and regulated retail prices, among other things.

Promoting renewables is part of the EU's wider goals to cut its carbon emissions and improve its energy security by reducing dependence on imported fossil fuels. But one of the most obvious impacts of the policy so far has been the fall in average European wholesale power prices from adding subsidized low-marginal cost renewable generation capacity to an already over-supplied market.

Key EU day-ahead power prices vs EU renewable power share 2005-2016

Renewables are not entirely responsible for the fall in average European wholesale power prices, however. The EC cites other contributing factors such as the fall in coal and gas prices, low EU Emissions Trading Scheme carbon prices, a general recession-led drop in power demand adding to the capacity oversupply in some parts of Europe, and more efficient cross-border trading through coupled markets.

According to the EC's 2016 report on energy prices and costs in Europe, a 1% increase in the share of coal, gas and oil in the power generation mix may add Euro0.2 to Euro1.3/MWh to the wholesale price, depending on the regional market. In contrast, the same analysis suggests that a 1% increase in renewables' share reduces the average EU wholesale price by Euro0.4/MWh.

"The actual reduction depends on the regional market and the fuel source being replaced by renewables," the EC said.

For example, it is larger -- around Euro0.6 to Euro0.8/MWh -- in northwest Europe, the Baltics and central and eastern Europe, it said. The EC does not expect the projected rise in renewables to lead to a complete collapse in EU wholesale power prices in the short and medium term, however.

"Although there will be hours with low (or even negative) prices, the wholesale prices will most probably be set by the marginal thermal generation technology during most hours of the year," the EC said in an impact assessment accompanying its clean energy package proposals.

It expects wholesale prices to fluctuate "within reasonable limits on an EU level" in 2030, though prices in EU countries with very large renewable shares, such as Spain and Portugal, and/or limited interconnections, are likely to be "significantly more volatile" than for their neighbors.

If the EC's proposed measures to encourage more short-term trading and demand-side response are successful, it expects the distribution curve for load-weighted EU day-ahead power prices by 2030 to shift to the left, compared with a business as usual baseline.

Distribution of load-weighted EU day-ahead power prices in 2030


The EC said its analysis does suggest that the new market design will lead to more volatile average hourly prices, driven in part by new locational signals revealing different values of electricity. The extent of this volatility would depend on the overall share of renewables and on how much could be absorbed by storage.

The EC cited its new METIS energy modelling software that it is developing to simulate hourly results for electricity and gas markets and systems operation for a whole year. An analysis using the METIS software found that when solar power generation's share is under 10-12% of total capacity, "solar production coincides with periods of high power demand and tends to smooth out residual demand over the day," the EC said.

This would lead to less variable prices. But higher shares of solar could increase price volatility "significantly" without storage, while wind output "is directly related to variability and a significant driver for flexibility needs."

The EC cites modelling that projects total renewables' share of net EU electricity generation (as opposed to final demand) reaching nearly 60% by 2050. The spread between average baseload and peak day-ahead prices widens from Euro19/MWh in 2020 to Euro67/MWh in 2060, as peak prices increase faster than baseload.

The projected average day-ahead price remains high, with thermal generation still expected to be marginal and thus set the marginal price for most hours.

These projected prices assume scarcity bidding in an energy-only market, where generators recover their costs fully from the market. They also assume in 2020 a 25% rise in coal and gas prices, higher demand driven by economic recovery, and little new capacity investment except in renewables to meet the 2020 targets.

This is very different from current market conditions, where regional overcapacity, low generation-fuel prices and national capacity remuneration mechanisms are impacting generators' returns.

Projected average EU day-ahead power prices vs renewable share 2020-2050


The EC's modelling projected that in an energy-only market -- without capacity remuneration mechanisms -- from 2021 to 2030 some 63 GW of unprofitable capacity would either be retired early or the relevant investment cancelled. About half of this would be coal plants and the other half peaking units or steam turbines using oil or gas. Unsurprisingly, taking out excess supply would boost wholesale prices.

Projected EU day-ahead price impact of 63 GW capacity exit

The main winners in an energy-only market are combined cycle gas turbine plants as the marginal technology, particularly those built after 2025, which "will likely remain profitable over the following 20 years of...operation," the EC said.

Some peaking units could also become very profitable after 2035, when higher renewable shares boost the value of flexibility, the modelling found. These results came with caveats that the profitability of any power plant depends greatly on its fuel and technology costs, and the EU's carbon price.

The EC added that the modelling looked at the individual profitability of plants, while generators usually have a portfolio of different technologies enabling them to hedge risk and improve overall profitability.


The EU will not have an energy-only market, however, as several countries, including big-hitters France, Italy and the UK, have or will soon have national capacity remuneration mechanisms in place.

These guarantee payments for making capacity available when the supply/demand balance is particularly tight, either directly through providing more generating capacity or supplies through an interconnector, or by reducing demand.

The EC has long railed against the risk that such national mechanisms, if badly coordinated, could distort the EU's internal energy market, and keep unprofitable capacity in the market long after it should have been retired.

The EC tackles this issue in its proposals by setting an EU framework for national capacity mechanisms. If approved, all governments would have to use a transparent, non-discriminatory and market-based process to select providers.

Capacity mechanisms would have to be open to all resources, including storage and demand side management if they meet the technical requirements.

An important element for the EC is ensuring cross-border participation is possible, so that generation adequacy is maintained at a regional rather than national level. It proposes that foreign capacity providers have the right to take part in the same competitive process for contracting capacity as domestic providers.

Governments would also be prohibited from restricting their national capacity providers from taking part in other EU countries' mechanisms. The market will have plenty of time to become familiar with the clean energy package proposals, as they have to be debated and agreed by the European Parliament and EU Council, representing national governments, which usually takes at least 18 months to two years.

Many of the provisions will apply two years after that, while some will apply directly from 2020 or 2021, if the current timings are approved. The EC can already influence the design of national capacity mechanisms considered state aid, under the EU's state aid guidelines.

For example, the EC only approved France's capacity mechanism last November after France agreed to make changes, including allowing foreign capacity providers to take part. The EC said this was the first capacity mechanism in the EU to "explicitly include and remunerate foreign capacities."

--Siobhan Hall,