Jean-Paul Harreman

Renewables and Emissions Comparison 2023

December 2023

Carbon Intensity of Power Production Down Across Europe

The growth of renewable generation capacity has made a great mark on European power markets in 2023. The percentage of power demand covered by renewable generation has grown, the grid load has dropped, and as a result, carbon emissions caused by fossil fuel power generation are down as well.


The differences between days with the highest and lowest renewable generation share and between the highest and lowest carbon emission days are striking. To illustrate, we have authored this short article.

Europe as a Whole

On average, 46% of European power generation came from solar, wind and hydro in 2023, about 6% more than last year.


The day with the lowest percentage renewable generation in 2023 was 23 February. We see very little wind and solar, combined with a peak demand of around 380 GW, about one fifth of which is filled by nuclear, about 33% by renewables and the rest by fossil fuels. Even on this lowest day of the year, zero emission power generation makes up around half of the total.


On the 7th of August we see fossil fuels being squeezed out of the merit order by a huge solar and wind generation, with nuclear providing the ever-steady baseload underneath. With a peak load of around 300 GW, nuclear again takes one fifth of the total, with renewables providing 58% of the total demand. The shape of gas and pumped storage shows that in this case, balancing supply and demand takes a lot more activity.


In terms of carbon emissions, we see that 2023 emissions from power generation are likely to end up between 15%-18% lower than in 2022, for the first time also lower than during the COVID year 2020.


If we then look at the days with the highest and lowest emissions, we find that demand on the 25th of January peaked at around 425 GW, the lowest emission day was the 3rd of July, with a renewable generation percentage of 56.6% still a very high share of renewables, but thanks to a rainy week before, the run-of-river hydro generation pushed more coal and gas offline than on the 7th of August. The difference is emissions from power generation between these two days is massive, on 25 January over 3.5 times as much carbon was emitted by power generation assets than on 3 July.


We can see that on high emission, low renewable days, the generation profiles are much more stable. This results in more stable prices during the day and more price convergence in the Single Day Ahead Coupling region. In the first image, we see Europe basically break into 4 different price zones.



This is due to the prices reaching relatively extreme levels due to the low renewable generation and high demand. Price differences occur when cross border capacity is too low to efficiently dispatch all assets across cross border connections. Here we basically see from lowest to highest prices: Northern Scandinavia (hydro generation, all countries exporting), Iberia (still had price support for gas generation), Southern Scandinavia and the Baltics (benefitting from exports from the North) and the rest of Europe.


On high renewable days, price convergence is not so easy to detect. As excess renewables need to be transported to regions that need cheap power, cross-border connections are filled to the max, causing the market coupling to run into the maximum limits of the interconnectors.



If we look at the details country-by-country, the differences are much bigger. Local characteristics determine when emissions are high and low, and the composition of the installed generation asset mix, has noticeable impact on when renewable energy sees the highest outturn, compared to the demand for power.


We have looked at several different countries, the main markets in Europe and some interesting small markets, where trends are occurring that we may see in other markets, or that have the potential to affect the whole of Europe.


In Germany, a massive renewable boom has taken place. As Germany was the first country to invest so heavily in wind and solar, it is one of the leaders in Europe in terms of installed capacity. With limited hydro generation and with nuclear assets retired, it depends on fossil fuels when there is no wind and/or sunshine. There is ample generation capacity available and with its central position among European markets, there is also good potential to import if there is cheap power available abroad or export if there is an abundance in the domestic market.


The average share of renewable generation versus demand has grown to 45.6% (YTD 2023), up 5% from the previous year. The amount of carbon emissions reduction for power generation is roughly 17%.



If we compare the days with the highest and lowest renewable percentage, we immediately see the impact of wind power, as wind produced through the evening peak on 15 January, this day turns out to be the day with the highest percentage of renewables versus power demand. During the full day, surplus power was exported. There was a considerable amount of conventional generation, but exports were actually higher than the total fossil fuel generation throughout the day. If we look purely at zero emission generation, and include nuclear power and biomass, this day the whole of the German demand could have been supplied by these sources, without any need for gas, coal, or lignite generation.


During an extremely ‘low renewable day’, like the 30th of November, we see massive amounts of coal and lignite generation, significant imports, and prolonged periods of pumped storage generation. This highlights that the system is not ready to run on renewables and flexible gas assets alone, yet.


If we look at carbon emissions, there is a strange coincidence that the highest emissions day is only 10 days away from the highest renewable generation day and the lowest emissions day is within one month of the lowest renewables day.


Between 15 and 25 January, peak demand rose from roughly 55 GW to 75 GW. The impact of sudden colder weather) pushed the need for more conventional power, 25 January is a classic example of a ‘Dunkelfläute’, a dark, cold period without wind.



On the 4th of November, this year’s lowest emissions day, we see the wind following the shape of power demand very nicely, so that conventional power never has to ramp up through the day. During solar peak and lower demand periods, some exports, combined with pumping water uphill for pumped storage balanced supply and demand and it is fair to say that the fossil fuel assets that were online were mainly running to provide reserves.


This is reflected in the daily average aFRR Capacity prices, which showed a high remuneration for downward capacity during the 4th of November, as plants running out-of-merit, had to compensate for providing additional downward capacity, by running at a higher than minimum level.



On the 25th of January, the reverse applied. All assets were running close to maximum output, which meant that additional upward capacity was scarce and expensive as it could also be sold in the day ahead market at a high price.


The French market sees a massive amount of nuclear power and is highly sensitive to cold temperatures. Demand shoots up when the temperature goes down in winter and when no renewables are available, the gap is filled with gas generation and pumped storage, as well as some reservoir hydro. The percentage of solar and wind versus demand is much lower than in Germany, however the nuclear generation ensures that the total zero-emission generation is much higher. France has seen an acceleration of renewable development after the COVID-crisis, resulting in an average share of 28% of renewable generation vs demand in 2023, up 6%. Emissions are down massively vs 2022, which was a record year for carbon emissions in France. The massive nuclear capacity problems forced emissions up by around 20% versus 2021. This year, thanks to the return of nuclear and the growth of renewables, emissions are projected to be down by 30% year-on-year.


The lowest percentage renewable generation day was 21 February, where CCGT’s picked up the slack from renewables. On the 5th of November more zero-emission power was generated than France could use itself. Only around 1.300 MW of gas was kept online for balancing purposes. This day saw massive exports to surrounding countries.



The highest emissions day in France was the 25th of January, where demand peaked close to 85 GW, which is double of the lowest emissions day, 15 October, where demand peaked at a mere 42.5 GW. On the 25th of January, also seen in Germany as the highest emissions day, lack of wind and solar prompted the use of gas, coal, oil fired generation and massive imports through the day. On the 15th of October, there was an excess of power available, nuclear plants were ramped down during the solar peak and the system so only small volumes of hydro, gas and pumped storage being needed.


Fossil fuel generation did not exceed 500 MW at any time of that day, the lowest emissions day in France produced only 4% of the emissions of the lowest emissions day in Germany.



Spain has seen tremendous investment in renewables in the last 10 years. It boasts significant capacities of solar and wind generation. The growth of renewables is reflected in an ever-increasing percentage of renewables in the generation mix, in 2023 this percentage vs demand increased from 47% to 56%. Thanks to lower demand and increasing renewables, the emissions have decreased around 23% year-on-year, as far as power generation is concerned.


With the growth of renewables, other issues also start to affect what happens in the power market. During the day with the lowest percentage of renewable generation, we see a strange shape for solar generation. The peak of solar generation is ‘shaved’ off the top, because of grid congestion issues. Flexibility in Spain mainly comes from CCGT (combined cycle gas turbines) and other gas assets, which were running flat-out that day.



In the day with the highest renewable percentage, we see renewables massively over-generating during the solar peak and we see a similar impact of curtailment. There is still a sizeable portion of gas generation running during this day, much of which was exported through France and Portugal. Up to 6.5 GW of exports, maxed out all the interconnectors.


The highest emissions day was 24 August, a summer’s day with high demand is not an exception in Spain, due to high power consumption because of air conditioning. The difference in peak demand between the highest and lowest emissions day is about 10 GW, a massive difference in a market like Spain, almost 40% of the average demand. This massive variance has a big effect on CCGT generation. Interestingly, the highest emissions day saw exports, whereas during the lowest emissions day, the solar generation was limited (and not curtailed), it was the massive amount of wind and hydro power, that made the 4th of November the lowest emissions day in Spain.

Great Britain

In Britain, renewables increased their share of demand from 36.5% to 40% in 2023, as demand decreased as in many other European countries, the drop in carbon emissions from power generation is projected around 15% versus 2022. What is interesting about GB is that as an island system, it still depends on conventional power to provide inertia to the grid. Therefore, we see that the day with the highest percentage solar, wind and hydro had a 68% share versus demand of these sources. Where Spain and Germany scored well above 80% for their ‘most renewable’ days. Thanks to being in the synchronous European area, Spain and Germany’s grids can cope with larger volumes on non-synchronous generation.



In all cases, with high renewables, low renewables, high emissions, or low emissions, we see that GB imports from the continent for at least part of the day. On 3 December, we saw the highest emissions day so far, with some coal plants running to satisfy the high demand during a cold spell. On 24 March we saw the day with the lowest emissions, low demand on a mild day, with lots of wind and imports ensured an exceptionally low share of gas generation, with coal being offline.



Data sources used for this article are ENTSOE Transparency and EnAppSys models, where data is missing or unreliable. The results are an approximation, because a bullet-proof calculation is not possible based on the data available. Note that for renewable energy sources we have used solar, wind and hydropower. We see a discrepancy between demand and total generation, which is due to small scale generation, this does not report its output through transparency regulations.