This document is a translation of
Over the past 15 years, most European countries have been attempting, to a various degree, to increase the share of intermittent renewable electricity sources (iREL) in their electricity mix, mainly with wind and solar photovoltaic (PV). The official goal is to significantly reduce the CO2 emissions of these countries and also to improve their energy independence.
The present study of a set of 15 Western European countries that are similar in their sociology, technology and economy shows that this policy breeds poor results...
Wind and PV Power, CO2 Emissions, and Electricity Prices for Households in Western Europe
* Former head of the Geology-Geochemistry Department of the IFPEN (Institut français du pétrole et des énergies nouvelles), subsequently head of the ENS of Geology (École Nationale Supérieure de Géologie). Former president of the scientific committee of the European Association of Geoscientists and Engineers.
This document is a translation of
Over the past 15 years, most European countries have been attempting, to a various degree, to increase the share of intermittent renewable electricity sources (iREL) in their electricity mix, mainly with wind and solar photovoltaic (PV). The official goal is to significantly reduce the CO2 emissions of these countries and also to improve their energy independence.
The present study of a set of 15 Western European countries that are similar in their sociology, technology and economy shows that this policy breeds poor results:
- The reduction of CO2 emissions from electric power generation over this time period is due to the progressive replacement of coal-fired plants by combined cycle gas turbines (CCGT) rather than to iREL deployment. In fact, the countries with low emissions are those whose electric mix relies mainly on hydro and/or nuclear power. These did not need to increase their iREL to reduce their emissions.
- The price of electricity charged to households in these countries increased in direct proportion to the iREL installed capacity.
- Finally, the development of iREL in countries that do not enjoy significant amounts of hydroelectricity and/or nuclear power requires that large backup capacities, i.e. coal-fired or gas-fired power plants, remain available to fill in for iREL intermittency. As long as we don't know of a way to store the enormous amounts of electricity involved, and it seems a solution is far off, these power plants will remain necessary. The deployment of iREL in these countries will thus, far from reducing their energy dependency, bind the future of their electricity production, including that from iREL, to the availability of those two fossil fuels. As their production is declining rapidly in Europe, except for brown coal in Germany, the future of electric power production as well as that of the iREL in the countries considered will be increasingly subject to the availability of imported coal and gas.
If, indeed, the present policy to forcefully develop iREL is motivated by climate or economic considerations, as the political circles and the media claim, then it is a serious mistake. It does not significantly reduce CO2 emissions. It is expensive for households. Given the lack of sufficient storage capacity, it threatens the stability of the European electric grid. In France, where the CO2 emissions are already among the smallest of the large industrially developed countries, it will increase emissions. It will also increase the price of electricity for households. It will make France increasingly dependent on imported gas and coal.
Moreover, this energy policy will annihilate the comparative advantage over other industrialized countries that France enjoys in being able to set up an electrically powered, oil free and, more important, practically CO2 free, transportation system. This asset is invaluable in view of the concerns over climate change, the increasing uncertainty regarding the future availability of oil on international markets and the 50% decline in its production in Europe since the beginning of this century.
Over the past 15 years, European countries have been attempting, to a various degree, to increase the share of intermittent renewable electricity sources (iREL), mainly wind power and solar photovoltaic (PV), in the electricity they generate. These efforts are justified officially by the need to mitigate global warming and, as a consequence, to reduce CO2 emissions, these being held responsible for most of the warming. True, these iREL, just like hydro and nuclear power, contribute little per se to these emissions, as opposed to fossil fueled electricity generation (figure 1).
Figure 1: Greenhouse gas (GHG) emissions, in kilotonnes-CO2 equivalent per TWh (= g/kWh) of electricity generated in North America by mode of production, calculated using the Life cycle analysis (LCA) method. Source: Hydro Québec, http://www.hydroquebec.com/developpement-durable/centre-documentation/pdf/15094E.pdf
Another reason invoked to justify these efforts is the reinforcement of Europe's energy independence.
The means used to push the deployment of iREL consist in, on one hand, their intense promotion in the eyes of the public via political circles, the media, and industrial lobbies, and on the other hand, the handing out of considerable financial benefits to these electric power generation modes, via absolute priority access to the grid and very lucrative feed-in tariffs (FIT) guaranteed to the producers by long-term contracts.
These privileges, which depart from the principles of fair competition in a market economy, have been granted on the grounds that they would allow time for these electricity sources to acquire sufficient maturity to become fully competitive on the market. Wind and solar PV power were supposed to eventually not only do without subsidy but also generate income for the general public at the end of this process. But the moment is still not here.
The deployment of iREL took up speed in virtually all the European countries, although at different rates, at about the same time around year 2000. We examine, then, if 15 years down the road, the elimination of GHG emissions by the electricity sector thanks to iREL deployment is, if not fully effective, at least in sight.
We examine also the consequences of this deployment on the price of electricity charged to households.
We limit our study to 15 Western European countries because, in our view, they constitute a rather homogeneous group sociologically, technologically, economically though they differ widely in the intensity of their iREL deployment.
The sources for the data used in this study are: The International Energy Agency ((www.iea.org, Statistics section) for gross electricity production and its generation modes (electricity mix) ‒ The European Network of Transmission System Operators for Electricity (ENTSO E) (www.entsoe.eu/db-query/miscellaneous/net-generating-capacity ) for power generation capacities ‒ The European Environment Agency (EEA) (EEA 2016, ENER 038 Overview of electricity production and use in Europe http://www.eea.europa.eu/data-and-maps/indicators/overview-of-the-electricity-production-2/assessment) for CO2 emissions from the gross production of electricity, excluding Norway and Switzerland ‒ Eurostat (http://ec.europa.eu/eurostat/data/database) for the prices charged to households ‒ British Petroleum Statistical Review of World Energy 2016 (https://www.bp.com/content/dam/bp/pdf/energy-economics/statistical-review-2016/bp-statistical-review-of-world-energy-2016-full-report.pdf) on the history of fossil fuel production and consumption.
1 - The electricity mix of the 15 countries considered
The electricity mix of a country is the distribution of energy sources used to produce the electricity as a percentage of the total electrical energy (measured e.g. in kWh, MWh, or TWh) produced by each of these sources. In this study, we consider only the gross production of electricity, without deducting the losses due to plant self-consumption, the losses on the grid, or the balance of exports-imports.
The gross electricity mix of the 15 countries differs widely (Table 1): historically, each mix has been largely determined according to the availability of local resources, guaranteeing a minimum of energy independence. Thus, in Norway, the country that enjoys the most favorable per capita hydraulic resources in Europe, hydroelectricity represents 96% of its electricity generation. The UK, which is poor in hydraulic resources but was rich with coal for a long time and then with gas from the North Sea still generates most of its electricity with these two fossil fuels. Germany too, has poor hydraulic resources but it is rich with coal (now mostly brown coal, the kind of coal whose massic energy content is the smallest and, as a consequence, its CO2 emissions per kWh the largest) that it uses to produce a large fraction of its electricity. France whose per capita hydraulic resources are small compared to those of Norway, or even those of Austria, Sweden and Switzerland, and whose fossil fuel resources are small, has strongly developed nuclear power. In all these countries and since the 1973 and 1979 oil shocks, oil is practically no longer used to produce electricity. The shares of iREL in the 15 countries' electricity mix differ widely. In 2014, the last year considered in this study (barring a few exceptions) for lack of reliable data beyond, they range from 1.6 % in Norway to 42.6 % in Denmark, its neighbor.
Table 2, shows, for each of the 15 countries in 2014, the population in millions and the per capita production capacity at the end of the year of each main mode of generation, in watt per capita.
A combination of tables 1 and 2, yields Table 3 where the annual load factor is evaluated for each mode of electricity production, i.e. the ratio of the effective production to the amount that would be produced at full nominal capacity all year round. The global efficiency of the electricity mix of each country or that of each production mode can also be compared. This shows that France produces on average, roughly 1.3 times more electricity than Germany for each installed power unit. It shows also that Germany produces roughly 7 times more electricity with its nuclear plants than with its wind and solar PV combined for each watt of per capita installed power! For France, this factor is only 5 because nuclear plants are used not only for base load generation as in Germany, but also do load following.
Table 3: Gross electricity production in kWh per capita, total installed capacity in watt per capita, mean load factor of this production, and load factors of the main production modes. Note the wide range of per capita electricity productions from Italy to Norway and the overall good performance of nuclear production. The load factor of solar PV in Portugal seems too high. A load factor similar to those of Italy and Spain might be closer to reality. Wind and solar PV load factors can anyway be imprecise, because their capacities are growing quickly. Therefore consistent errors could be incurred if calculations were not made with a precise step by step reconstitution of capacities and productions.
2 - iREL deployment, CO2 emissions and price of electricity charged to households in Western Europe
Table 4 shows for year 2014 the proportion of iREL (wind and solar PV) in the gross electricity production mix, and its CO2 emissions in million tonnes and in grams per kWh of electricity produced, along with the price of electricity charged to households in euros per MWh for the 15 countries considered. It also shows, in watts per capita, the total installed iREL power. The relations between these quantities appears more clearly in figures 2 and 6.
iREL and CO2 emissions
Figure 2 shows, for the 15 countries considered and for year 2014, the CO2 emissions due to the gross electricity generation versus the iREL proportion in the mix. Note the generally positive correlation between the two quantities. The question, then is: while iREL and in particular wind, emit little CO2 per kWh generated (see Figure 1), why do the CO2 emissions of the countries considered increase overall with the fraction of iREL in their electricity mix?
The sole determining factor of CO2 emissions is of course the share of fossil fuels in the electricity mix, and their type (gas, coal, oil). Of these 15 countries, only 5 viz. Austria, France, Norway, Sweden and Switzerland have managed, so far, to do almost without fossil fuels in their electricity mix so that the CO2 emissions from their electricity production are very small. One of these countries, Norway, is graced with exceptional per capita hydroelectric resources (see Table 2) which generate 96% of its electricity. Austria too is well endowed, with 70% hydroelectricity in its production mix. It complements its mix with fossil fuels and biomass so that it has the highest emissions of the 5 countries. The mix of the three others, France, Sweden and Switzerland is based mainly on nuclear and hydroelectricity so that they use even less fossil fuels than Austria. Sweden and Switzerland, enjoying better per capita hydroelectric resources than France, rely even less than France on fossil fuel-fired plants, so that their CO2/kWh rate is smaller.
Then comes Finland which has nuclear and hydroelectricity in its mix, but still not enough to sufficiently eliminate fossil fuels.
Rightly, these countries have relatively little iREL in their electricity mix. Indeed, they do not need it to significantly reduce their CO2 emissions : emissions from the first five are already very low and Finland, which is less well placed for the time being, is continuing to develop its fleet of nuclear power plants. It will soon catch up with the leading group. Nevertheless, Sweden has a relatively large proportion of iREL and apparently intends to increase it further (Table 1).
Figure 2: CO2 emissions, in grams per kWh, of the electric mix versus the proportion, in %, of wind & solar PV in this mix for the 15 countries considered. Circles filled with red, France, black, Germany, orange, the Netherlands, green, Denmark and yellow, the average of the 15 countries considered.
At the other extreme, four countries have very large CO2 emissions: the Netherlands, the UK, Germany and Ireland. They share having a very small amount of hydroelectricity. In 2014, two of them still had a significant proportion of nuclear power in their electricity mix, the UK (18.8%) and Germany (15.4%). Their emissions are somewhat lower than those of the Netherlands, which has very little nuclear (3.9%) and Ireland which does not have any at all. In spite of having a much bigger iREL fraction (19.5%) than the Netherlands (6.4%), Ireland's CO2 emissions are somewhat larger than those of the Netherlands.
Four countries are in intermediate situations : Belgium, Italy, Spain and Portugal. Belgium has no hydroelectricity to speak of, but has a large proportion of nuclear power (46.4%). The three others have significant per capita hydroelectricity resources; though smaller than those of Austria, Sweden, Switzerland and of course Norway, they are larger than those of France. Note that Spain's mix includes a significant fraction of nuclear power (20.4%).
Finally Denmark deserves special attention: it has no nuclear power; it has no hydroelectricity. However, its small size and its geographical position allow it to manage the intermittence of its iREL (mainly wind) using the large hydraulic storage resources of its Swedish and Norwegian neighbors. As we shall see, Denmark can then introduce a large iREL proportion in its electricity mix without being confronted with severe technical risks, and can thus reduce the CO2/kWh rate of its gross electricity production. It only needs to be able to help itself to hydroelectricity from its northern neighbor and fossil fueled electricity from its southern neighbor. However, if, like Ireland, Denmark had been electrically isolated, it would not have been able to equip its mix with such proportions of iREL (42.6%) and its CO2 emissions per kWh would be much larger. Denmark thus enjoys a niche situation. Economic considerations, which we will address later, set aside, Denmark's mix cannot be extrapolated to the rest of Europe whose hydraulic resources are much too small to sustain such iREL proportions in its electricity mix without resorting to conventional (fossil or nuclear) production means to ensure the stability of the grid.
Thus, the situation varies a great deal from one country to the next. The Europe of electricity does not exist, there are often good reasons for a country not to align its electric mix with that of its neighbor. Of course, this discussion shows that it is by reducing the share of fossil fuels in its electricity mix, and in particular that of coal (whose CO2 emissions per kWh produced are about twice as large as those of gas (figure 1)), that a country can reduce the CO2 emissions from its electricity production. The countries which, because of their geography, enjoy large per capita hydraulic resources have a great natural advantage here. For those countries which do not enjoy such resources, nuclear power is clearly much more efficient than iREL in reducing their CO2 emissions. The reason for this is simple: the intermittence of the iREL has to be managed and this requires backup power that is provided by "conventional" power plants capable of producing much more electricity in the year than the iREL. Indeed, barring access to massive storage capacities which are today not accessible in sufficient amounts at the European scale, and probably will not be for a long time (see Appendix 1), it is not possible to have an iREL proportion much larger than their load factor in an electricity mix; in Germany, for example, this was 14% for wind & solar PV combined and in Denmark, 28.5%. In the absence of sufficient hydroelectricity and/or nuclear power, the backup must be provided by fossil fueled plants, which generate large amounts of CO2.
In Western Europe, the five countries that have relied most heavily on wind and/or solar PV power for their electricity production are Germany, Denmark, Spain, Ireland and Portugal. It is therefore interesting to compare the evolution of the CO2 emissions from their electricity production during the years of intense deployment of these sources of electricity, i.e., since year 2000, with those of countries that relied on nuclear power and hydroelectricity: none of these countries, in spite of boastful declarations by the media, environmental political parties and NGOs has managed to reduce its emissions to the levels of France and a fortiori of Sweden, and that by a long shot (see Figure 3). Of those countries, Denmark has the best performance. The reasons for this have been mentioned above and will be discussed in greater detail below.
However, there is a very significant gradual decline of the emissions of these five countries over time. A general remark can be made that puts the progress displayed by these decreasing curves in perspective: in terms of reducing CO2 emissions, the first step is always the easiest. Thus, the worse the performance, the easier it is to find ways to improve. A comparison in terms of a percentage gain over a given time period of one country with another thus has little meaning if the initial situation is not considered. Moreover, for the climate, what counts is the total CO2 emissions. This said, the progressive decline of these countries' emissions is quite visible. The question is what it is due to. First, it is due, for a small part, to the progressive improvement of the energy yield of fossil fueled power plants. However, some of the more noteworthy gains (in Spain, Ireland, Portugal) result essentially from a progressive switch-over of power generation from coal to gas, whose CO2 emissions per kWh are much smaller (see Figure 1). Besides, Portugal and, to a lesser degree, Spain have significantly increased their hydroelectric production since year 2000; Portugal by 40% and Spain by 15%. Germany alone has not really made any progress, because it has too little hydroelectricity and still relies heavily on coal (45.4% of its power generation in 2014 (see Table 1) with about half of it based on brown coal, the kind that emits the most CO2 per kWh generated); little progress, then, in spite of massive iREL deployment. Note that Germany and Spain are still operating a few nuclear power plants. What will happen if they are (Spain) or when they will be (Germany) shut down?
Figure 3:Evolution between 2000 and 2014 of the iREL proportions in the gross electricity production mix in % (left panel) and of the CO2 emissions from this production in grams per kWh (right panel) for the European countries with the largest wind and/or solar PV deployment, compared to the same quantities for France and Sweden which rely mainly on nuclear power and hydroelectricity.
Figure 3 shows that, of the five countries, Denmark is the most successful in reducing its emissions although it has no nuclear power and virtually no hydroelectricity. Still, it continues to rely a lot on coal so that it is one of the worst per capita polluters of the European atmosphere. However, though its hydroelectricity potential is practically non existent, it can manage the intermittence of its wind power by calling on the "storage batteries" of its neighbors: it is mainly the hydroelectric plants of Norway and Sweden that serve this purpose. This represents a financial cost for Denmark (low priced exported kWh, expensive imported hydraulic kWh) but it lifts technical issues and allows a large proportion of wind in its gross electricity production mix (42.6% in 2014). Nevertheless, the proportion is much smaller (roughly 27% in 2014, i.e. about the mean load factor of wind+solar PV) in its gross consumption mix, since it exports a large part of its wind production and imports hydroelectricity! And, of course, it also imports, in quantities that are difficult to evaluate, nuclear electricity from Sweden, but also from Germany and France via its interconnections with Germany.
The decline of its CO2 emissions is most pronounced from 2008 on. As we will see below, this phenomenon is correlated to the rapid increase of its electricity imports from that date, coupled with the resumption of wind turbine construction, which had stagnated from 2003 to 2008 as shown in Figure 4 below.
Figure 4: Evolution, in MW, of installed wind capacity in Denmark from 2000 to 2015 on December 31 of each year. Note the small quantity of new installations between 2003 and 2008. Data Energinet, Denmark. Courtesy Bjarke Nielsen.
If such a system can work at the scale of a small country like Denmark, surrounded by large neighbors to which it is connected with significant transfer capacities, it cannot be considered at the EU28 scale. For example Germany produces 20 times more electricity than Denmark. Were it to have the same percentage of iREL in its mix, Germany would need the help of 20 Scandinavias! The Danish performance, though it is celebrated by the media, is thus only a trompe-l'œil. In fact, it would be more appropriate to refer this wind production to the total Scandinavian electricity production rather than to only that of Denmark. As previously stated, and this will appear better through a comparison with Ireland, Denmark enjoys a niche situation, its system cannot be generalized to Europe as a whole.
Sweden has a better performance than France. This is because it relies less on fossil fuels to produce its electricity (Table 1). Also, it can rely on wind a little more than France, and manage the intermittence thanks to its abundant hydroelectricity resources, rather than by burning fossil fuels.
France, then, owes its good performance to the fact that, like Sweden, it relies little on fossil fuels for its electricity production and relies mainly on nuclear power and hydroelectricity. Thus, in 2014, France has emitted 12 times less CO2 per kWh produced than Germany! Indeed, despite its uninterrupted development of wind and solar PV for the past fifteen years, our neighbor still uses about the same amount of fossil fuels, coal in particular. Figure 5 shows that the progression of the iREL has had very little effect on the CO2 emissions of its electricity mix.
In all probability, the impact of Germany's energy policy on public health in Europe is considerable, an impact that some NGOs have attempted to quantify in a recent report (http://awsassets.wwfffr.panda.org/downloads/dark_cloud_full_report.pdf; see also https://vimeo.com/172886975).
Figure 5: Germany between 2000 and 2014 - Evolution of the iREL proportion in the electricity mix (blue curve, vertical axis in %) and CO2 emissions of this mix (red curve, vertical axis in 100g/kWh).
The damage is caused mainly by the fine particles and sulfur and nitrogen oxides emitted by fossil fuel-fired power plants, particularly coal and brown coal-fired plants. Since atmospheric movements do not recognize borders, Germany, as well as other countries (Poland for example), which produce a large part of their electricity with fossil fuels, export this dangerous pollution to neighboring countries. Among these, France, where the report mentioned above ventures an evaluation of the additional mortality due to these undesirable pollution "imports": 1000 premature deaths per year just because of coal mainly from Germany, the UK and Poland.
In the Western European countries with significant iREL development, iREL has probably reduced CO2 emissions in those countries where the electricity mix rested essentially on fossil fuels. However, this positive effect is marginal as the European statistics show. Actually, when it occurred , it was the shift from coal to gas in the electricity mix that played the most decisive role in the observed decrease of the emissions. Extending these countries' experiments to other nations may thus turn out to be just as disappointing.
Incidentally, note that the countries which engage in these iREL massive deployment policies de facto bind the future of their electricity production to fossil fuels, along with the CO2 emissions and atmospheric pollutants that come with them, but also expose themselves to potential future supply problems. This could change if very large electricity storage capacities became available with which to manage the iREL intermittence. But, as discussed in Appendix 1, this is totally unrealistic today and no solution is on the horizon. For countries like France, whose electricity mix generates very little CO2, there is no point in developing iREL since it cannot significantly reduce emissions that are already very small.
iREL and price of electricity charged to households
Figure 6 summarizes the numbers of Table 3 for the 15 countries considered: the left panel shows the price charged to households versus the iREL proportion (%) in the electricity mix and the right panel shows the price charged to households versus the installed iREL capacity in Watts per capita. Note the positive correlation: the electricity is all the more expensive that the iREL proportion or the iREL installed capacity is large. This correlation is even more obvious with the watts per capita installed capacities than with the iREL proportion in %.
Figure 6: 15 Western European countries in 2014 : price of electricity charged to households in €/MWh versus the iREL proportion (%) in the electricity mix (left panel) and price of electricity charged to households in €/MWh versus the iREL installed capacity in watts per capita (right panel). Circles filled with red, France, black, Germany, orange, the Netherlands, green, Denmark and yellow, the average of the 15 countries considered (overlayed on Portugal in the right panel).
The highest prices are those of Germany and Denmark. However, the Danish prices are barely higher than those of Germany while its iREL proportion in the electricity mix is much larger! But note also that this disparity is much reduced when the prices are compared to the installed capacities. This is due to an iREL load factor (the ratio of the amount of electricity effectively generated over the year to the amount that would have been generated had the conditions been of nominal operation over the year) difference: the load factor in Germany is half that in Denmark, with 14% in 2014 for wind & solar PV combined in Germany versus 28.5% in Denmark. Indeed, the iREL fleets of the two countries have different characteristics: about half of the German fleet, compared with only 10% of the Danish fleet, consists of solar panels (Table 2), with an annual load factor approximately half that of wind. Moreover, the wind is on average much more favorable in Denmark than in Germany, a continental country which enjoys winds with an average speed comparable to those of Denmark only on its Baltic Sea coast. In addition, by relying on the hydroelectric equipment of its Scandinavian neighbors, little Denmark (little in terms of the amount of electricity generated, of course) can afford to have a much larger wind production capacity than it could have if it were electrically isolated. Its capital and infrastructure expenditures per unit of iREL capacity are nevertheless about the same as those of Germany.
Sweden and Norway buy (at low cost) Denmark's temporary wind electricity surplus so that they can save the water that they would otherwise have used to satisfy their own demand and keep it in the dams. Conversely, they provide hydroelectricity (at high cost) when the wind in the North Sea is insufficient. This cannot be contemplated for Germany, the water resources of the whole of Europe would not be sufficient.
In Germany, during the years 2000-2014 (Figure 7, left panel), there is a strong correlation between the electricity price increase for households and the progression of the iREL proportion in the electricity mix.
Figure 7: Germany (left panel) and France (right panel) 2000-2014: price of electricity charged to households versus the iREL proportion in the electricity mix in %. Note, for Germany, a quasi linear correlation with a 6.4% price increase per iREL proportion percentage point. For France, the price increases quasi linearly beyond a 1.5% iREL proportion.
This correlation appears also for France beyond a 1.5% iREL proportion though the contribution of iREL to the mix is much smaller (Figure 7, right panel). Although the electricity price increase in France has had other causes than the deployment of iREL, it must be noted that the price of electricity there increased by about a third from 2009 to 2014 for a 2.6% iREL proportion increase. The slope of the upswing since 2009 is thus even steeper than in Germany!
Figure 8 shows the variation between 2003 and 2014 of the electricity prices in the 5 Western European countries with the most iREL in their electricity mix, along with, for comparison, those of France and Sweden that have a small iREL proportion.
Figure 8: Evolution of the price of electricity (in €/kWh) charged to households for the 5 Western European countries with the most iREL in their electricity mix along with, for comparison, those of France and Sweden. The data prior to 2003 are available only for France and Germany.
Electricity prices in a country are formed in a complex process that depends partly on public policies but also on the price of raw materials, fossil fuels or uranium. The increase in electricity prices observed in Western Europe in recent years therefore does not depend solely on the proportion of iREL in the electricity mix. However, the correlations observed and particularly the price differences according to the relative weight of iREL in the mix show that the iREL proportion plays an important role in determining the price. This is easily understood: in order to be usable within an integrated network that does not have sufficient storage capacity (as in Europe today and for a long time - see Appendix 1), iREL production cannot do without backup from "conventional" power plants.
iREL capacities thus do not substitute for existing conventional capacities that are still necessary to the grid but, for the most part, add to them. From this point of view, Germany is a striking example: according to the European Network of Transmission System Operators for Electricity (ENTSO E), Germany's total installed capacity, all modes combined, increased in rounded figures from 104 GW in 2000, including 2.6 GW of iREL, to 188 GW in 2015, including 82 GW of iREL (see Figure 9). The iREL development has almost doubled the electricity capacity of Germany in 15 years! For France, the corresponding values are 111 GW, of which 0.2 GW of iREL in 2000, and 129 GW, including 17.4 of iREL, in 2015. The capacity increase in these two countries is due almost solely to iREL deployment and the "conventional" plant capacity has globally not been reduced.
Figure 9: Evolution between 2000 and 2015 of the net electricity production capacity in Germany (left panel) and France (right panel) in GW: we show total capacities, and the capacities in nuclear, fossil, hydroelectricity, total "new renewables", i.e. iREL+biomass and waste, and the share of iREL alone from 2009 (ENTSO E does not give the detail before then). Note Germany's rapid total capacity increase, due mainly to iREL development. Note also the discontinuities in the increase of new renewables and of fossils after Fukushima and the succeeding reduction of nuclear in 2011. In France, the total capacity increases after 2008, mainly because of iREL, and there is a slight decline of fossils after 2013.
On the other hand, the amount of electricity generated did not change significantly in the two countries since 2005 except for a sudden dip in 2009 because of the economic crisis, followed by an approximate return to previous values. With a total conventional power plant capacity that has not changed, the increased iREL production thus came hand in hand with reduced conventional power plant production, i.e. a reduced overall load factor of those conventional plants.
In other words, for the same service (providing electrical energy to the citizen) the capital expenditure has been massively increased. Moreover, reducing the output of conventional power plants has increased the price of the kWh they produce since their fixed costs remain the same for a lesser production. Finally, adapting the grids and building the new high voltage lines that are necessary to the insertion of the iREL further increases the cost. Someone has to pay for all this. At the end, whatever the mechanism adopted, it is always the consumer.
Note, on Figure 8, that the price of electricity in Sweden is notably higher than that in France. Correlatively, the iREL installed capacities in Sweden are now nearly twice those of France (see Table 3).
Three very different countries: Denmark, Ireland, France
Finally, we compare with France two countries that have developed iREL to a great extent, and do not call on nuclear power nor do they have any hydraulic or fossil fuel resources to speak of. France, too, has practically no fossil fuel resources. But it has widely developed its nuclear power fleet and enjoys a good hydroelectricity fleet (rivers and dams, including 5 GW pumped storage hydroelectricity (PSH). Far from being negligible, this hydroelectricity remains limited, since, depending on the year, it can provide only between 10 and 15% of today's gross electricity production.
The gross production of electricity and the population of Denmark and Ireland are comparable (see Tables 1 & 2). Nevertheless, Ireland, as opposed to Denmark, does not have much electrical interconnection with the rest of Europe.
Denmark has no nuclear power. Nor does it have hydraulic resources. It has no coal. It has some oil and gas resources in the North Sea but they are running out. Very early, it has had efficient electricity connections with its Scandinavian neighbors, Norway and Sweden and also of course, with its big German neighbor. The Danish electric system presents a peculiarity: the interconnections between its western part and its eastern part have a small 600 MW capacity, so that they are almost electrically independent from one another. The western part, though, is well connected to the inter-Scandinavian electricity grid, and constantly exchanges electricity with Norway and Sweden, while the eastern part is well connected to Germany, with which it also exchanges constantly.
Figure 10 shows the evolution between 2000 and 2014 of the iREL proportion in Denmark's electricity mix. This proportion, comprising mainly wind since Denmark has little solar PV, had already reached more than 10% in year 2000. Between 2007 and 2010, it seemed to settle at an upper value slightly below 20% but it then began to rise steeply again, exceeding 40% in 2014.
Figure 10: Denmark: evolution between 2000 and 2014 of the iREL proportion in % in the gross electricity production mix (green curve), of the CO2 emissions from this mix in tens of grams per kWh (red curve), of the gross electricity production in TWh (blue curve), of electricity exports in % of the gross production (black curve) and of imports in % of gross production (orange curve). Note the wide fluctuations of the imports (orange curve), as well as their overall increase over this period. Note also that the low points in the imports curve match the high points in the CO2 emissions curve (red curve). The CO2 emissions decrease markedly after 2008, in concordance with increased imports, a decreasing gross production and an increasing iREL share.
Figure 10 shows the exceptional volume of electricity exports and imports relative to gross electricity production. The electrical Denmark can survive as it is only thanks to its neighbors that absorb its surplus and supply its demand when the wind fails. Since 2003, its exports have been fairly steady at around 30% of the gross production, while its imports have fluctuated widely with an average below the level of exports until 2008, to later reach a level higher than exports. In 2014, the imports to exports balance represented 9.3% of the final consumption. It reached 16.7% in 2012! Correlatively, as previously discussed, there is a marked downturn of the CO2 emissions but their high points coincide with lower points in the imports curve. The more the country relies on its own resources, the more CO2 it produces! These are the effects of the real symbiotic situation of this country with its Scandinavian neighbors, Norway and Sweden. It is this symbiosis, in particular the availability of considerable hydraulic resources in the Scandinavian countries, that allows Denmark to boast both a record iREL level in its electricity mix and CO2 emissions significantly lower than those of other countries where iREL have been strongly developed.
In 2015, Denmark's interconnection capacity with its neighbors was increased from 5 GW to 6 GW allowing its exports to increase further. A 1 GW link with the Netherlands is being prepared. By comparison, France's connections with its neighbors are barely double those of Denmark, with an electricity production about 17.5 times larger. A Danish style electricity production system is unthinkable for France and it would be unmanageable: 17 Scandinavias would be needed to accept a similar proportion of iREL in its power generation mix.
Denmark also uses a lot of biomass as an addition to coal in its coal-fired power plants.
Thanks to imports, Denmark was able to very significantly reduce the proportions of coal and gas in its electricity production mix. A strong correlation between the evolution of CO2 emissions and that of the coal fraction in the mix can be observed as shown in Figure 11.
Figure 11: Denmark: evolution between 2000 and 2014 of the coal proportion in % of the gross electricity production mix (black curve), of that of gas (yellow curve), of that of imports (orange curve), and of CO2 emissions in tens of grams per kWh (red curve), to be compared to the iREL proportion (green curve).
Ireland produces about the same amount of gross electricity as Denmark (Table 1). Its population is about the same size (Table 2).
Like Denmark, Ireland has no nuclear power and no significant hydraulic resources. Its fossil fuel resources are even less than Denmark's.
Note (see figure 12), that Ireland is a net electricity importer but its exchanges with abroad are much smaller than those of Denmark. From 2000 to 2014, the iREL share in its electricity production mix increased from practically 0% to 19.5%. Over the same time period, the price of its electricity more than doubled (see figure 8).
Ireland is an island which, although not completely isolated electrically, is connected to England by only two 500 MW interconnections: one, Moyle, was created in 2001 with Scotland via Northern Ireland, and the other, East-West, was created in 2012 between Ireland and Wales. It should be noted that the latter underwent lasting damage last September 8, damage that led to limiting the production of wind turbines at certain times. This shows that wind production is already partially dependent on the electricity import-export capacities with the neighboring countries http://www.independent.ie/irish-news/broken-power-line-between-ireland-and-britain-to-spark-electricity-bills-rise-35094500.html
Figure 12: Ireland: evolution between 2000 and 2014 of the iREL proportion in % of the gross electricity production mix (green curve), of that of imports (orange curve), of that of exports (black curve). Note the sudden increase of imports after the East-West interconnection with England is established in 2012.
The fossil fuel proportion in the electricity mix is still approximately 75% but the share of gas has increased progressively relative to that of coal (see figure 13).
CO2 emissions remain very large. However, they have decreased markedly, more because of the replacement of coal by gas, which emits less, than because of the massive deployment of iREL. On figure 13, the correlation of the emissions decline with the reduction of the share of coal in the mix is clearly visible.
Note, in this connection, that a recent study shows that in terms of CO2 emission reduction from electricity production the benefit from the development of wind power suffers from the poorer efficiency of gas-fired power plants due to the incessant regime changes required to adapt to wind intermittence. (http://euanmearns.com/co2-emissions-variations-in-ccgts-used-to-balance-wind-in-ireland/ ).
Figure 13: Ireland: evolution between 2000 and 2014 of the iREL proportion in % of the gross electricity production mix (green curve), of the coal proportion (black curve), of the gas proportion (yellow curve) and of CO2 emissions in tens of grams per kWh (red curve). Note the iREL share increase, the decline of the coal proportion and the increase of that of gas. The decline of the CO2 emissions, though they remain large, is almost parallel to the decline of the share of coal.
Because of the relative isolation of its grid, it seems difficult for Ireland to significantly increase further the share of iREL in its electricity production mix, at least as long as it is not able to develop its interconnections with the rest of Europe to a degree similar to Denmark's. This would cost a lot of capital investment and it seems Ireland could not profit much by such interconnections; Denmark already occupies the only true European hydraulic niche, Scandinavia. For example, a link with Brittany is currently being contemplated. It is difficult to understand what point there is to such a link both for Ireland and for Brittany since the latter produces very little electricity, about 15% of its demand; it relies on imports from elsewhere in France for the rest of its consumption. Ireland can, however, reduce its CO2 emissions by completely replacing its coal with gas. In doing so, it will of course become totally dependent on foreign gas suppliers (Russia?) since it has no gas resources on its territory and its iREL would be largely useless without backup gas power plants.
France has nuclear power that generates three fourths of its gross electricity production and hydroelectricity that generates about 10 to 15 % of this production, depending on the year, in fact on the rainfall. Figure 14 shows the evolution of the proportions of iREL, coal and gas in the electricity production mix, as well as the CO2 emissions of this mix.
Figure 14: France: evolution between 2000 and 2014 of the iREL proportion in ‰ of the gross electricity production mix (green curve), of the coal proportion in ‰ (black curve), of the gas proportion in ‰ (yellow curve), of CO2 emissions in grams per kWh (gray curve) and of the price of electricity charged to households in €/MWh (red curve). Note the parallel evolution of the price and of the iREL proportion.
Note that the proportions of iREL, coal and gas are given in per thousand (‰) in this figure and not in percent (%) as in the other figures. The increase in the fraction of iREL in the production mix is well correlated with that of the electricity prices. The explanation could be twofold : on the one hand, the increasing "Contribution to the Public Electricity Service" (CSPE), a tax on electricity consumption which now exceeds € 6 billion per year, VAT included; almost three-quarters of that are used to cover the additional costs due to iREL feed-in tariffs. On the other hand the steady increase of the electricity transport cost (including the charge on using the public electricity network - TURPE). These now account for about 40% of the electricity bill charged to households, they are partly due to the deployment of iREL.
This situation will not improve since, because a profitability loss for conventional plants threatens their survival, a so-called capacity mechanism is being put in place that, in truth, consists in subsidizing these plants. This will necessarily be financed with an electricity price increase. Part of the cost will also be financed with the fossil fuel consumption tax, allowing a somewhat smaller increase of the CSPE, but concealing the overall cost of iREL development for the consumer.
The contribution of fossil fuels is very small and has decreased between 2012 and 2014. It was particularly small in year 2014. The CO2 emissions of the electricity production mix (here in g/kWh) are very small. They have decreased regularly since 2005 (see Figure 14). This results from the shutdown or mothballing of coal-fired plants and their gradual replacement with combined cycle gas turbine (CCGT) power plants, much more than from the increased iREL proportion in the mix: figure 15 shows that, in year 2000, the coal-fired plant capacity was about 8 GW. It was only half of that in 2015. CCGT plants were nonexistent in 2000; they represented about 5 GW in 2015. Of course, the iREL may have contributed somewhat to the emissions decline insofar as the weather conditions may, but randomly, be such that a large production from wind turbines coincides with the demand peak which occurs in France in the evening between 7 pm and 9 pm. In this favorable situation, wind production can, indeed, replace the fossil fuel production which normally deals with these demand peaks. By contrast, solar PV is of no use in this evening time slot.
Figure 15: France: evolution between 2000 and 2016 of the fossil fuel-fired power plant capacity in MW. Note the significant decline, starting in 2013, of the total FFP capacities (red curve) and of coal (black curve) and oil (green curve) capacities starting in 2013 and the rapid increase of CCGT plants (yellow curve) starting in 2009. The capacity of oil and gas-fired combustion turbines (CT) also increases (orange curve). Courtesy F. Poizat and J.Patel.
In figure 16, we show the variations of the hydroelectric production, along with the electricity exports and imports. As previously mentioned, the hydroelectricity production varies from year to year, depending on the rainfall (between 8 and 14% of the production mix) Exports are in the same range. They are far greater than imports. Thanks to its nuclear fleet, France is the leading European electricity exporter with a positive contribution to its trade balance.
Figure 16: France: evolution between 2000 and 2014 of the contribution of hydroelectricity in ‰ of the gross electricity production mix (blue curve) of imports in ‰ of the mix (orange curve) and of exports in ‰ of the mix (black curve).
iREL and CO2 emissions
It is obviously the share of fossil fuels in the electricity production mix of a country that determines for the most part the extent of CO2 emissions from its electricity sector. The kind of fuel used is also important: CO2 emissions from gas are about half those from coal for each kWh produced (see figure 1). As for oil, it is hardly used today.
Of the fifteen countries considered, only five have an electricity production mix that emits very little CO2: it is those countries that produce their electricity practically without fossil fuels, i.e. Austria, France, Norway, Sweden, and Switzerland. This is thanks to exceptional per capita hydraulic resources as in Norway and to a lesser degree in Austria, or to an electricity production mix based essentially on hydraulic and nuclear power, in proportions that vary according to the hydraulic potential in the three other countries. In these countries, if the aim is really to reduce CO2 emissions, the point of intensely developing iREL is not clear. One can even venture that, were they to be developed in association with a reduction of the nuclear power share in the countries that have it, their performance in terms of CO2 emissions could only worsen since it would be necessary to establish backup means based on fossil fuels to compensate for the intermittence.
In the ten other countries, because they have not been able or willing to develop sufficient hydraulic and/or nuclear resources, the contribution of fossil fuels in their electricity production mix is large, though variable from country to country. Five of these have developed iREL more than the others with the aim (put forward in the press, at any rate) of reducing their CO2 emissions, viz. Germany, Denmark, Spain, Ireland and Portugal. However, they have not succeeded in lowering their emissions to the level of the top five, and by far. The explanation is easy: iREL intermittence requires that they be associated with backup power plants that end up producing much more electricity during the year than the iREL themselves. In the countries with insufficient hydroelectric and/or nuclear resources, this role will of course be played mainly by fossil fuel power plants. Of the five, Denmark, the wind turbine world champion, is the one that has best succeeded in reducing its emissions. However, on analysis, it appears that this country uses the hydroelectric power plants of its Scandinavian neighbors, Norway and Sweden, as a backup for its wind power. This possibility that Denmark takes advantage of would no longer work at the European scale; the hydraulic resources would be widely insufficient. By contrast, Germany's mediocre performance in spite of an impressive iREL deployment does not really speak in favor of iREL development to reduce CO2 emissions.
iREL and price of electricity charged to households
Although the formation of the price of electricity in a country results largely from public policy, as well as from the price of raw materials such as fossil fuels and uranium, the correlation between the price of electricity charged to households and the extent of installed iREL capacities is obvious (see figure 6). Indeed, it is logical: barring huge electricity storage capacities, and it is widely accepted that these are presently unattainable and probably will be forever (see Appendix 1), iREL, in order to be usable, cannot do without "conventional" backup power plants. iREL capacities thus come as an addition to existing conventional capacities rather than allowing them to be significantly reduced. Thus, in Germany, iREL development has led to practically doubling the installed electricity production capacity over 15 years while the annual production has hardly changed. Capital expenditures have thus increased and must, in one way or another, have an impact on the price paid by the consumer. Moreover, the output of conventional power plants being reduced to make way for iREL, the price of the kWh they produce increases, since their fixed costs remain the same for a lesser production. Finally, the grid adaptations required for the insertion of iREL further increase the cost.
Note that, if the necessary storage capacities were realizable, their cost would undoubtedly be much higher than that of the backup power plants (see Appendix 1).
iREL and Europe's energy independence
One of the official objectives assigned to the development of iREL is to reduce Europe's energy dependence.
The development of iREL in Europe has probably reduced the consumption of fossil fuels but only marginally. This development is, however, inseparable from the availability of fossil fuel based backup power plants in those countries where iREL deployment is the most intensive. We are witnessing the end of the European fossil reserves, with a very rapid decline of their production. The graphics in Appendix 2 show how dramatic this phenomenon is.
The iREL then, far from decreasing Europe's energy dependence, have created, in the countries which have developed them strongly, a lasting fossil fuel dependence of their electricity production, while their own fossil fuel production is either non existent, or rapidly declining in those countries which are still producing some, except for Germany with its brown coal. iREL in these countries will soon be able to survive only thanks to fossil fuel imports from non-European countries.
What about France?
Given the already very low CO2 emissions from the French electricity production mix, and the strong correlation of the iREL share in the mix with the cost of electricity observed in all the European countries, there is no reason to further increase the share of iREL in the French mix, whether for economic reasons or for climate considerations.
Moreover, because of its relatively small hydroelectricity production and, contrary to Denmark, the impossibility of relying on the hydroelectricity of other European countries as storage batteries, eliminating its nuclear power and developing iREL strongly could only put France in a situation similar to that of Germany or Ireland where, in spite of intense iREL development, most of the electricity is still produced by fossil fuels. The consequences of such a policy for France would then be a considerable increase of its CO2 emissions and its air pollution, a lasting dependence on imported fossil fuels and thus, a deterioration of its trade balance.
Indeed, it has recently been possible (in the autumn of 2016) to verify in practice that in a situation where nuclear power is unavailable (18 GW of nuclear power stopped by the "Agence pour la sûreté nucléaire" (ASN) to verify metallic parts) the 18 GW of iREL power (wind & solar PV)) deployed in France since the beginning of this century were unable to substitute their production. Part of the nuclear power being unavailable, it is indeed the foreign fossil fuel power plants which, through imports, ensured the stability of the French electricity grid.
The iREL path would lead France to a stalemate.
Another consequence would be that France would lose the considerable advantage it has over all the other industrialized countries thanks to the very small emissions of its electricity production mix, namely the possibility to considerably reduce the CO2 emissions of its transport sector by developing electric mobility (see figure 17). Indeed, while electric vehicles do not emit CO2 directly, the electricity they consume emits a lot if the share of fossil fuels in the production mix is substantial, the case in all the large industrialized countries except France!
Figure 17: CO2 emission for the same distance traveled by an electricity-powered car compared to those of a diesel-powered car for some major industrial countries. Electric vehicles themselves have zero emissions but the production of the electricity they consume emits according to the electricity production mix of the country.
This advantage is all the more valuable that the European oil production has decreased very rapidly since 2000 (see Appendix 2) and this decline will continue even if a temporary pickup was observed because of high oil prices between 2003 and 2014, allowing significant investments which are bearing fruit today. Since the amounts of oil available on the international market, and thus the possibilities for European import, have started to decrease since 2008, under the double effect of stagnating world production and increasing consumption on the part of the major oil exporting countries, European countries will encounter increasing difficulties in supplying themselves on the world market. Yet oil accounts for 98% of transport today.
If the present intensive iREL development in conjunction with the reduction of the share of nuclear power in France is indeed driven, as the political circles and the press claim, by climate change and economic considerations, then this policy seems, let us say ... not very pertinent, if we are to avoid risking ... being impertinent.
Appendix 1 - Storage, the iREL Achilles' heel
With incessant and rapid variations of the instantaneous electric power they deliver, the intermittence of iREL is such that, barring complex mathematical simulations, it is difficult to make a precise calculation of the storage power and volume required at all times to make iREL production compatible with the demand on the grid. However, the orders of magnitude of the storage volumes necessary to guarantee consumption at all time, as well as the cost incurred and their global impact on the environment can be approached rather simply, as we do here.
In the following, we consider a mix made exclusively of iREL complemented with the already installed hydroelectric capacities.
First, a reminder: the electricity production which is necessary to secure internal demand is presently on the order of 520 TWh (gross production minus exports-imports balance) per year in France, or 10 TWh per week on average; the mean electric power needed for this production is about 60 GW. The consumer demand is much larger in winter than in summer.
We focus our attention on the months of December and January that frame the winter solstice. In cold weeks during these months, the demand can reach 90 or even 100 GW. It is this last value that has to be taken into account if the demand is to be satisfied at all times in winter. The hydroelectric installed power in France is 25 GW but of these, only 15 GW are available on a regular basis during these cold weeks so that the power that has to be guaranteed by the iREL is 85 GW for a 14 TWh per week consumption.
Today, there are only three means of storing electricity in significant amounts.
- Consuming snow melt reserves stored in altitude dams during the previous spring.
- Pumping water from a lower reservoir to an upper reservoir located behind a hydroelectric dam; this is known as pumped storage hydroelectricity (PSH). The existing PSH installations in France can return within a few hours at most the equivalent of 100 GWh of the 1500 GWh that are stored over the year in all of the hydroelectric dams, for a total turbine equipment power of 5 GW (Ursat et al, 2011, Castaing 2015).
There are 6 PSH plants of high power capacity in France - two are so-called pure, in that they operate in closed circuit between the upper and lower reservoir, with no upstream water input. These are Revin and Montézic that can pump approximately 25 GWh worth of reserve. Four PSH plants are so-called mixed, in that they receive upstream water from snow melt. These are Grand'Maison, Super-Bissorte, Cheyla and La Coche capable of pumping about 75 GWh from a smaller size lower reservoir connected to waterways.
- Electrochemical batteries, whose capacities are currently on the order of 100 kWh per tonne for industrial lithium batteries.
Today, PSH plants account for over 95 % of the amounts of electricity that can be stored worldwide.
1- Wind power
We will then assume here that 85 GW of the mean electric power needed to secure winter consumption during cold spells are provided by wind turbines. Because the power delivered by wind turbines constantly fluctuates at all time scales, a storage mechanism is necessary to ensure a good fit between the consumption and production of electricity. We will try to identify the characteristics and the dimensions of this storage so as to guarantee that the production balances the consumption even in the event of very weak wind production over a long period. Such a situation, that can last a week or two, is not frequent but neither is it exceptional on the French and even the European scale. The dimensioning parameters of such a storage are the power it can deliver and its storage capacity.
The mean load factor observed for wind turbines in France during the months of December and January is on the order of 25% so that the installed wind power should be 340 GW to provide 85 GW on average during those months. This corresponds to 110 000 wind turbines of 3 MW each, 180 meters high, blades included. With a surface occupation of 10 MW per km², the total surface covered would be about 35 000 km², excluding the areas made unfit for habitat in the vicinity of the farms, the ancillary facilities and the necessary service areas. Given an implantation cost today of 1 500€ per kW for onshore wind and 2 500€ per kW for offshore wind the cost of this deployment would be approximately 450 billion €, and that should be doubled to take into account the extensions and modifications of the electric grid that would be made necessary by this deployment.
However, there is a possibility that because of slack winds, these turbines produce only 5 to 10% of their average output during a very cold winter week. This is due to the settling in of very stable anticyclones over France as was the case in late fall 2016. Note that, during these periods, slack winds are often observed throughout Europe (Flocard and Pervès 2012) and there would be little help coming from those of our neighbors equipped only with wind power and hydroelectricity. To cope with such a production hazard, which would be fatal to the French economy, it would therefore be necessary to permanently have an 80 GW capacity reserve able to produce somewhat more than 13 TWh.
Water storage in a dam
Finding an additional 80 GW and 13 TWh of hydro power to cope with a near-total wind failure of one week with this system, is that possible?
The total hydroelectric power in France is 25 GW, including 13 GW of run-of-river (ROR) hydroelectric plants with virtually no water reserves. The power RORs generate is directly related to the flow of water in the waterway they use and cannot vary on demand. 12 GW correspond to pondage or lake hydroelectric power plants whose total water reserves could produce 1.5 TWh. Of these 12 GW, 5 GW are PSH installations which can provide or rapidly renew 100 GWh.
Of the 25 GW, 15 GW are generally used in winter. The remaining at most 10 GW could in principle be put to work, but it's 8 times as much that are needed. Also, the total water reserve is 9 times smaller than what would be necessary. And that is a one shot affair: it would take several years worth of snow fall to fully reconstitute the stock.
Electricians consider that 70% of the ultimate hydroelectricity capacities that could be economically profitable are already in use in France. Thus, even with new plants reaching to these ultimate capacities, the total hydroelectric power in France could be, at best, increased by 40% to cope with the problem. The same applies at the European scale.
Note, by the way, that if that were possible, increasing the permanently available hydroelectric power to 100 GW would be enough to secure the bulk of electricity consumption in France in all circumstances. Why then bother with iREL?
We are left with pure PSH plants which, because they operate in closed circuit, need only a minimal water supply (to compensate for evaporation and leakage) once one of the two reservoirs is filled. The total power of France's pure PSH plants is on the order of 2 GW for a storage of about 25 GWh. But it is important to understand that in the absence of wind production over a week, and that is the problem under consideration, it would be impossible to restore the upper reservoir water reserve once it is emptied, and it would be emptied within only a few hours.
The problem would be solved, then, if a large number of pure PSH plants were built, providing 40 times as much power and, more important, 500 times as much storage capacity as are available today! The key parameter is the storage capacity of the smaller of the two tanks.
The necessary surface would depend on the height difference of the two reservoirs and therefore on the local relief. The possibilities for large height differences are restricted (the average altitude of France is only 342 meters). One must think, then, of average plants such as Revin which covers a 5 km² surface, including installations, but could do with less power, on the order of 100 MW. It is, then, a surface totaling 20 000 km² that has to be found, half of which will be flooded, in order to build the necessary 4000 PSH plants. Such surfaces cannot be found in France and, as the Sievens dam case has just demonstrated, there would anyway be strong opposition from environmental movements, even though they are very much in favor of wind turbines.
As for the cost of such facilities, it can be estimated from existing installations. Building a medium sized PSH plant such as Revin with its two reservoirs behind a dam would cost today about 5000 € per kW, or 3.6 billion euros! Certainly, it is possible to do better, especially in the frame of a 4000 PSH plant program but a total expenditure of 5 000 billion euros seems to be a minimum.
Building PSH plants by the sea has been suggested, so as to use the ocean as the bottom reservoir; such prototype facilities exist, such as in Okinawa. However, the necessary area along the seashore remains considerable and the resulting environmental damage would be very large (Nifenecker 2013). Note that Nifenecker's study is very minimalist compared to ours, because it considers a situation where 20 GW of nuclear power are replaced in France by 20 GW of wind rather than our situation where the system is based entirely on iREL and hydroelectricity during a week without wind.
Note, finally, that the round-trip energy consumption of a PSH plant is about 30% of the stored energy. This means that the number of wind turbines would have to be increased by 40%, reaching 150 000 turbines, with a cost around 600 billion euros, plus the same amount for the electric grid adaptation. The surface they would occupy would be about 50 000 km².
We then reach a "solution" for wind turbines + storage + hydroelectricity whose total cost would be on the order of 6 000 billion €, comprising 150 000 3MW wind turbines 180 meters in height, and thousands of PSH plants covering 70 000 km² of the French territory, of which 10 000 km² would be flooded. The absurdity of this "solution" is blindingly obvious.
We add that two running weeks of slack winds in the winter, though unlikely, have indeed been observed. It would be wise then, to be in a position to rely on a storage system twice as large as the one described here, so as to cope with such a situation.
Given that the storage capacity of batteries is on the order of 100 kWh per tonne, it would take 130 million tonnes to recover these 13 TWh. The corresponding cost would be, at the current rate of 50 000 € per tonne, 6 000 billion €, perhaps only half of that in 10 years, but the expense would have to be incurred every ten years, which is not the case with hydraulic storage! Add the cost of the wind turbines to these amounts. Since the energy loss during charge-discharge cycles is about 30% here again, it is 150 000 wind turbines that would be needed, at a cost of 600 billion €, not counting the grid overhaul, just as in the hydraulic storage case.
Maybe this "solution" is physically feasible, if the materials for these batteries were available, and this is doubtful, but it comes out more expensive, even, than the previous seeming "solution".
2- Solar PV
The problem here is different as solar PV intermittence is governed by the day-night cycle with the additional complication of cloud cover variations during the day.
We should reason, then, at the 24 hour scale, but also take into account the seasonal aspect since the solar PV load factor in winter is much smaller than in summer in France and in most of Europe. During the months of December and January, the mean solar PV load factor for France as a whole is on the order of 5%. To secure an 85 GW mean consumption in this period, 20 times as much installed capacity is required, i.e. 1700 gigaWatt-peak (GWp), or 5 times the power required in the case of wind turbines.
Let us make an approximation and assume that most of the electricity produced is generated during the two daily hours of maximum sunshine, yielding 3400 GWh per day, while one twelfth of that is consumed during the 2 hours (assuming a uniform consumption in the day) so that 3100 GWh have to be stored within those two hours of production, and released during the rest of the day to satisfy the demand.
This corresponds now, to "only" 120 times the amount that can be accumulated in our existing pure PSH plants. Or, in the case of battery storage, to "only" 34 million tonnes of batteries for a cost of "only" 1500 billion €. But, here again, a 30% energy loss is incurred in the battery charge-discharge cycles so that the solar panel power should be increased by 40%, to reach 2400 GWp.
Today, a kilowatt-peak (kWp) of solar panels costs about 1000 € for large solar farms so that 2400 GWp would cost on the order of 2400 billion €. It is possible, today, to install 100 MWp of solar panels per km² as in the Cestas plant near Bordeaux. The surface required in our hypothesis would then be "only" on the order of 2400 km².
However, a whole winter week with practically no sun because of cloud cover all over France is not a rare occurrence. If the mean load factor is then divided by 2, the necessary solar panels, surface and storage capacity have to be multiplied by 2.
This "solution" does not seem realistic either, but it is less demanding than the previous options both in terms of cost and in terms of environmental impact.
The wind + storage + hydroelectricity "solution" is in fact physically out of reach if the storage is based on pure PSH plants because the existing pure PSH capacities are quite insufficient and it does not seem possible to augment them to the necessary level. Storage based on electrochemical batteries would be ruinous and it is far from certain that such storage is physically feasible.
The solar PV + storage + hydroelectricity "solution" seems less extravagant, but it remains very expensive and greedy for land surface.
Combining solar PV and wind power would hardly change the orders of magnitude.
Other solutions have been considered, such as storage using hydrogen or methane produced with iREL but these are even more delirious because, among other reasons, the energy losses incurred are on the order of 80% of the electricity originally generated (Sapy 2016) so that the wind and solar production capabilities would have to be multiplied by 5, as would the surface occupied and the associated costs, to be compared to the 40 % increase in the case of electrochemical battery storage.
Naturally, the coupling of wind power and solar PV with any of these storage schemes would be an ecological catastrophe, an aspect that the "defenders" of the environment don't seem to perceive.
Finally, note that with the present storage capabilities in France, if there were only one day with slack winds all over the country, a frequent occurrence, and if there were no backup plants or any possibility of imports, if only the hydroelectricity could be counted on to secure the French consumption during that day, it is 1200 MW of wind turbines that would be necessary. This corresponds to 400 000 3MW turbines, about one per km² of usable French territory, and a cost of 1500 billion €, not including the necessary grid overhaul (SLC 2017). Conversely, on a windy day, with the wind turbines producing up to 70% of their capacity, 90% of them would have to be disconnected, or the enormous amounts of excess electricity they produce exported to our European neighbors.
Storage, then, is the Achilles' heel of iREL, and it is a safe bet that "conventional" backup power plants have a long future ahead. The more so that, as we saw, the cost of such storage capabilities would in all events be much more than that of these plants.
If the iREL promoters were forced to build, along with their wind or solar PV plants, sufficient storage capability to cope with their intermittence, the real cost of these projects would at last come to light as well as their considerable environmental impact.
1-Ursat, X., Jacquet-Francillon, H.et Rafaï, I., 2011 : Expérience EDF dans l’exploitation des STEP. Société Hydraulique de France. SHF : «Pumped storage Powerplants», Lyon, 23-24 novembre 2011 - X. Ursat et al. - Expérience EDF
See also Castaing, P, 2015 : « les stations de transfert d’énergie par pompage », slide show
2- Flocard, H. et Pervès, J-P. , 2012 : Intermittence et foisonnement de l’électricité éolienne en Europe de l’Ouest .
3- Nifenecker, H., 2013 : Limites de l'intégration des productions d'électricité intermittente.
4-Sapy, G., 2016 : Pertes énergétiques du schéma « Power to gas + Gas to power » http://www.sauvonsleclimat.org/images/articles/pdf_files/etudes/Pertes%20energetiques%20Power-to-gas-to-power.pdf
5- SLC, 2017 : Le vent pourrait-il remplacer le nucléaire.
Appendix 2 - Exhaustion of European fossil fuel reserves
According to British Petroleum's Statistical Review of World Energy 2016 (https://www.bp.com/content/dam/bp/pdf/energy-economics/statistical-review-2016/bp-statistical-review -of-world-energy-2016-full-report.pdf ), the fossil fuel consumption (non-traded firewood excluded) for the entire economy (electricity generation but also transport, heating…) now represents a smaller proportion of the total primary energy consumption in the EU28 + Norway than 50 years ago (figure 18 - left panel). However, this proportion remains large, about 75%! Furthermore, two thirds of the 400 Mtoe (million tonnes oil equivalent) difference observed in 2015 between primary energy consumption and fossil fuel consumption are provided by hydroelectricity and nuclear power. In 2015 according to the same source, renewable energies other than non-traded firewood and hydroelectricity amounted to only 136 Mtoe, or one third of the above 400 Mtoe and 8.5% of the 1600 Mtoe total primary energy consumption. iREL amounted to only 30 Mtoe of these 136 Mtoe, or 7.5% of the 400 Mtoe, or a little under 2% of the total primary energy consumption!
In spite of the marked decline in fossil fuel consumption since 2006, up to 300 Mtoe in 2015, it appears that the production of fossil fuels within EU28 + Norway declined by about the same amount during this time period. Thus, Europe's dependence on imported fossil fuels has not been reduced. It amounts to about 700 Mtoe in 2015.
The right panel of figure 18 shows the fossil fuel production within EU28 + Norway between 1981 and 2015, according to the same BP statistical review. Coal production has been declining since 1982, that of oil since 2000 and of gas since 2004. The high prices observed between 2003 and 2014 did not reverse the trend in spite of improved production techniques and a better profitability of the operations during those years. This inescapable situation is the consequence of the depletion of the reserves.
Figure 18: EU28 + Norway: Left panel - Evolution over the past 50 years of the primary energy consumption (green curve), of the fossil fuel consumption (black curve), of the fossil fuel production (orange curve). Right panel - Evolution between 1981 (BP does not provide production statistics prior to 1981) and 2015 of the production of coal (black curve), gas (red curve), oil (blue curve), and total production (orange curve). In its primary energy consumption statistics, BP does not include non-traded firewood but, in Europe, this represents only about 5% of the primary energy consumption. In the graphs, the energy unit is million tonnes oil equivalent (Mtoe). Source: BP statistical review of world energy 2016.
I thank Hubert Flocard, Jean-Jacques Hérou, Elisabeth Huffer and François Poizat for their help in carrying out this study, as well as Jacques Patel, Paul-Frederik Bach and Bjarke Nielsen for the valuable data they provided.