Power market developments

A view to 2030

3 November 2009

A new European forecast predicts 70GW of nuclear new build by 2030, even after wide-ranging uprating and PLEX, to meet expected demand. By Jacques Leclercq, with Guy Bettoun and Jacques David

A number of studies have looked at potential energy scenarios for Europe in the 2030s, but few take into account the transmission-distribution system. This article considers three possible scenarios – including a doubtful one from the European Commission – and analyses the possible place of nuclear power in the future generating mix for 27-member Europe.

Predicting Europe’s energy mix exercise proves difficult because energy policy in Europe differs from state to state, and talk of nuclear electricity remains taboo in some countries. Nevertheless there are a few analytical paragraphs on the subject in the 2008 World Nuclear Association report and in the 2008 edition of the IAEA’s report on nuclear electricity estimates to 2030. A detailed 2007 study, European Energy and Transport up to 2030, was also published by the European Commission DG TREN based on the PRIMES model. It was updated in November 2008 as part of the second strategic analysis of the European Economic Community’s energy policy.

This study predicts that there will be decline of nuclear electricity from 30% in 2005 to 20% in 2030, based on official decisions at mid-2007.

We will attempt to demonstrate the reasons why nuclear energy can plausibly continue to represent 30% of electricity consumption.


The DG TREN study (Figure 1) suggests that by 2030 there will be a 35% increase in demand for electricity to 4,400TWh. The study predicts that, in addition to nuclear’s drop, study renewable energy will grow by 8% to 23% (with wind increasing by 6%); gas and coal/lignite (without carbon capture and sequestration) will each increase by 3% to 25% and 30%. We believe the hypotheses about renewable energy, and gas and coal, are probably fragile and so will not comment.

Another study, VGB Energy and Transport Outlook, a 2007 booklet from the Germany-based trade association of the same name (see Figure 2), also predicts increasing demand, but also predicts that current electricity generation will decline with time. To keep up, it concludes, 350GW of replacement capacity needs to be commissioned by 2030. In addition, more than 100GW of extra capacity will be needed, while reinforcement and development of the transmission and distribution networks (very high voltage in particular) will be required to support this.

Following the DG TREN study, the aim is to meet projected 2030 demand with 170GW of wind power and biomass; 360GW of thermal power (coal & gas); and 57.6GW of nuclear power. It is estimated that this will cost in the region of EUR1000 billion. Nuclear energy would take 15% of this total.

Initial spending will undoubtedly focus on improving operating performance (so operating availability is, on average, 85%) and on plant uprates and lifetime extensions.

Competition will be fierce and serious technical and economic realignment can be expected. The process will begin fairly quickly, not only for financing reasons but also because of the risk of under-capacity in certain areas that could lead to unacceptable blackouts, perhaps as soon as 2015.

Case 1: Decline to 20%

The first scenario we will consider is a significant decline in nuclear capacity to 2030, as predicted by the Commission.

Figure 3 displays two possible tracks for the evolution of nuclear capacity as it could be in 2010, 2020 and 2030. Electricity generation from nuclear power accounted for 134GW, 30% of total generation in 2005. In the DG TREN scenario (blue line), the share of nuclear falls from 30% to 20% by 2030. For reference, we also plot a scenario where the nuclear share remains constant at 30%.

We argue that faulty assumptions in the DG TREN study’ make it too pessimistic, and that the future may more closely follow the red line than the blue one.

First, the Commission assumes the closure of power plants totalling 87GW over this period (28.4GW by 2020, then 58.6GW). But it does not take into account any plant life extensions or predicted power uprates, both of which are becoming more and more common. Second, it takes into account the commissioning of 57.6GW (only 9.4GW is certain today) so essentially 48.4GW of new nuclear capacity to be added between 2020 and 2030.

Another assumption that the study makes is that the capacity factor (Kp) in 2030 will be equal to the operating availability (Kd), at 93%. This is unrealistically high, because it does not take into account the load-following nature of nuclear power plants in France (which account for about 40% of the total capacity in Europe at present). Also the performances of the various fleets in Europe are far from those in the United States, which have averaged at best about 90% in the last five years. For our study we have selected a capacity factor of 85% in 2030. This figure, which is already very optimistic, yields 7.5TWh/GW instead of the 8.18TWh/GW considered by the Commission. The lower the load factor, the greater the installed base of nuclear power required for power generation. This difference alone requires an extra 10GW of nuclear capacity.

For these reasons, we feel that it is entirely realistic for nuclear to maintain a 30% share of electricity generation in Europe. In such a scenario the share of gas and coal would remain constant at 49% instead of rising to 55%, and wind power and biomass would ‘only’ increase by half as much as originally predicted, from 15% to 19% rather than 23%.

This scenario makes sense for three reasons: it is technically and economically feasible; it ensures security of supply, and will contribute to reduced greenhouse gas emissions.

We will now look in more detail at current trends and present two scenarios of our own, one relatively conservative and one relatively optimistic.

Case 2: events slow decline

In our second scenario, we have chosen a number of hypotheses that differ to the Commission in the DG TREN study.

The first is that plant lives will be extended by an average of ten years (decided on a case by case basis). This seems logical and in line with what has already been done, particularly in the United States.

Second, is that there will be uprates totalling 2.3GW.

The final assumption is that 17.5GW of new nuclear capacity will be commissioned. This breaks down as 6.6GW in the UK, 3.3GW in France, 3.3GW in Finland and 4.3GW in Eastern Europe. This figure naturally includes construction already in progress.

These hypotheses, combined with postponed decommissioning, show that the ‘decay’, which becomes evident by 2010 in the European Commission scenario will only begin in 2020. This is shown schematically in Figure 4.

Case 3: Maintain 30%

We now present a third scenario which we consider plausible that could maintain the percentage of nuclear power at 30% in 2030. This scenario makes the following three hypotheses, furthering those outlined in case 2:

• There will be lifetime extensions of 15 years, or more.

• There will be 3.7GW of extra uprates– in total, 6GW of uprates.

• A supplemental new build programme of 53.2GW will ramp up (12.8GW in 2011-2020 and 44.4GW in 2021-2030) – i.e. a total of 70GW new nuclear capacity will be commissioned by 2030.

These programmes have been evaluated on a country-by-country basis, according to probable developments, (even though some of the views might seem unrealistic in today’s political environment). For 15-member Europe, 40.4GW of new capacity is envisaged, in France, the UK, Italy, Switzerland, the Netherlands–but also Spain, Belgium and Germany where government policies may need to change.

Some 12.8GW is predicted for Eastern Europe including Slovenia, Hungary, Romania, Bulgaria, the Czech Republic and Lithuania/Poland.

Taking into account these new nuclear programmes and the 15-year delay in decommissioning due to lifetime extensions, we plot Figure 5.

If there were to be 70GW of new-build by 2030, we hypothesise that it would be comprised of BWR and PWR technology. We say that 10GW could be produced using BWR reactors, such as GE’s ABWR and Areva’s SWR for example, Candu reactors (such as the ACR1000) and other types. This leaves 60GW for PWR reactors divided between KHNP’s APR, Areva’s EPR, Westinghouse’s AP1000 or Rosatom’s VVER-type reactors as follows:

• 30GW for EPR

• 15GW for AP1000

• 15GW for VVER

On this basis, we would need to start building 20 EPRs in the next 15 years (for commissioning in 2030).

Transmission networks

The importance of electricity transmission networks and grid interconnections are often poorly considered when it comes to estimating the future energy mix.

If we look at the conclusions of a CEA-headed study on the European electricity transport system [CEA-ITESE, 2008], there are two problem areas in medium and high voltage (220KV and 400KV).

On a domestic level, countries need to respond to increases in wind generating capacity. This is a complicated process because wind tends to be decentralized, low power (5 to 100 MW), and intermittent. Although these aspects are delicate and costly, they are well under control.

The second aspect relates to grid connections across Europe. Although this presentation only looks at the enlarged European Union, in our opinion, nuclear Europe encompasses not only these 27 states (140GW) but also Ukraine (14GW) and in the future Turkey and Belarus. Russia (24GW) also is, and will increasingly be, a player in the zone for two reasons. First, the eight hubs of the transmission-distribution system of geographic Europe are interconnected, and second because of the competitive nature of the industry, as clearly shown by the recent alliances.

Grid connections are often insufficient between the eight hubs of Europe. In July 2009 a new European umbrella ENTSOE was set up to join the five Western European networks–UCTE, NORDEL for the Scandinavian countries; the British Isles system (UKTSOA and ATSOI) and BALTSO for the Baltic countries, as well as southern Mediterranean systems. Next door is IPS/UPS for Russia and CIS states.

Common rules concerning supply security already exist, and existing grid interconnections allow mutual assistance between partners. This being said, a significant disruption can easily be propagated throughout the entire system. We feel that the following action needs to be taken with respect to the grid:

• Medium/long term planning of supply and demand, which as we see it, should be strengthened at the community level

• Sufficient investments: an estimated EUR125 billion (according to the OECD) of the previously mentioned total of EUR1000 billion should be invested in the grid. This should include EUR12-15 billion for the wind connection and EUR150 million for VHV transmission networks and interconnections, which are essential.

• Political support from the member states to overcome the adverse perceptions of nuclear facilities.

Author Info:

Jacques Leclercq, president of JAL Consulting, 21, Boulevard Suchet 75016 Paris, France. With the collaboration of Guy Bettoun (EDF) and Jacques David (CEA)

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Figs 1, 2 and 3. Figs 1, 2 and 3.
Figs 4 and 5. Figs 4 and 5.

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