Euro-grid improvements2 September 2016
Two new studies point the way ahead to maximize the benefits of power generation in European Member States by improving the electricity grid in line with European policy Corrina Thomson reports.
The objectives of the European Energy Union include energy security, sustainable development and competitiveness. Investigations into how to improve the European electricity grid are used to inform policy and identify which developments are cost-effective. The European grid performance also affects each Member State’s ability to meet climate policy objectives and is vital to European energy market aims.
Published in June, the European Commission (EC) report by Tractebel Engie ‘Study on the benefits of additional electricity interconnections between Iberian peninsula and rest of Europe’ details the costs and benefits of 12 different electricity grid improvement scenarios. The report supports the work of an EC high-level group on interconnections for Southwest Europe established by France, Spain, Portugal and the EC.
The EC Joint Research Council (JRC) report ‘The Baltic Power System Between East And West Interconnections, First Results From A Security Analysis And Insights For Future Work’ was also published recently and adds key insights about the Baltic grid to the European electricity transmission landscape.
In 2002, the EC decided that there should be a target for Member States, which would mean they had electricity interconnections equivalent to at least 10% of their installed generating capacity by 2005. Interconnectors are high-voltage transmission lines that allow energy to flow from one network to another and the term is applied specifically to international links. This target was reiterated by the EC in 2013, when the Commission also agreed to eliminate so-called energy islands, which have no interconnectors at all.
The current target for electrical interconnectors is at least 15% of installed capacity by 2030. In order to achieve these targets countries nominate, and the European Commission chooses, “projects of common interest”. These should benefit from faster and more efficient permission procedures and improved regulatory treatment.
European aims for fully integrated electricity transmission systems within and between Member States are informed by studies such as the Tractebel Engie report on the Iberian peninsula, which shows that some new Iberian interconnections would bring significant benefits while others may be prohibitively expensive and bring little benefit.
The 12 scenarios in this study are based on three load/generation visions and four transmission scenarios. The load/generation visions are based on those developed by the European Network of Transmission System Operators for Electricity (ENTSO-E), and published in its 2030 Visions. Entsoe-E’s Visions are intended to inform Entose-E’s European Ten- Year Network Development Plan.
The reference case scenario comprises all existing interconnections between Spain and the rest of Europe and three Projects of Common Interest, which have already been approved. These are: a double circuit High Voltage Direct Current (HVDC) cable from Baixàs, France, to Santa Llogaia, Spain; a phase shifter transformer in Arkale, Spain; and the Biscay Gulf HVDC project.
Including these projects should give an interconnection capacity between Spain and the rest of Europe of 7.8GW, which is estimated to be seven percent of the installed capacity in Spain in 2020.
In the three other transmission scenarios the net transfer capacity (NTC) between Spain and the rest of Europe reaches about 10%, 12% and 15%, respectively, of the expected installed capacity in Spain in 2030. They correspond to 14GW, 16.8GW and 21.1GW of interconnection capacity around Spain.
For the load/generation visions, the report noted the total generating capacity installed in France, Spain and Portugal at the end of 2013 was 248GW.
There was 128GW of installed capacity in France. Nuclear power plants represented about half of this capacity (63GW) and the remaining was split between thermal plants (25GW), hydro (25GW, of which 4.6GW is pumped storage) and renewable energy (12GW).
In Spain the installed capacity was 102GW in 2013. There is 7.9GW of nuclear power. Thermal power plants provide about 40GW, whereas new renewable energy sources reached 30GW (23GW wind and 7GW solar) and the hydro capacity was 17GW.
In Portugal, the total installed capacity amounted to 18GW. About 40% of this was from thermal plants and 60% from renewable energy sources including hydropower.
Comparisons of peak load with installed capacity vary greatly in the countries studied.
Peak loads in 2013 were 92.6GW in France, 44.4GW in Spain and 8.3GW in Portugal. In France, with 128GW of installed capacity for a peak load equal to 92.6GW, the installed capacity margin is about 38%. For Spain, the installed capacity was 102GW while peak load reached 44.4GW, so the margin was about 130%. In Portugal, installed capacity was 18GW for a peak load equal to 8.3GW so that the reserve margin exceeded 110%.
Differences in the generation mix are highlighted in the report, which states: “In France, most of the energy produced comes from nuclear power plants which are highly predictable and highly reliable, so that the need for backup remains limited. Moreover, the peak load in France corresponds to very exceptional situations in winter and generally appears only a couple of hours each year.
“...in Spain, the nature of generating units is completely different with a large share of renewable energies which are characterised by their intermittency and their low predictability, and some thermal power plants that are not used anymore. Such a generation mix can justify a higher reserve margin.”
It goes on to say the reserve margin is “really high” in France and in the Iberian Peninsula due to development of renewable energy on top of conventional power plants and the slowdown in electricity demand everywhere in Europe.
“The reinforcement of interconnection between European countries could help at reducing the need for reserve margin in the future, especially when energy mixes and load demand profiles are strongly different on both sides of the interconnection,” it says.
The possibility of interconnections to other countries was considered, such as the BRITIB project, which could connect the UK, France and Spain by a tri-branch HVDC connector. The study also included analysis of an undersea HVDC project between Spain, France and Italy.
Cost benefit analysis
The first transmission scenario was built by considering the two projects included in the Madrid Declaration, a key European and Iberian energy agreement, and the BRITIB project. These three projects were sufficient for interconnection to reach about 10% of installed capacity in Spain. In each of the load generation visions, this transmission scenario appeared to be profitable.
The study found that even if the total costs are quite high, about €6.5 billion, the investment made would bring significant benefits each year – €550 million to €600 million in 2030. Considering the magnitude of the net present value, which is close to €2000 million, the profitability is considered to be robust against variations in costs and benefits of new interconnections, which are highly uncertain.
The second transmission scenario considered four new projects through the Pyrenees as well as the BRITIB project. This would bring the interconnection level to 12%. But the total estimated cost of these projects is nearly €9 billion and the expected annual benefit will reach €550- 630 million in 2030. Therefore, the 12% objective appears to be at the limit of profitability.
The third transmission scenario considers four new projects through the Pyrenees and two HVDC undersea projects to connect Spain to the UK (BRITIB) and Italy. The undersea HVDC project costs are huge, although they bring important benefits. They are also the only way to reach the 15% interconnection level for Spain.
However, the total estimated cost of these projects are close to €19 billion. Even if the undersea cables brought annual benefits that reached €1 billion by 2030, this cost level means that the developments cannot be profitable.
The cost benefit assumes that power exchanges between the Iberian peninsula and Morocco stay around their current level: export of about 5.8TWh from the Iberian peninsula to Morocco (average power 660MW) and almost no transmission in the opposite direction. However, plans to develop renewable energy in North Africa may change that.
The report came to the final conclusion that to reach the 10% target, the projects that are most beneficial are those in the Western and Central Pyrenees. Extension of interconnections to 1, about 10% of installed capacity in Spain in 2030 (4GW) could bring benefits that will be much higher than related costs.
The main benefit is from optimizing interregional transmission, leading to a better use of renewable and nuclear energy, accompanied by a drastic reduction in gas consumption.
In all cases, reaching the 10% target by developing the two Madrid declaration projects and a third one (BRITIB or a trans-Pyrenean project) is profitable. The benefits resulting from the new interconnections are higher than the costs in all the load generation visions.
The report also found that the 12% objective is at the limit of profitability.
In order to reach the 15% target, additional submarine lines to the UK and Italy are needed. The report concluded that an interconnection level of 15% of installed capacity in Spain in 2030 is not profitable under any of the scenarios.
Also informing European policy is the new Baltic grid report by the JRC. The Baltic States are strongly connected to the electricity grids of Russia and Belarus but current energy security and independence targets in the EU mean that alternative energy sources are a target. Integration of the states into the EU energy market is a strategic priority for all three countries. There is also a Baltic Energy Market Interconnection Plan (BEMIP), which aims to create a Baltic Sea region unified market.
JRC developed a power system model of the Baltic States to provide options for reliable and secure development of the Baltic electricity system. The analysis for 2020 and 2030 showed that the dependency of the Baltic States on external resources is fairly low, as long as expansion of the electricity system goes ahead.
The Baltic integrated power system – encompassing Estonia, Latvia and Lithuania – is operated as a synchronous grid in parallel with the unified power system in Russia and some Russian Commonwealth states.
The JRC report noted that Baltic power systems still lack adequate interconnectors, both between themselves and to other parts of the EU. It pointed to improvements that have been made, including the Estlink 1 and Estlink 2 connections between Estonia and Finland, the LitPol connection between Lithuania and Poland, and the Nordbalt connection between Sweden and Lithuania. These new grid links have significantly increased transfer capacity.
The JRC report highlighted one of the major changes to power generation in the Baltic region, the shutdown of Lithuania’s Ignalina nuclear power plant. The early-version RBMK two-unit plant was shutdown as a condition of accession to the EU. The units were rated at 1185MWe net and were shutdown in 2004 and 2009. In 2009, the single remaining unit at Ignalina produced almost 40% of the electricity needed by the Baltic States. A new ABWR in Visaginas has been considered as a replacement.
According to the report, in 2013 generation in Estonia was mainly characterised by large thermal power plants with a total generation of 11,892GWh/year. Renewable sources, mainly wind power, provided 451GWh/year.
In Latvia, hydro produced 2912GWh/year and fossil fuels accounted for 2869GWh/ year, whereas wood and wind power plants contributed 119GWh/year.
Lithuanian generation capacity consisted of hydropower and pumped storage power plants producing 1066GWh/year; gas, coal or oil producing 2615GWh/year; and wind producing 649GWh/year.
The availability of primary energy sources for electricity production and dependence on other countries is different for the various Baltic States. Estonia’s energy independence is 90%, whereas Latvia’s is 48%, and Lithuania’s 19%.
The JRC model found that cross-border power flows are close to recorded ENTSO-E data in winter off-peak load and summer peak load scenarios. Two additional scenarios, winter peak load and summer off-peak load, were also considered.
JRC noted the Baltic States usually export electricity to mainland Russia but import it from the Russian enclave of Kaliningrad and from neighbouring Belarus. From a Baltic perspective, electrical dependence on Russia is fairly low.
Lithuania’s grid infrastructure is adequate and can sustain a large quantity of imports. A hydro pump station is important for shifting generation resources and plays a key role in reducing the system marginal cost in Lithuania.
According to the report, the Latvian power system has market advantages due to the high ratio of renewable energy, mainly hydro, in its generation mix. In the reference scenario, Latvia is a net exporter but the network is not as effective as in Lithuania as sometimes congestion causes an increase of the system marginal cost.
Estonia’s network occasionally experiences lower voltages compared with the other two Baltic States, especially when the Estlinks with Finland are under heavy loading. Estonia has highest the installed wind capacity of the three Baltic States, but it is not enough – and not dispatchable enough – to give Estonia the same strategic market position as Latvia with the latter’s hydro capacity.
Cross-border transmission corridors inside the Baltic States are enough to sustain electricity use patterns assumed in the scenarios but JRC said that internal network projects should be encouraged to remove congestion.
Nuclear generation in Lithuania could greatly improve security of electricity supply in the, it noted, but went on to say that without nuclear power the Baltic States can still count on alternatives for generation, though these would result in a lower security margin.
The Baltic States aim for greater energy independence through diversity of primary generation but due to the countries’ limited ability to act on their own, particularly on expensive projects, joint efforts are needed.
Nuclear or not
In scenarios with nuclear power, nuclear generation was always assumed to be available to the maximum capacity, minus self-consumption. The assumption of higher importing prices and zero exporting prices of the Baltic States implies that, unless it were absolutely necessary to maintain the operation of the system, power exchanges with the neighbouring countries would not take place, according to JRC.
However, with a nuclear power plant operating in Lithuania, generation adequacy would be greatly increased. During some off-peak periods, export to outside countries would take place even at zero prices, simply to maintain the operation of the system. Nuclear power would also bring about much lower system marginal cost most of the time.
Without a nuclear reactor, the power exchange with neighbouring countries was again practically zero, according to the report. The system marginal cost became comparatively high. The hydro pump stations in Lithuania were modelled as load during off-peak hours, causing power to flow from north to south. During the winter peak hours, the power flow is reversed.
For the winter off-peak case, Lithuania became a net importer, with 124MW and 692MW from Estonia and Latvia, respectively. The generation in the northeast part of Estonia provided counter-flows to relieve system congestion, when location marginal cost was zero at those buses.
It is clear from both reports that European electricity grid improvements are required to develop a more efficient transmission system and move towards the goal of a single European energy market.
Baltic States have made good progress in developing their grids and making them better connected, a process which is likely to continue.
When it comes to power generation, the reports show that despite key changes, such as the shutdown of Ignalina nuclear power plant, the Baltic grid is able to respond adequately.
The Iberian peninsula has clear advice on which projects will be the most cost- effective and beneficial in moving towards the interconnections target.
Neighbouring non-European countries are also likely to affect the future of grid development, such as the potential of renewable energy in north Africa mentioned in the Iberian report or a relationship with the Russian grid.