At first glance, the integration of the internal electricity market seems to be on track. However, when taking a closer look it is clear that without an extra effort, much of the work done over the last decade may be at risk.
Twenty years ago the joint energy wholesale market was at the heart of the internal market agenda. This was sensible because competition between conventional power plants across Europe would improve operational efficiency, meaning that consumers could be served by fewer and more efficient plants with less scope for operators to charge excessive prices.
To date energy regulators and network companies are working at full steam to harmonise complex technical rules for cross-border electricity exchange. Co-ordination of the operation and planning of networks has substantially increased. Therefore, completing the internal energy market next year – the ambitious political deadline set by European Union heads of state – seems feasible.
At first glance, the internal energy market seems to be on track. The 2012 ACER/CEER report shows how electricity prices during the past years have converged significantly. For example, Dutch and German power plants operators received the same hourly price for their electricity in 7% of the time in 2008 and in 2012 this had increased to 57%. Further, estimates show that the implemented technical rules for cross border trade have already saved EU consumer about 2 billion euros per annum merely by better utilising the existing generation and infrastructure (see here a Booz and Company report and see here Bruegel reporting). Moreover, sound price formation based on market fundamentals is essential to plan efficient investments in generation and networks of it is estimated the EU needs more than 800 billion euro until 2020.
However, the energy landscape has changed dramatically over the past few years. During the last 10 years generation from either wind or solar has increased by more than 500%. The massive deployment of renewables is propelled by national non-market based supporting schemes with a view to reducing CO2 emissions. As a result of this and the delayed grid expansions, electricity becomes worthless when the zero-operational-cost production from these sources exceeds the demand. For example, in 2012, average wholesale prices in Belgium, France, Germany and the Netherlands fell below €0.05 per kilowatt hour (kWh) while in Germany, prices dipped below zero in 48 instances. At the same time domestic consumers in the Netherlands paid in 2012 nearly €0.19/kWh and in Germany €0.25/kWh. Apart from VAT these include, levies and tariffs for national schemes for networks, renewables, capacity and flexibility that are outside the price formation of the internal market.
In view of the increasing share of wind and solar generation, the need for flexible power generation capacity (for example gas turbines) is going up. This type generation is needed to quickly ramp up adjusting the variable production from wind and solar to serve demand. However, the pricing of renewables, remuneration for network availability, flexibility and capacity remains often organised nationally. For example, capacity in France and Germany used to be remunerated through the wholesale price only as is still the case in the Netherlands. Now, France is putting in place a mechanism to remunerate all capacity in its territory, while Germany has introduced so-called ‘strategic reserve’ that pays only for the capacities of selected power plants. All in all, the current trend is an emerging patch work (see here ACER communication) of national remuneration schemes which are implemented to solve national energy market solutions. A concern is that these schemes may introduce barriers to competition between power plants located on both sides of EU borders. Moreover, there is a concern that these schemes will drive new investments in generation and not the market.
Implementing additional schemes for capacity remuneration at national level may in fact rewind the market integration process and introduce prices distortions that blur investment signals. Irrespectively of whether in the future additional schemes are needed to improve the current market design, such schemes should be evaluated and added on top of a well-functioning energy market, while the latter is a prerequisite.
A well-functioning integrated energy market renders sound prices and a correct value for flexible generation. This will attract existing resources in the system to participate in the supply of flexible electricity, including attracting demand response sources which in the US have shown to be able to successfully participate in the market. In addition, it will further improve the efficient use of the interconnections, ensuring that electricity flows from regions with an excess of low-cost generation to regions where the demand can absorb it. Prices will send appropriate signals to the market for investments in, inter alia, flexible new plants, storage, distributed generation and demand-side response technologies. Moreover, it will yield greater availability of least-cost flexible resources on a wider geographic scale to mitigate the impact of intermittency. It also reduces forecast errors of wind and solar generation which will further reduce the need for costly adjustments to balance supply and demand.
The internal energy market has delivered huge benefits for EU consumers and completing it is the obvious way to address the challenge of integrating renewables in the European energy system. In the interest of European Consumers MSs should therefore implement what they have signed up for, which is to further harmonise the rules for cross-border electricity exchange, coordinate new network development and put national solutions into the fridge.
Economist at the Agency for the Cooperation of Energy Regulators* and University of Amsterdam
* The views expressed in this article are the views of the author and do not necessarily reflect the views of the Agency for the Cooperation of Energy Regulators.