In March, Cornwall Insight launched its new Energy Spectrum Europe publication in collaboration with the Institute of Energy Economics at the University of Cologne (EWI). Below is an extract of our Energy Perspective article from our latest issue, written by Konstantin Gruber and Nils Namockel from EWI.
Local forms of coordination are being increasingly discussed in connection with the structural change in the German electricity system. Local markets can satisfy the demand for locally generated electricity and help avoid grid bottlenecks by using flexibilities. However, existing studies show that it is difficult to quantify the benefits of local coordination mechanisms, while the current regulatory framework and lack of incentives limit implementation.
In the study, Economic evaluation of the benefits of local coordination mechanisms in power supply, carried out on behalf of Siemens AG and Allgäuer Überlandwerk GmbH, EWI has analysed local coordination mechanisms from an economic perspective. The study evaluates the benefits of local coordination for two major aspects; meeting demand for locally generated energy with additional willingness to pay for locally generated electricity and avoiding the expansion of the distribution grid through decentralised flexibility. Moreover, various regulatory aspects that act as obstacles to implementation are highlighted.
Existing studies highlight the economic potential of local markets
In general, to form a local electricity market, both supply and demand need to have a local character. The demand has a local character if preferences for locally generated electricity exist or if local flexibility is used to avoid grid congestions in the corresponding distribution grid. Hence, it is especially important to quantify these aspects to evaluate the economic potential of local markets.
Regarding the preference for locally generated electricity, the economic benefit is tied to the marginal willingness to pay. Empirical studies provide circumstantial evidence for a higher willingness to pay, but the results are rarely representative for Germany. Often, only individual regions or samples are represented in the studies through surveys of individuals. In addition, marginal willingness to pay is difficult to interpret, as it is seldom the case that the maximum marginal willingness to pay (e.g., for green electricity) can actually be realised.
Quantifying the value of harnessing local flexibility through local markets to avoid grid congestion is also difficult based on existing studies. For instance, according to the Agora Verkehrswende study published in 2019, the avoided grid expansion in Germany could reduce the total costs by up to 57% in relative terms or by up to €2.4bn (£2.1bn) per year in absolute terms. Still, the concrete potential contribution of local markets to the utilisation of these flexibilities is uncertain. Most of the studies considered the way in which the flexibility options are harnessed which remains unresolved. Besides local markets for flexibility, various mechanisms, such as balancing energy markets, would be available for this purpose. Thus, it remains unclear whether the corresponding flexibility options can develop their full potential through local markets.
Overall, existing studies provide indications of the economic potential of the two considered benefits of local markets, but there is currently insufficient data to further quantify this potential. Consequently, further research is needed to develop methodologies and apply them to the quantitative assessment of local coordination mechanisms. Moreover, adjustments to the regulatory framework are needed to make the local market concept more attractive. Currently, regulatory frameworks inhibit the participation of different actors in local markets.
Feed-in tariffs and the ‘Doppelvermarktungsverbot’ rule inhibit participation in local markets
The practical feasibility of local market mechanisms is limited due to the design of the German regulatory framework. An important aspect in this context is the ‘Doppelvermarktungsverbot’ rule (i.e., prohibition of multiple sales). This law prohibits the additional marketing of electricity as green electricity via local markets, provided that corresponding renewable energy plants are already supported by feed-in tariffs. Thus, plant operators must either choose to sell their electricity within a subsidy scheme or within local markets. As the feed-in tariff is generally more economical for plant operators than exclusively marketing the electricity locally, participation in local electricity markets is only an option for plants that are no longer subsidised after 20 years. In principle, it would be possible for these plants to sell their electricity via an electricity service provider or in local marketplaces after the end of the subsidy. However, the decisive factor here is whether cost-covering operation is possible, especially for photovoltaic (PV) systems that have been removed from subsidies. Figure 1 compares the marketing and operating costs of PV systems of different sizes with the market value in the German spot market.
The fixed costs for continued operation and direct marketing have a greater impact on profitability the lower the installed capacity of the PV system. Continued operation and marketing costs could be as high as 10.1 cents per kilowatt hour (ct/kWh) for PV systems with a capacity of 5kW. Given an average market value for solar electricity (dashed black line) of about 3.8ct/kWh (in 2019), a profitable continued operation for these plants would hardly be feasible. Revenues from local markets could consequently be used to close this gap, provided there is a sufficiently high willingness to pay for locally generated electricity. Otherwise, without the possibility of profitably marketing the PV plants that are not subsidised anymore, the dismantling of approximately 36GW of PV plants would be imminent from 2021 to 2035.