Can Europe’s Electric Grid Handle Renewable Energy-Intensive Electric Mixes?

 

by Aimé Boscq*

In January 2021, the International Energy Agency (IEA) and RTE, French transmission system operator (TSO), published a study concerning the technical feasibility of a power system with a high share of renewables in France towards 2050[1]. The report highlights that reaching 50% of electricity generation covered by renewable energy sources (RES) by 2030 would only require marginal adjustments to the current management of the electric grid. However, the analysis points out the major challenges associated with surpassing this objective after 2030.

France’s transition from an electric mix relying on centralized production capacities based on nuclear and fossil fuels to a RES-intensive mix associated with largely decentralized production capacities is far from being an isolated example in Europe. In order to fulfil their common ambition of becoming carbon neutral by 2050, the European Union (EU) and its member states will need to bring about significant changes in their energy consumption and production patterns, electrifying several energy usages and shifting to RES to produce their electricity[2].

This major shift in electricity production and consumption will have a significant impact on the way electricity is produced, but also on the way it is provided to end-consumers through grid infrastructure. The European power grid was initially designed to provide electricity produced in large, centralized power plants to end consumers. This design involved TSOs calling dispatchable power plants online and offline in order to meet demand and provide grid stability when required[3].

However, the growing share of RES in the mix has led to a radical change in this organization, with a large part of generation now produced intermittently, geographically spread around the grid and with some grid users frequently shifting from a consumer to a generator profile as prosumers and self-consumptions are increasingly widespread. As power plants are called online and offline by TSOs based on their marginal cost, RES such as solar and wind enjoy an injection priority given their marginal cost is close to zero. This injection priority, further secured by incentivizing policies at European and national levels, is remodelling the way the European grid is dimensioned and managed by TSOs and distribution system operators (DSOs). Ensuring technical stability and balancing supply and demand now requires additional tools and services, including capacity reserves and flexibility solutions such as battery storage, requiring swift and efficient changes in the operations of system operators. Without major overhauls in its technical and financial management as well as its regulatory framework, the grid could become a major source of tension and slowdowns in the energy transition[4].

Amongst the challenges associated to the grid integration of a high share of RES, the most debated is likely to be that of security of supply. Electric grids require a constant alignment of production with demand to ensure resource adequacy and quality of service for all consumers. With the increasing capacity of non-dispatchable RES, notably solar and wind, being deployed by EU member states to reach their decarbonation targets, matching supply and demand could become a major issue for TSOs and DSOs[5]. Production from RES, while predictable to a large extent thanks to precise weather forecasts, does not always coincide with demand peaks. In an RES-intensive mix, would households, businesses, and industries be condemned to endure power cuts whenever the wind stops blowing or the sun stop shining?

Beyond the supply-demand equilibrium, the integration of renewable production to the grid is becoming increasingly challenging from a technical point of view. First, the physical capacity of the grid to absorb extra production is increasingly challenging in areas where RES development is particularly dynamic. In some cases, a large part of this capacity may also be reserved for future developments in conventional generation capacities (such as additional nuclear reactors in the case of Romania)[6]. While the first renewable production units benefited from existing infrastructure and relatively low connection fees, existing power lines and substations can only handle a given amount of production. As such, the connection of newer production projects is often linked to soaring grid connection costs, should they be handled by end-consumers, taxpayers, or by producers themselves depending on the grid financing mechanisms in place in each state. These costs can, in some cases, offset the significant decrease in the cost of RES technologies experienced in the past decades, leading to raising concerns on the overall cost of the energy transition and subsequently to public acceptance issues. Moreover, the geographical concentration of production units can lead to challenges in voltage and frequency management, given that some RES can be limited in their capacity to contribute to these critical aspects of grid stability[7].

Major breakthroughs have been made in the past decades with regards to electricity storage as providers of grid management services in RES-intensive electric mixes. Electrons themselves are extremely complicated to store physically, implying costly and logistically challenging infrastructure. They can however be converted into potential energy, which will in turn be converted into electricity again when demand rises. Such conversion units can take multiple forms, using as many different technological solutions associated with varying roundtrip efficiencies. One of the most mature means of storing electricity are pumped-hydro-storage plants, where water is pumped up when excess electricity is produced and released through a turbine to produce electricity when needed[8]. However, this technology has become rather difficult to roll out due to environmental and public acceptability concerns over the flooding of large areas, severely affecting wildlife and local populations. Furthermore, this technical solution is also very capital-intensive, further undermining its attractivity.

The technical solution regarded as having the highest potential to meet the EU’s upcoming electricity storage needs are chemical batteries (lithium-ion technology being one of the more mature solutions, but far from the only one)[9]. This solution presents the crucial advantage of being extremely modular, able to respond extremely fast to calls from grid operators or market players and have a relatively long-life cycle. Moreover, battery costs have decreased dramatically in the past decade with major technological breakthroughs fuelled by the accelerating rollout of EVs, and a large part of electric-vehicle batteries can still be used in standalone applications when they are not efficient enough anymore in vehicles[10]. The rollout of EVs represents a fantastic opportunity for grid management, as specific charging points enable electricity consumption by the battery as well as injection to the grid or to a specific consumer in a process called vehicle-to-anything or V2X.

Although less consensual, other technological solutions could also be mobilised by TSOs and DSOs in order to maintain grid stability. Among those, power-to-gas (P2G) has been the subject of heated debates concerning its potential contribution to the energy transition. P2G technologies include the production of synthetic methane and hydrogen with excess electricity and later either using these gases in peaker power plants to produce electricity or in industrial processes to produce heat[11].

Along with RES production curtailments already in use today, demand-side management could also play a significant role in enabling the grid integration of RES in renewable-intensive electric mixes. Today, end-consumers are no longer passive absorbers of electrons, as the rise of prosumer behaviours enables them to produce, store, self-consume, share the electrons they produce and even take part in grid services[12]. While large industrial consumers have been mobilized by some TSOs and DSOs to provide load reduction services for many years now, small scale consumers including households are now becoming increasingly integrated in the market mechanisms and regulatory frameworks encompassing grid stability in the context of the energy transition.

While it would be easy to conclude that the solutions described in the previous paragraphs make the energy transition’s grid-related issues irrelevant, such a conclusion would hinder a key aspect of the transition’s acceptability – its cost. Most studies show that the overall cost of an electric system compatible with the Paris Agreement, and its repercussion on the price paid by end-consumers for their access to electricity, would not be very different to the one we experience today[13]. However, in order to maintain an acceptable price tag while massively accelerating the energy transitions, infrastructure investments to ensure the connection of new capacities to the grid and increase the interconnection of national grid on a European scale will be needed as soon as possible. These investments will need to be accompanied by both a significant mobilisation of end-consumers to adapt their behaviours and strong political momentum to accelerate the integration of all actors of the energy sector, big or small, to grid services markets[14].

The European Clean Energy Legislative Package[15] and subsequent reforms have brought about significant tools for national public authorities, regulators, grid operators to adapt market designs and technical requirements to the introduction of a significant proportion of RES to the European electric generation mix. However, the implementation of these reforms on a national level has been slow and is still far from complete, years after their adoption in Brussels[16]. These reforms are essential to the energy transition as they will render the cost-efficient technical solutions available on the market available to use by grid operators. As such, the complete transposition of European legislative initiatives on a national level as early as possible seems to be a prerequisite to considerably facilitate the rollout of RES and make the energy transition as a whole a success.

 

[1] International Energy Agency and Réseau de Transport d’Electricité, Conditions and requirements for the technical feasibility of a power system with a high share of renewables in France towards 2050, 2021. Url: https://www.iea.org/reports/conditions-and-requirements-for-the-technical-feasibility-of-a-power-system-with-a-high-share-of-renewables-in-france-towards-2050

[2] European Commission, 2050 long-term strategy. Url: https://ec.europa.eu/clima/policies/strategies/2050_en. See also: European Commission, 2030 climate & energy framework (https://ec.europa.eu/clima/policies/strategies/2030_en) and National Energy Climate Plans of EU member states (https://ec.europa.eu/energy/topics/energy-strategy/national-energy-climate-plans_en#final-necps)

[3] Subhes C. Bhattacharyya, Energy Economics, Concepts, Issues, Markets and Governance, Springer, 2011

[4] Brigitte Knopf, Paul Nahmmacher, Eva Schmid, The European renewable energy target for 2030 – An impact assessment of the electricity sector, Energy Policy Volume 85, October 2015, Pages 50-60. Url : https://www.sciencedirect.com/science/article/abs/pii/S0301421515002037

[5] D.P. Schlachtberger, T. Brown, S. Schramm, M. Greiner, “The benefits of cooperation in a highly renewable European electricity network”, Energy Volume 134, 1 September 2017, Pages 469-481. Url: https://www.sciencedirect.com/science/article/pii/S0360544217309969

[6] https://world-nuclear.org/information-library/country-profiles/countries-o-s/romania.aspx

[7] See note 5

[8] US Energy Information Administration database

[9] Michael Child, Claudia Kemfert, Dmitrii Bogdanov, Christian Breyer, “Flexible electricity generation, grid exchange and storage for the transition to a 100% renewable energy system in Europe”, Renewable Energy Volume 139, 2019. Url: https://www.sciencedirect.com/science/article/pii/S0960148119302319?via%3Dihub

[10] Behrang Shirizadeh, Quentin Perrier, Philippe Quirion, “How Sensitive are Optimal Fully Renewable Power Systems to Technology Cost Uncertainty?”, The Energy Journal Volume 43, Number 1, 2020. Url: https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3592447

[11] Ibid.

[12] Campos et al., Regulatory challenges and opportunities for collective renewable energy prosumers in the EU, Energy Policy Volume 138, March 2020. Url: https://www.sciencedirect.com/science/article/pii/S0301421519307943

[13] See notes 8 and 9

[14] See notes 1 and 11

[15] https://ec.europa.eu/energy/topics/energy-strategy/clean-energy-all-europeans_en

[16] See, for example, the transposition process of the market design directive (directive n°2019/944) into national law in EU member states: https://eur-lex.europa.eu/legal-content/EN/NIM/?uri=uriserv:OJ.L_.2019.158.01.0125.01.ENG

 

*Aimé Boscq is an EPG Fellow. The views expressed in this paper are those of the author and do not necessarily reflect the opinions of EPG.

 

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