Conditions and requirements for the technical feasibility of a power system with a high share of renewables in France towards 2050

France is one of several countries which have pledged to achieve net zero carbon emissions by 2050 to meet its climate change mitigation commitments under the Paris Agreement. To help it reach this goal, the French government recently published a new energy and climate law and the National Low-Carbon Strategy (Stratégie nationale bas-carbone, or SNBC). This comprehensive strategy for achieving carbon neutrality relies largely on energy efficiency, systematic use of biomass and greater use of electricity.

France already enjoys extremely low-carbon electricity, owing largely to its nuclear generation fleet built in the 1980s and the 1990s. The operating life of these nuclear generators is assumed so far to be 60 years, so by 2050 most will have been decommissioned. To keep emissions in the power sector to a minimum, two options are thus on the table: replacing retiring reactors with new ones and renewables or replacing them with renewables only to eventually reach a power system with 100% renewable energy sources. Both options rely on significantly scaling up variable renewables: wind and solar photovoltaic (PV) power.

The French Ministry for the Ecological Transition commissioned the International Energy Agency (IEA) and France’s transmission system operator, RTE, to jointly carry out a framework study identifying the conditions and requirements to assess the technical feasibility of scenarios in which the power system would be based on very high shares of renewables. This report presents their findings.

The main conclusions focus on four sets of strict conditions that would need to be met towards a technically secure integration of very high shares of renewables in a large power system such as that of France:

1.  Even if they still need to be proven at large scale, there is a general scientific consensus that technological solutions to maintain power system strength – and hence system stability – without conventional generation exist in several cases. Specific difficulties are expected in the case of a system with a significant share of distributed solar PV. Further assessment of the impacts of distributed PV on the distribution network is needed as well as their implications for electricity security.
2.  System adequacy – i.e. the ability of a power system to cope with load at all times – can be ensured even in a system mainly based on variable renewables such as wind and solar PV, when substantial sources of flexibility are available, including demand-response, large-scale storage, peak generation units, and well developed transmission networks and interconnections. The maturity, availability and cost of these flexibility sources need to be considered.
3. The sizing of operational reserves and the regulatory framework for balancing responsibilities and procurements would need to be substantially revised, and forecasting methods for variable renewables continually improved.
4. Substantial grid development efforts would be necessary beyond 2030 at both transmission and distribution levels. This requires strong pro-active steps and public engagement in long-term planning, assessing costs and working with citizens on social acceptance. These efforts can nonetheless be partly integrated in renewals of ageing network assets.

Assessing the costs of these conditions is beyond the scope of this report. However, the study underlines that costs may be substantial and that meeting these conditions has deeper technical and social implications. Further socio-economic studies are necessary, building on the conclusions of this report, to assess the different options to reach carbon neutrality by 2050 in France. As a next step, in 2021 RTE will publish a full assessment of different electricity scenarios to reach carbon neutrality. 

The SNBC relies on three pillars: energy efficiency (reducing final consumption by almost half, from 1 600 TWh to 900 TWh), a stronger use of biomass (from 200 TWh to 430 TWh by 2050), and a more significant role for (decarbonised) electricity as a final fuel, which must go from 25% to 50% of final energy needs by 2050. The increase in electrification of end uses is in line with most European scenarios that aim for carbon neutrality.

The SNBC does not specify which kind of decarbonised electricity should be used, but it does not foresee the use of fossil fuels associated with carbon capture, utilisation and storage (CCUS) nor the massive use of biomass or biogas for electricity generation. This leaves renewables and nuclear power as the two possible options.

France’s civil nuclear programme, implemented in the aftermath of the oil shocks in the 1970s, led to the building of 58 nuclear reactors in 25 years, amounting to up to 400 TWh per year of decarbonised electricity generation – around 75% of the French total electricity generation. As a result, 93% of electricity generated is carbon-free. In 2019, the average emission factor of electricity generation was 35 g CO₂/kWh – 11 times less than Germany and 13 times less than the Unites States in the same period. While hydropower has also contributed to France’s low average emission factor, it amounts to only 11% of electricity production, and the potential for further expansion is limited as full potential was already exploited in the 1970s.

Nevertheless, questions over the future of France’s nuclear fleet have started to emerge over the last ten years. First, the desire to rebalance the electricity mix, seen as too dependent on one technology and one generation of reactors, has emerged at the social and political levels, in particular after the accident at the Fukushima-Daiichi nuclear power plant in Japan in 2011. The development of renewables in France (mainly wind power and solar PV) which started in the late 2000s, sped up recently with the adoption of the Multi-Annual Energy Plan (Programmation pluriannuelle de l’énergie, or PPE). The PPE envisages a significant increase in annual renewable generation from 109 TWh to 300 TWh in ten years. At the same time, a target to reduce the share of nuclear in electricity generation to 50% by 2035 has been signed into law.

Second, it is now paramount to develop an industrial strategy for replacing existing nuclear generators when they reach the end of their lifetimes. The reactors currently in operation were built over a short period: the fleet is 35 years old on average, with 27 out of 58 reactors scheduled to reach the 40-year threshold over the next five years. A major industrial programme has been launched to extend the lifetime of these reactors past 40 years, subject to case-by-case assessment and approval by the independent Nuclear Safety Agency. As of today, there is a broad consensus that current generators may not be operated for more than 60 years and that the vast majority will be decommissioned between 2030 and 2050.

France will therefore be confronted with the task of managing the retirement of some of its nuclear reactors, while at the same time expanding its decarbonised electricity supply, to reach climate change mitigation targets. This, regardless of the political discussion of recent years about the “rebalancing” of the electricity generation mix between nuclear and renewables. In other words, what is at stake is a strategy to replace the capacity for generating 400 TWh of decarbonised electricity in France over the next 30 years. Two options are on the table:

1. Replacing some decommissioned reactors with new ones – i.e. launching a new nuclear programme – and complementing this with higher shares of renewables to obtain a full decarbonised electricity mix by 2050.
2. Replacing decommissioned reactors with renewables only. If this option is chosen, the share of renewables would reach about 85-90% by 2050 and 100% by 2060.  

While both options would significantly increase the share of variable renewable generation, the second option, 100% renewables, departs so considerably from the current situation that numerous questions arise about its technical feasibility.

Apart from small systems mainly based on dispatchable hydroelectric units, there is no experience of operating such systems. Advocates for 100% renewables claim – with reason – that past alarmist predictions of operational problems from increasing renewables in the power sector have been proven wrong. However, given that there is no proof of concept regarding the integration of high shares of variable renewables –such as wind and solar PV- in large power systems, technical challenges are bound to come up. This uncertainty has raised scepticism about large shares of renewables as an option to combat climate change, particularly in comparison with other low-carbon solutions. In France this debate has been lively, given that the current generation mix combines exceptionally low CO₂ emissions with a high reliance on nuclear power.

While no consensus has been reached in the French debate about the overall possibility of a future power system based only on renewables – notably with high shares of variables sources like wind or solar PV – the first step is to assess whether and under what conditions and requirements such a system could be technically feasible, which is the aim of this report. It is the first milestone established in the framework of the PPE, which states that the different options to ensure the power supply-demand balance in the long run need to be reviewed in mid-2021.

The report identifies and discusses conditions and requirements for the technical feasibility of scenarios with high shares of variable renewables. Results on this topic are a necessary precondition for further studies, including the next stages of the general modelling started by RTE for 2021. Technical feasibility has been considered in a broad sense, encompassing key technical system-wide challenges associated with such scenarios.

The report does not address whether those scenarios are socially desirable or appealing, or how much they cost and whether they are financially sustainable. Those questions will be addressed at a later stage on the basis of simulation work conducted by RTE with stakeholders. Even if one or more scenarios may appear technically feasible, any conclusions on their socio-economic desirability would thus require further analysis. Moreover, the report does not compare high renewables scenarios with others, either technically or economically.

This report has been commissioned by the French Ministry for the Ecological Transition. To answer the questions asked by the Ministry, the IEA and RTE have joined forces. In October 2020, the IEA published its latest World Energy Outlook, which includes two scenarios to reach global net-zero emissions. The Sustainable Development Scenario (SDS) puts the energy system on track to achieve sustainable energy objectives in full, including the Paris Agreement, energy access and air quality goals. The SDS assumes that relevant carbon-neutrality targets of countries and companies as announced so far are achieved, helping to put global emissions on track for net zero by 2070. For the first time, the IEA has expanded the SDS with a Net‑Zero Emissions by 2050 case, which details the necessary steps in the next ten years to put global emissions on track for net zero by 2050. In addition, Energy Technology Perspectives 2020 offers a complementary tool for policy makers to understand the necessary steps in terms of technology maturity requirements. Notably, the ETP 2020 highlights that half of the cumulative emissions reductions needed for reaching net-zero emissions by 2050 stem from technologies that are not commercially available today.

RTE publishes a yearly report (Bilan prévisionnel) which serves as the reference report on the electricity sector in France, both for the adequacy assessment and for perspectives for the power sector.

The current report combines the international experience of the IEA with the modelling expertise of RTE to identify what precisely is at stake in opting for large shares of renewables and to provide strategic insights for policy making. It provides high-level conclusions on some points, and identifies questions requiring additional work and new analyses regarding other points.

RTE will follow up on those questions in its ongoing work to establish new reference scenarios for the public in France, based on a wide-ranging consultation with all stakeholders. This work, expected to conclude in 2021, will be published in the next edition of Bilan prévisionnel, dedicated to long-term scenarios aiming at reaching net zero by 2050.

From a technical point of view, four main issues would prove challenging in transitioning to very high shares of variable renewable energy sources in a large electricity system like France’s.

1. System strength, with a focus on reduction of inertia

Nowadays the stability of large, interconnected power systems is based on the alternator rotors of conventional power plants rotating together at the same frequency, set nominally at 50 Hertz in Europe as well as in most of Asia and Africa.

These rotating machines stabilise the system by contributing to inertia and short-circuit power. This contribution is called “system strength”. When the system faces a disturbance, these machines automatically help to stabilise frequency by releasing some of the kinetic energy stored in their rotating rotor before other reserves take over. In addition, they are able to generate their own voltage waveform and to synchronise independently from other electricity sources: they are naturally “grid-forming”. Rotating machines are a historical cornerstone of power system stability.

With higher shares of non-synchronous generation sources like wind and solar PV, rotating machines would become less available. As opposed to conventional generators, wind farms and PV panels are connected to the network through power converters. Present conventional converter technologies do not provide full system strength. They do not contribute to system inertia, as they are not able to generate their own voltage waveform and are dependent on the frequency signal given by other sources, such as conventional generation, to run properly: they are “grid-following”. Future power systems will host many more converter-based connections via electric‑vehicle charging, grid-scale battery storage, HVDC connections and others.

This report finds that while several technical solutions exist to overcome the difficulty of inertia reduction, they are at different stages of maturity. While some are already deployed in field operations, others are in the research and development stage and will need to be tested in real-life settings before being deployed at scale.

To achieve a high share of renewables, the first step is to develop a new way for converters to operate when they start dominating the system. New services are needed to cope with the reduction of inertia. These services, known as fast frequency response or synthetic/virtual inertia, can be provided by specific converters that allow renewable generation to adjust very rapidly to a deviation of the frequency signal, e.g. by temporarily increasing power output, thereby helping to re-establish system frequency. Such services have already been implemented in Ireland and Quebec. However, these solutions do not have the same effect as the inertia of rotating machines and cannot guarantee secure operation of the system if the instantaneous share of PV and wind becomes very high, for example, above 60-80%, in the synchronous area. It is therefore necessary to go beyond such solutions in systems based on wind and solar PV and significantly revamp the way the power system is operated.

To go further, one solution would be to deploy synchronous condensers. They operate similarly to synchronous generators: their motors provide inertia and short-circuit power and, therefore, system strength, but they rotate freely, without producing electrical power. Synchronous condensers are a well-known and proven technology, historically used to maintain voltage in specific areas, including in France. More recently, this solution has been used in Denmark and South Australia and has proven effective to ensure system stability. While this solution has been proven in specific situations, a generalised roll out in the context of large-scale system strength has yet to be evaluated. The associated costs of deployment are low on an individual basis, but they must be taken into account with other system costs in a thorough economic evaluation of scenarios with high shares of renewable production.

Another possibility would be to develop grid-forming controls for converters that give wind and solar power plants the ability to generate their own voltage wave. This solution has been successfully tested in the laboratory (for example, in the European project MIGRATE) and on microgrids, but not yet at the scale of a large power system, where other complications could arise. Full-scale experiments are needed in the coming years to validate this concept.

The issues at stake are not just technical. The regulatory instruments chosen to deploy these technologies and the institutional allocation of responsibility for providing these services need to be considered as well in light of the current French and European institutional frameworks. Policy makers need to keep oversight on this topic taking into account the cost impacts on end consumers, manufacturers, developers and system operators. For example, specific grid-forming capabilities could be required through technical standards levied on original equipment manufacturers, impacting technology costs. Alternatively, transmission operators could directly own or contract synchronous condensers owned by third parties or create competitive parameter-based services, leaving the technology choice and successful deployment to market participants. All three options come with specific cost and system security trade-offs, which will need to be evaluated in follow-up analyses and eventually decided on by policy makers.

Finally, the technical challenges related to system strength differ depending on the mix of renewables. Moving towards grid-forming controls would be much more challenging for a power system relying largely on distributed solar PV generation, as it would have a strong impact on the operation of distribution grids. The challenge would be smaller if the system were mainly based on large wind farms, onshore or offshore, compared to many solar PV installations connected to low-voltage networks. In any case, a system with a significant share of distributed PV would need a further detailed assessment of the impacts on the distribution network and their implications for electricity security.

To sum up:

1. There is now a broad scientific consensus on the theoretical stability of a power system without conventional generation.
2. However, the necessary technical solutions in power electronics are not yet commercially available at the scale of large meshed systems like those in France. Thus, innovation and large-scale testing would need to accelerate.
3. It will be necessary to continue R&D projects. This will include launching demonstration and pilot-projects, learning from operational experience of the considered solutions, and understanding and testing system stability in large-scale applications. 

2. Adequacy and flexibility resources to cope with the variability of wind and solar PV

Coping with the variability of energy produced from wind and solar PV is the main challenge for integrating renewables in power systems. Yet, power systems with high shares of renewables in France will be based mainly on wind and solar PV. Hydropower has already been developed to nearly its full potential, so it can only cover part of future needs, and the potential of bioenergy for electricity generation is limited.

On average, wind and solar PV have different and complementary seasonal generation patterns, with more wind power on winter and more PV generation in summer. But their monthly, weekly, daily and hourly variability create challenges for keeping a continuous system balance. Thus, maintaining system adequacy – the ability of a power system to cope with load at all times –requires developing additional tools to cope with this fundamental variability in generation.

RTE adequacy analyses have repeatedly concluded that the development of wind and PV scheduled in the next ten years in France under the PPE can be accommodated by existing and planned generation units (in France and neighbouring countries) as well as demand-side flexibility at a reasonable level. Beyond 2035, however, it is no longer possible to accommodate higher shares of renewables without significantly developing flexibility.

Targeting a system based overwhelmingly on variable renewable electricity generation therefore requires the development of four types of flexibility, in different proportions depending on the considered scenarios.

1. New dispatchable peaking units. These currently use fossil fuels – albeit in very small proportions – but they could use other fuels, such as hydrogen or biogas.
2. Large-scale, dedicated storage facilities, such as batteries to address daily fluctuations; new or revamped pumped-hydroelectric generation units to address weekly variations; or synthetic fuels production (power-to-hydrogen or power-to-gas) and storage to address inter-seasonal and inter-annual variability.
3. A considerable amount of demand-side flexibility. Installations in buildings and factories would need to be able to respond automatically to market triggers or explicit requests from grid operators.
4. Strengthened power grids, enabling large-scale geographical power system integration to mitigate local variations and facilitate access to a maximum of flexibility sources. Regional and international interconnection of networks will indeed play a major role in integrating higher shares of renewables to the power system. 

The development of new uses for electricity provides opportunities to develop flexibility sources on the demand side, such as electric vehicles, hydrogen production and its multiple uses, and heating in new buildings, where advanced smart management demand can be implemented. Extensive use of the batteries of electric vehicles with smart charging systems could be a key element to ensure adequacy. Batteries will already be there for the purpose of fuelling vehicles, so the main challenge would be to define the right interfaces with the power system. Mobilising the necessary flexibility resources will require both physical investment in assets like storage as well as regulatory and market frameworks than can unlock smart, distributed flexibility solutions.

In addition to adapting the power system to integrate variable renewables, it is possible to optimise the deployment and operation of variable renewables through best combinations of PV and wind capacity. This will require optimal siting targeting high capacity factors and, possibly, minimising the size of grid connections. Such measures would be complemented by the participation of variable renewables in markets and accurate forecasting of infeed.

Complementing variable renewables with peakers, storage, extensive demand-side management and grid to ensure system adequacy has important cost implications. Cost analysis, which is not in the scope of this report, will be carried out at a later stage of the process in RTE’s future 2050 scenarios. Any future evaluation should focus, however, on overall system costs rather than on metrics like levelised cost of electricity because these fail to account for costs associated with technical requirements (security of supply and others). Both the IEA and RTE believe that any cost estimation should take into account all the costs associated with a high share of renewables, including the costs of storage, demand-side flexibility and grid development. This report shows that those costs might be substantial in France after 2035. It sets the stage for the future cost-evaluation on metrics shared at international level.

This kind of scenario has implications in terms of industrial feasibility, which should be studied in conjunction with RTE’s future 2050 scenarios. Since the capability to reach a very high share of renewables in the mix will rely on batteries, digital technologies for smart load management, or synthetic fuel production (power-to-hydrogen or power-to-gas) and storage, it is important to assess the maturity of these technologies and the ability to efficiently roll them out at scale. Future analyses should not only focus on projected cost but also encompass a purely industrial dimension and consider the challenges of increasing the rate of deployment for technologies at various levels of technological readiness. This implies thinking about the conditions for developing the necessary industrial environment.

Finally, the environmental footprint of deploying these flexibility resources – on land use and critical materials – must be considered. This applies to their social acceptance – in particular, to generalised demand-side response uptake in the residential sector or for the deployment of infrastructure such as electrolysers or interconnectors. This environmental and societal analysis must consider the whole energy system, integrating all flexibility resources.

To sum up:

1. Attaining ~50% share of renewable energy generation in France by 2035 under the PPE scenario would be possible with existing non-renewable generation capacity and some additional demand-side flexibility or distributed storage. But, reaching higher shares afterwards would require additional peak generation units, large-scale storage and/or intensive demand-side management at some point.
2. Rather than using metrics like LCOE, future assessments of the cost of different options for high shares of wind and PV should focus on system costs, including flexibility resources, balancing and grid assets.
3. Significant steps have to be made in coming years to take some flexibility resources to industrial-scale deployment, for example large-scale flexibility from electric vehicles or synthetic fuels production (power-to-hydrogen or power-to-gas) and storage. 

 3. Operational reserves

In a liberalised power system, market parties are responsible for keeping their portfolio in balance. However, operational reserves are procured and used by the TSO to balance the system in real time wherever markets do not deliver or in case of unforeseen outages. Reserves are sized to cover uncertainties and contingencies in generation, consumption and grid capacity. The shift towards a greater share of variable renewables, along with changes in electricity consumption foreseen in the SNBC, mean that the type and amount of those reserves will also change.

Although the dimensioning of operational reserves and balancing responsibilities is a well understood issue in current debates about market design, the issue has not attracted a lot of attention in relation to long-term scenarios at policy level. Moreover, the impact of wind and solar PV on operational reserves is generally not considered in academic publications on large-scale deployment of renewables.

For the time being, France does not need to procure large volumes of operational reserves compared to other countries, and its balancing system is competitive, resulting in low costs for the consumer compared to other European countries. The generation fleet is largely dispatchable and market regulations provide for resource pooling and proactive balancing systems that help to minimise costs. 

In the future, increasing variable renewables will require revising current practices for the sizing of operational reserves and the allocation of balancing responsibilities. Today, the uncertainties taken into consideration to determine these reserves are mainly related to risks of sudden disconnections of major generation units and of unexpected deviations in consumption patterns. However, the practices for procuring and using operational reserves should evolve to account for rising shares of wind and solar PV. This is because wind and solar PV are difficult to forecast accurately, even within one day before real time, because of the local characteristics of the weather patterns and the small size of these units. This difficulty is particularly pronounced for distributed solar PV systems because a large proportion of their production cannot be monitored in real time – i.e. they do not necessarily have a metering device that measures generation in real time and transmits to grid operators.

As a result, high shares of wind and solar PV could lead to important uncertainties about future production, even a few hours from real time. Efforts are therefore needed to improve the real-time monitoring of wind and, especially, solar PV to enable better predictability or a direct and accurate estimation of net load (i.e. load minus distributed generation). Short-term forecasting, sizing and operations of reserves could also be improved. Current methodology for sizing operational reserves will need to be updated to take into account the increase in uncertainty due to a large share of variable renewables.

In the extreme situation, when current conditions of predictability and real-time monitoring for renewables were applied up to 2050, the need for operational reserves increases dramatically. By contrast, this increase could be largely mitigated if full monitoring were implemented. This difference underscores the need for improved visibility of new renewable generation, forecasting techniques and balancing obligations.

To keep the need for new operational reserves to a reasonable level, efforts to improve predictability and real-time monitoring of variable renewables are being made. Using new technologies to collect, transmit and analyse data from distributed generation like PV panels is one path taken to meet this objective. Another way of balancing the system in the future would be to use renewables as balancing units that respond to more stringent obligations, like those currently placed on traditional units. Wind and PV units have been installed in recent years as marginal units and thus have not been subject to the traditional regulations applied to bigger generation units. This practice, perfectly sound for the early stages of developing renewables, is not suited to scenarios in which renewables may comprise nearly all generation by 2050. This issue is increasingly being addressed in recent grid codes around the world, albeit only for new generation units.

Lastly, future areas for improvement also include the use of new sources of power system flexibility – storage, peaking units, demand-side flexibility and especially the charging of electric vehicles – for balancing the system in real time. They could indeed provide additional power reserves that can be activated very quickly. There remain operational challenges to overcome in the field, and stepping up efforts to demonstrate successful large-scale participation of distributed units to provide significant volumes of operational reserves – for example, with electric car charging – could be an industrial priority in the coming years.

To sum up:

1. Integrating large volumes of wind and solar PV requires dedicated action to cope with uncertainties and the decentralised nature of variable renewables. This will also affect how operational reserves are sized and used.
2. Forecasting methods need to be improved while work is already under way to optimise balancing processes at the international level.
3. Over the next ten years, regulatory improvements are necessary to take into account the changing nature of the power mix. These should make it possible to use the flexibility of wind farms, PV panels and electric vehicles, and establish conditions for new units and refurbished ones in order to ensure that the power system has sufficient reserve capability.  

4. Grid development

To reach high shares of renewables in the power mix, electricity grids will need to be developed and modified in important ways.

A power system with a higher share of renewables is indeed much less geographically concentrated than a system with nuclear power or large thermal fossil fuel plants. More grid reinforcement and expansion are necessary to connect generation facilities and match demand patterns, geographically and in time. By contrast, if the grid is correctly developed, such a system would be more resilient to the loss of single large components such as network line or a generation unit.

Key grid developments are already planned for the next ten years both at the national level and as part of the wider regional European power system. In France, RTE has recently published its reference Ten-Year Network Development Plan (Schéma décennal de développement de réseau, or SDDR) up to 2035. At the European level, the European Network of Transmission System Operators (ENTSO-E) publishes a Ten-Year Network Development Plan (TYNDP) every two years, which already accounts for the implications of planned grid development within and between countries. To accommodate the integration of renewables, these plans envision not only grid adaptations but also a push in grid optimisation through the generalisation of real-time use of flexibility from renewables (mainly wind farms). In the medium term, these changes are enough to keep the need for new grids in France lower than, for example, Germany today or France in the 1980s, while still attaining ambitious targets for renewables.

Beyond 2030, however, grid expansion, reinforcement and restructuring would be needed to increase the share of renewables in the power mix. The report explains the key actions needed to shape this grid refurbishment and expansion.

By 2050, the very high-voltage grid used for interregional and international exchanges (400 kV and most of 225 kV) will still be in place. Built mostly between the 1970s and the 1990s to make the nuclear programme possible, it was planned to allow large transfers of energy across France. As such, this backbone is well adapted to integrating renewables. Apart from a few well-identified weak zones, this very high-voltage backbone can cope with the variability of renewables until 2030 under the assumptions of the PPE scenario. Greater ambitions for 2050 will require more substantial reinforcements, however. The emergence of new transmission technologies – such as superconductivity, gas-insulated assets, and AC to HVDC switching – should make it possible to gradually adapt the existing system to an even larger share of renewables. 

Offshore grids and cross-border interconnections would also need to be developed in addition to the reinforcements to the national transmission network. On the one hand, this would allow integrating offshore energy to its full economic potential. Wind turbines far from shore require planning for a co‑ordinated offshore transmission grid, possibly connected to sites of decommissioned nuclear plants. On the other hand, grid expansion should also significantly increase exchange capacity across Europe by adding more cross-border interconnections (west-east and north-south).

By 2050, the high-voltage grid (63-90 kV – which is part of the transmission grid in France), traditionally used to supply electricity to consumers, will need to be redesigned in any case, as it has been built mainly between the end of the Second World War and the 1970s. Preparing for this renewal is an important part of the network plan RTE published in September 2019. This grid will need to be significantly adapted to take into account the higher targeted share of variable renewables. This represents an opportunity to keep costs on track by combining refurbishment and expansion.

Social acceptance and costs will be crucial factors in implementing structural changes in the grid. A power system with very high shares of renewables would mean a bigger footprint for grids (as well as generation units), and local resistance to grid reinforcement is sometimes already high – even when shares of wind integration are low and grid reinforcements much smaller than required to meet the energy transition goals. Lastly, while costs do not currently seem to be the most substantial point of discussion when it comes to grid development, they should be considered in future studies when looking at the context of power system development towards 2050. 

To sum up:

1. In France, the current transmission grid provides a good platform to build upon. It is not poised to become a limiting factor for the integration of renewables in coming years if targeted reinforcements are implemented. To further increase the share of renewables, adjustments to the grid structure are necessary but remain limited compared with the pace of grid development in the 20th century.
2. Beyond 2030, fundamental grid expansion, reinforcement and restructuring will be needed to reach high shares of renewables. Given the time required to consult stakeholders and obtain permits, these developments must be planned soon and decided in the coming years.
3. Gaining social acceptance for grid adaptation is a key factor in facilitating the development of wind and PV. Solutions such as forward spatial planning of grid adaptations (for example, to connect offshore grids) and using flexibility sources in addition to new grids could play a significant role in enabling this transformation.
4. Public authorities and regulators need to establish an effective system to enable industries to attract enough investment for network development and overcome social acceptance hurdles. 

The findings and methodological propositions of this report will be used to follow work undertaken at French level, particularly for the next issue of RTE long‑term scenarios (Bilan prévisionnel), which will study the means to achieve net‑zero emissions by 2050.

This work, initiated in 2019, has been held in consultation with stakeholders. It is currently at the end of its framing phase, before simulations are conducted and discussed collectively. This integrates (1) a complete description of possible scenarios (including differences in lifestyles and individual behaviours) with and without new nuclear reactors; (2) a quantitative technical analysis of supply-demand balance and grid requirements, taking into account the effect of climate change according to different IPCC scenarios; (3) an extensive modelling of the European power sector; (4) a detailed modelling of interactions between the power sector and other energy carriers; (5) a full system cost-analysis; and (6) an assessment of environmental effects, including not only greenhouse gas emissions and footprint but also items such as the need for critical minerals and the impact on land use. Those new scenarios are scheduled to be completed in 2021