The value of electric energy storage in electricity systems with high shares of wind and solar PV: the case of France in the energy transition

The adoption of ambitious targets for variable renewable energies (VRE) such as wind and solar has important effects on the technical and economic operation of power systems. Increasing shares of VRE will in particular require the deployment of more flexible and responsive technologies. Key flexibility providers in the scope are demand side management (DSM) and different forms of electric energy storage (EES) such as pumped hydroelectric (PHS), Li-ion batteries (Li-ion), and compressed air (CAES), among others. It have been previously showed how the value and the deployment of such new flexibility providers depended on the shares of VRE shares introduced into the system (Brijs et al., 2016; Van Stiphout et al., 2015; Villavicencio, 2017). Building on this works, this paper explores the value of storage in the context of a realistic Brownfield model calibrated on the existing French electricity system. In particular, this paper compares the value of storage (a) in a system corresponding to the target of 27% VRE production formulated by the French government in its 2015 Energy Transition Act by 2020 and (b) in a system corresponding to the target of 40% VRE production formulated in the same Act by 2030. The latter case will necessarily reflect the additional target which by 2025 limits the share of nuclear power to 50% of electricity production. In 2020, 4.7 GW of DSM are sufficient to provide the required flexibility and no EES investments will be needed. By 2030, however, in addition to a comparable level of DSM, 3.2 GW of additional EES investments are required. These storage solutions will generate an economic value of euro 350 million per year and will increases overall welfare by euro 670 million per year by 2030. The modeling yields a number of additional policy relevant results. First, limiting nuclear production will open opportunities for alternative base and mid-load providers, mainly gas, implying a threefold increase of CO₂ emissions compared to 2020 levels. Second, wind and PV increase their surplus at the expense of profit reductions of baseload conventional technologies. Third, peak-load capacity is reduced but the capacity remuneration mechanism (CRM) allows covering up fixed costs to attain the zero profit condition. Fourth, EES lowers the cost of VRE integration which under the assumption of a complete cost retrofitting to consumers, made them significantly better-off, benefiting from a less constrained system. Fifth, an important dynamic inconsistency exists concerning the investment path to optimally attain both 2020 and 2030 targets, which urgently requires a decision at the policy level for prioritizing or target harmonization. (author)