Ángel Arcos-Vargas

Battery energy storage systems (BESS) and pumped storage hydropower (PSH) compete for the same arbitrage revenues in electricity markets, yet capacity planning often treats storage as a single technology or imposes investment levels. This paper assesses whether both technologies can profitably coexist in a marginal-pricing day-ahead market and which capacity mix results from market-driven investment. A bi-level framework is proposed. At the operational level, the hourly dispatch of both technologies is modeled as a non-cooperative multi-period Cournot game with intertemporal storage constraints, solved in a rolling horizon, with price-demand elasticity derived from actual day-ahead bidding curves. At the investment level, capacity additions are modeled as a static non-cooperative game whose payoff matrices are obtained from the dispatch model. The framework is applied to the Spanish day-ahead market with 2025 data. At current costs, the Nash equilibrium consists of 6 GWh of BESS and 4 GWh of PSH, with returns on investment of 9.13% and 4.98%, respectively, without subsidies. This storage absorbs about 3.1 TWh per year, mostly surplus renewable energy, reduces the average daily price spread by about 30% and lowers peak prices, while leaving the average price nearly unchanged. Both technologies operate mainly in daily cycles. The results are intended to provide regulators and system operators with a market-consistent benchmark for storage targets, remuneration schemes and policy incentives.

Reaching a decarbonised power system in the coming decades requires the in-tegration of large shares of variable renewables into the grid while ensuringsupply-demand adequacy and operational security. Energy storage, such aspumped hydro or large-scale batteries, is a natural choice to manage residualload variability in this context. However, the intelligent deployment of variablerenewable energy sources can also help reduce the storage requirements, deliv-ering economic benefits to the system. In this paper, we study the overall effectof two aspects, namely the panel layout in photovoltaic plants and the flexibilityof the hydropower production. Using a customary generation expansion plan-ning model for a hypothetical decarbonised scenario, we investigate the optimaldeployment of new PV and battery capacities under different investment costsand demand flexibility assumptions. When applied to our case study for theSpanish system, we conclude that installing PV panels at steeper angles thanthose that maximise annual yield may result in investment cost reductions ofnearly 8%. Realizing the importance of the hydropower fleet in countries likeSpain, we also test the robustness of the expansion model under different hydro-logically constrained scenarios, confirming the crucial effect of this technologyon total system costs and observing the effect of panels installation angle on theoptimal use of the constrained hydrological resources

The rapid decarbonization of European power grids has elevated solar photovoltaic (PV) generation to a central pillar of the energy mix, yet high penetration levels introduce volumetric and ramp risk. On 12 August 2026, a total solar eclipse over Spain caused a forecastable contraction in PV generation, offering a natural stress test for both system operations and electricity markets. The novelty of this study lies in its explicit three-layer decomposition of the event into the physical generation shortfall, the operational ramp requirement, and the day-ahead price co-movement, together with an identification-aware treatment that separates anticipatory bidding from a causal price effect. Using 15 min resolution data from Red Eléctrica de España (REE) and the Iberian Energy Market Operator (OMIE) for 11–13 August, the analysis documents a peak PV shortfall of 78.9% (3.00 GW) at 20:45 CET and a cumulative deficit of 4.48 GWh during the 19:30–22:00 window, with ramp rates 57% steeper than the clear-sky baseline. Day-ahead prices exhibited a peak premium of +45.43 €/MWh (+24.6%) at 20:30 relative to a structural counterfactual; however, because day-ahead auctions clear before delivery, this price movement is interpreted as anticipatory bidding rather than a purely causal shock, an identification challenge that is explicitly discussed and left to future work using intraday and balancing market data. An illustrative economic decomposition is also provided, together with a discussion of the conditions under which co-located battery energy storage (BESS) could mitigate asset exposure to similar events, offering insights ahead of the 2 August 2027 eclipse in southern Spain.

This paper addresses the joint modelling and optimization of battery energy storage systems (BESS) and pumped storage hydro (PSH), to assess whether the coexistence of BESS and PSH is economically optimal in a marginal pricing, limited-liquidity day-ahead market. A bi-level model has been developed. The lower level is a deterministic Real-Time Optimization (RTO) model optimizing the dispatch and net revenues of both technologies for predefined installed storage capacities. The model replicates market participants’ behavior under different bidding strategies, using day-ahead bidding curves as a proxy for price–demand elasticity. Because both technologies aim to maximize their own net income, the interaction naturally leads to a non-cooperative differential game with an optimum in the Nash equilibrium. In the upper level, the investment model, the optimal combination of technologies is determined by maximizing expected profitability under the simulated market conditions. Investment decisions are formulated as an equilibrium problem in which the payoff matrix is derived from net incomes computed by the dispatch model. The approach complements conventional Capacity Expansion models by providing a more realistic and market-oriented representation of storage, supporting regulators and system operators in designing more effective planning criteria, remuneration schemes and policy incentives for storage deployment. Its applicability is illustrated for the Spanish power system using 2025 day-ahead market data.

Reaching a decarbonised power system in the coming decades requires the integration of large shares of variable renewables into the grid while ensuring supply-demand adequacy and operational security. Energy storage, such as pumped hydro or large-scale batteries, is a natural choice to manage residualload variability in this context. However,organised deployment of variable renewable energy sources can help to structurally reduce the need for storage requirements, delivering economic benefits to the system. In this paper, we study the overall effect of two aspects, namely the panel layout in photovoltaic plants and the flexibility of the hydropower production. Using a customary generation expansion planning model for a hypothetical decarbonised scenario, we investigate the optimal deployment of new PV and battery capacities under different investment costs and demand flexibility assumptions. When appliedto our case study for the Spanish system, we conclude that installing PV panels at steeper angles than those that maximise annual yield may result in investment cost reductions of nearly 8%. Realizing the importance of the hydropower fleet in countries like Spain, we also test the robustness of the expansion model under different hydrologically constrained scenarios, confirming the crucial effect of this technology on total system costs and observing the effect of panels installation angle on the optimal use of the constrained hydrological resources.

This work develops a replicable method for designing the optimal renewable hydrogen production facility, applicable to any site and based on technical parameters and actual equipment costs. The solution is based on the integration of photovoltaic (PV) energy with lithium-ion battery storage systems, which maximizes electrolyzer operating hours and significantly reduces the Levelized Cost of Hydrogen (LCOH). This study shows that increasing the inclination of the photovoltaic modules reduces the need for storage, optimizing operation and extending the electrolyzer’s annual operating hours. In the Seville case study, with current costs and efficiencies, a minimum LCOH of €4.43/kg was achieved, a value well below market benchmarks, opening the door to a potentially competitive industrial business. The analysis confirms that electrolyzer efficiency—particularly specific power consumption—is the most important factor in reducing costs, while technological progress in photovoltaics, storage, and equipment promises further reductions in the coming years. Overall, the proposed methodology offers a practical and scalable tool to accelerate the economic viability of green hydrogen in a variety of contexts.