Grid‐Constrained Sizing and Predictive Dispatch of a PV–Battery–Hydrogen Energy Community: An Island Case Study

Abstract

Grid‐connected energy communities on weak or capacity‐limited feeders increasingly consider hybrid photovoltaic (PV)–battery–hydrogen systems yet planning studies often size assets against annual balances while leaving the grid connection as an effectively unconstrained buffer. Here, we develop a boundary‐centred planning architecture that couples long‐horizon investment decisions to schedule‐feasible operation. A genetic algorithm (GA) selects component capacities, inverter rating, and contracted import/export power, while a rolling‐horizon (MILP) formulation implements model predictive control (MPC) resolves tariff‐coupled dispatch with bounded daily load shifting. Using a public‐sector community on the island of Formentera (Spain), we benchmark reactive load‐following against predictive operation under 0% to 8% flexible demand. Predictive coordination reshapes both, sizing and energy flows by converting temporal foresight into “capacity value” at the point of common coupling. Relative to load‐following, the optimiser tightens the contracted exchange envelope from ±78 to ±37 kW and reduces the inverter rating from 120 to 77 kW, while increasing PV utilisation and reducing grid import reliance to roughly 9%–11% of demand. These gains arise from coordinated storage operation: the battery provides mostly short‐term balancing, while hydrogen supplies a smaller secondary contribution through surplus absorption and occasional deficit support. Economically, modest flexibility amplifies the effect, reducing net present cost (NPC) by 9% and lowering levelised electricity cost (LCOE) from 0.243 to 0.218 €/kWh. Together, the results show that hybrid community value is anchored in enforceable boundary control, and that limited behavioural adaptation can substitute for contracted capacity in weak‐grid planning.