Australia

In sustainable energy transitions the utilization of hydrogen is crucial providing flexibility in the operation of net-zero emission renewable-based energy systems. This paper presents a study on the optimal operation of netzero emission multi-energy future microgrids that utilize hydrogen as an alternative fuel instead of natural gas. The electrolyzers’ output is injected into the hydrogen grid to meet demand or converted back to electricity later using generating units owing to the storage capability of pipes called linepack. For this purpose a detailed mathematical model is developed to simulate the main characteristics of grids (e.g. voltage current hydrogen flow and pressure) as well as various components (e.g. renewable systems electrolyzers and hydrogen-fired units). To become more realistic a possibilistic-robust approach is developed to account for the uncertainty arising from the lack of real-world implementation. By representing a case study a test is performed to evaluate the possibility of employing a low-pressure gas grid to meet the demand for hydrogen. After that the effects of electrolyzers are analyzed in the presence and absence of the uncertainty consideration approach. The result indicates that despite hydrogen’s lower energy density compared to natural gas it is still feasible to satisfy the same energy demand level considering the technical characteristics of the grid. The integration of electrolyzers can reduce wind curtailment by 2 % and supplement hydrogen demand by 50 %. A higher level of conservatism in the possibilistic-robust approach leads to an increase in the mean value of the objective function and a reduction in the standard deviation under the realization of uncertain parameters which provides the decisionmakers with a more realistic insight.

Achieving net zero by 2050 will require decarbonising stand-alone energy applications. Hydrogen is increasingly viewed as a promising energy carrier but its economic viability remains uncertain due to the lack of consensus on future demand and limited deployment of key components such as fuel cells in stationary stand-alone applications. This study investigates whether hybridising batteries with hydrogen can deliver meaningful cost benefits under future cost trajectories. Using a Monte Carlo framework we simulate 8000 scenarios across constant and seasonal load profiles varying the capital costs of batteries fuel cells electrolysers and hydrogen tanks based on 2025 estimates and 2050 projections. Our results show that hydrogen integration only becomes economically attractive when multiple component costs decline simultaneously. The fuel cell-to-battery power capital cost ratio emerges as the dominant driver of levelised cost of energy (LCOE) improvements. For constant loads median LCOE savings remain below 12 % with more than 5 % savings only achieved when the fuel cell cost is less than 7 times that of the battery. Seasonal nighttime loads offer a wider theoretical LCOE savings range (0–156 %) but substantial gains occur only under unrealistic cost mixes where battery costs remain high and fuel cell costs fall sharply. These findings highlight the sensitivity of hydrogen viability to load profile characteristics and cost interdependencies. They underscore the need for targeted cost reduction strategies particularly for fuel cells to justify added system complexity. These findings are important considerations for future investment and policy decisions.