Hydrogen-Enabled Microgrids for Railway Applications: A Seasonal Energy Storage Solution for Switch-Point Heating

Abstract

Switch-point heating systems are essential for railway reliability and safety in winter, but present logistical and economic challenges in remote regions. This study presents a novel application of a hydrogen-enabled microgrid as an off-grid energy solution for powering a switch-point heating system at a rural Austrian railway station, offering an alternative to conventional grid-based electricity with a specific focus on enhancing the share of renewable energy sources. The proposed system integrates photovoltaics (PV), optional wind energy, and hydrogen storage to address the seasonal mismatch between a high energy supply in the summer and peak winter demand. Three energy supply scenarios are analysed and compared based on local conditions, technical simplicity, and economic viability. Energy flow modelling based on site-specific climate and operational data is used to determine hydrogen production rates, storage capacity requirements and system sizing. A comprehensive cost analysis of all major subsystems is conducted to assess economic viability. The study demonstrates that hydrogen is a highly effective solution for seasonal energy storage, with a PV-only configuration emerging as the most suitable option under current site conditions. Thus, it offers a replicable framework for decarbonising critical stationary railway infrastructure.

1. Introduction

The global shift toward sustainable energy systems has underscored the importance of renewable energy integration, particularly in critical infrastructure sectors such as transportation [1,2,3]. Within railway operations under wintry weather conditions, electrically powered switch-point heating systems are essential for maintaining track safety and ensuring uninterrupted service, by preventing snow and ice accumulation on railway points during winter precipitation events [4,5]. Along electrified routes, these systems are typically connected to the traction power grid. On non-electrified routes, they must be connected to the national power grid. However, reliance on national grid electricity supply poses logistical, economic, and sustainability challenges, and grid extensions in remote non-electrified areas can be costly or infeasible [6,7,8,9]. This underscores the necessity for an alternative energy carrier that both decreases dependence on the conventional electricity grid and actively contributes to increasing the share of renewable energy sources.

To address these challenges, the integration of renewable energy with long-duration storage has emerged as a promising pathway—particularly through hydrogen-based microgrids [10,11,12,13,14,15]. Hydrogen facilitates the decoupling of energy supply and demand by allowing surplus renewable electricity, typically generated in summer, to be stored chemically and utilised in winter when demand peaks [16,17,18,19,20]. This is achieved through water electrolysis, where electrolysers convert electricity into hydrogen, which can then be stored using one of two primary methods: compressed hydrogen or metal hydride systems—both offering enhanced seasonal storage potential with lower energy losses compared to conventional battery storage [21,22]. Fuel cells subsequently reconvert the stored hydrogen into electricity, enabling flexible supply for various applications [23].

The flexibility and scalability of hydrogen microgrids have been extensively studied in various contexts, with a growing body of research confirming their suitability for off-grid and hybrid applications. Alam et al. designed a photovoltaic and fuel cell-based microgrid system using hydrogen storage to stabilise a DC system for railway applications [24]. Additionally, Ayodele et al. [25] and Babatunde et al. [26] demonstrated the feasibility of hybrid renewable energy systems with hydrogen storage for rural clinics and off-grid communities in sub-Saharan Africa, highlighting improvements in system reliability and CO₂ emission reductions. Damato et al. demonstrated the viability of a microgrid integrating hydrogen and battery storage in a small community in Italy, underscoring the effectiveness of hydrogen as a seasonal long-term storage solution enabling year-round off-grid energy autonomy [27]. Moreover, Meriläinen et al. investigated hybrid off-grid energy systems in Nordic climates combining hydrogen with battery storage, underscoring the critical role of hydrogen for seasonal storage in cold environments [28]. Furthermore, Ceylan et al. evaluated green hydrogen-based hybrid energy systems for both off-grid and on-grid applications, demonstrating the critical potential of hydrogen integration for decarbonising energy supply while improving system reliability [29].

From an economic perspective, hydrogen storage systems offer competitive long-term viability compared to conventional alternatives [30]. Moreover, PEM (Proton Exchange Membrane) fuel-cell systems integrated with renewable energy can lower the operational costs, reduce the reliance on fossil fuels, and minimise the environmental impact compared to diesel generators [31]. Capital costs associated with electrolysers and fuel cells are expected to decline with technological advancements and industrial scaling, supporting the case for early adoption in niche applications such as railway switch-point heating [32]. Furthermore, policy frameworks at the EU and national levels, such as the European Union’s Hydrogen Strategy [33] and Hydrogen Strategy for Austria [34], emphasise the integration of green hydrogen in transport and infrastructure to meet ambitious decarbonisation targets.

The railway sector has seen extensive developments in hydrogen-powered rolling stock and refuelling infrastructure, but the stationary application of hydrogen microgrids to power auxiliary systems remains relatively underexplored [35,36,37]. Research by Deng et al. [6] proposed green microgrids specifically tailored for railway infrastructure, incorporating hydrogen storage to increase resilience and reduce reliance on carbon-intensive electricity grids. Such microgrids can provide enhanced operational autonomy and facilitate climate adaptation by maintaining critical infrastructure functionality during grid outages or extreme weather events. Mitrofanov et al. emphasised the strategic relevance of stationary hybrid renewable energy systems in railway applications, where the integration of renewable energy sources and energy storage systems can significantly improve the efficiency and environmental friendliness of railway transport [38].

The seasonal nature of switch-point heating loads presents a convincing case for hydrogen storage, given the significant mismatch between summer renewable resource availability and winter energy demand. Additionally, hybrid energy systems that combine photovoltaic (PV) systems and wind turbines leverage complementary power-generation profiles—solar resources peak in summer, while wind tends to be stronger in winter—thereby smoothing supply variability and reducing required storage [28,39].

This study presents a concept and techno-economic assessment of a hydrogen-enabled microgrid designed to power a railway switch-point heating system at a rural, non-electrified station in Austria. As part of the analysis, the seasonal energy demand and electricity generation from renewable energies are modelled on the basis of site-specific climate and operating data, with the electricity demand derived from real-world operational data of the existing switch-point heating system. The study also includes the sizing of core components such as the electrolyser, hydrogen storage and fuel-cell system, alongside an evaluation of associated capital and operational expenditure to assess the feasibility of deploying such systems in practice.

While the integration of photovoltaics, wind energy, and hydrogen-based storage within microgrids has been studied extensively [10,11,12,13,14,15], the novelty of this work lies in its application to stationary, safety-critical railway infrastructure—specifically, the decarbonization of switch-point heating systems in remote and non-electrified locations. Previous research in this sector has primarily emphasised hydrogen for rail propulsion [35,36,37], whereas its use as a seasonal energy buffer for small-scale, fixed infrastructure remains underexplored. By applying established energy-balance modelling tools to a distinct infrastructure use case, this study provides a replicable design and techno-economic baseline for off-grid hydrogen microgrids in cold-climate railway contexts. The core challenge addressed involves establishing a reliable and autonomous power supply for switch-point heating in settings where extending the traction grid is not viable. Such systems must operate with high reliability, while managing significant seasonal mismatches between energy supply and heating demand. In this regard, hydrogen offers unique advantages as a long-duration storage medium capable of ensuring energy availability during prolonged periods of low renewable power generation. The study fills a gap in the current research by evaluating the technical feasibility and operational relevance of a hydrogen-based microgrid tailored for stationary rail infrastructure, highlighting its potential contribution to decarbonizing critical fixed assets in the transport sector.

2. Materials and Methods

The selected case-study location for the hydrogen-enabled microgrid is the station Gars-Thunau, situated on the Kamptalbahn railway line in Lower Austria; see Figure 1 and Figure 2. This rural station represents a typical regional railway facility regularly subjected to frost and snowfall during the winter season. In these conditions, the uninterrupted operation of switch-point heating systems is critical for railway safety and operational reliability.

However, due to the lack of railway electrification and a relatively modest load profile, a decentralised and decarbonised energy supply was examined. The heating system under consideration serves two switch-points, each equipped with electric heating rods. The system operates seasonally, typically from November to February, with an average of 120 operational hours per year.

Based on measured real-world operational data and railway infrastructure specifications, the installed switch heating system has a total power demand of 13.8 kW. During the 2023/2024 heating season, with 144 h of operation, this resulted in a total energy demand of approximately 2 MWh (see Figure 3).

2.1. Microgrid System Description and Calculations

The proposed microgrid system (see Figure 4) is designed to capture and store renewable energy from solar and wind in times of abundance, ensuring enough reserves are available to meet high power demands during winter. Therefore, hydrogen is produced via water electrolysis, utilising electricity generated from on-site renewable sources. The system architecture comprises an electrolyser, dimensioned to cover peak hydrogen production rates, a hydrogen storage system—either compressed hydrogen or metal hydride containers—sized to accommodate the full annual hydrogen demand, a fuel-cell system for converting stored hydrogen back into electricity to operate the switch-point heating, a battery storage system for smoother operation and renewable energy sources modelled with site-specific performance parameters.

For the annual energy balance, the analysis adopts a purely balance-based approach considering electricity and hydrogen flows. The renewable generation is evaluated using a combination of simulation models, empirical measurements, and site-specific approximations adapted to the conditions at the case-study location. Auxiliary loads are primarily covered by renewable electricity supply or buffered through the battery storage system.

With these assumptions, the calculated hydrogen demand, the simulated renewable power generation, and the energy balance of the microgrid system is constructed. The annual balance highlights the following advantage of hydrogen as a seasonal energy storage medium: Hydrogen is produced and accumulated during periods of surplus renewable electricity generation, stored with minimal energy losses and subsequently reconverted to electricity to supply the switch-point heating system during the winter season when energy demand reaches its peak.

System calculations are performed with hourly resolution and weekly balancing to assess dynamic energy flows throughout the year. Heating demand is based on measured real-world operational data and railway infrastructure specifications for the switch-point heating system, which typically activate when ambient temperatures drop below 0 °C in combination with precipitation. PV generation profiles were simulated using BIMsolar based on regional climate data, incorporating panel tilt, orientation, and seasonal variations [40,41]. While wind energy scenarios are modelled using empirical data from commercially available small wind turbines investigated at the UAS Technikum Wien’s Lichtenegg wind test site and approximated to the analysed location and wind conditions [42].

Hydrogen production is calculated based on surplus renewable electricity available for water electrolysis. The electrolyser is sized to match the peak hydrogen production requirement and operates flexibly between 10% and 100% load to maximise system efficiency and adapt to variable renewable generation. During high-yield, low-demand summer months, the energy management strategy (EMS) prioritises PV generation for on-site loads and diverts surplus electricity to hydrogen production. In winter, when heating demand peaks and renewable generation is low, the fuel-cell system operates predominantly in the mid-load range to maximise efficiency and extend component lifetime. The battery storage system serves as a short-term buffer, absorbing rapid PV fluctuations or covering transient loads, while also facilitating smooth power delivery. This coordinated control strategy ensures stable operation of the microgrid, with renewable energy used for direct supply, stored as hydrogen for seasonal shifts and buffered through the battery for short-term balancing and efficiency optimisation. Conversion efficiencies are calculated with fuel-cell efficiency assumed at 43% and electrolyser efficiency at 62%, based on manufacturer data [43,44].

2.2. Renewable Power Generation

To assess the feasibility of hydrogen integration, three renewable energy scenarios at the case-study location were examined, as shown in

Table 1. Overview of renewable energy supply scenarios for the microgrid system.

Scenario	Configuration
Scenario 1: PV	Power generation via PV
Scenario 2: Wind	Power generation via small wind turbine
Scenario 3: Hybrid (PV + Wind)	System combining PV and small wind turbine

.

2.2.1. Scenario 1: Photovoltaic (PV)

A feasible option for energy supply is a PV system. Due to the rapid expansion of PV installations in recent years, considerable expertise has been developed in this sector and costs have significantly decreased thanks to large-scale production. The solar potential across Lower Austria is relatively uniform, and in the investigated region approximately 1150 kWh/kW_p. Because PV modules rely on sunlight incidence to generate electricity, their output is restricted to daytime hours and varies seasonally with changes in solar altitude and irradiance. PV generation was simulated for a system designed to be installed on a flat rooftop of an existing railway station building. The PV array is assumed to have an almost ideal east–west orientation with a tilt angle of 20°, optimising energy capture within the constraints of the available roof space; see Figure 5a,b.

2.2.2. Scenario 2: Wind

Another option for the microgrids energy supply is via small wind turbine. Unlike large-scale wind turbines, they have lower power outputs in the range of a few kW but benefit from a lower hub height—typically around 10 m—making their installation easier and less costly. A significant advantage of wind turbines is their ability to generate electricity both at night and during winter months, provided sufficient wind speeds. This characteristic offers a relatively even production profile throughout the year. However, a brief site analysis at the case-study location indicates a low wind potential, with an annual average wind speed of approximately 3 m/s at a height of 10 m height [45].

This highlights a limitation of small wind turbines: due to their low construction height, they are significantly affected by local topography, surrounding buildings and wind shadows, all of which reduce energy yield. Wind sites are generally classified based on average annual wind speeds as follows: below 2.5 m/s: poor site, 2.5 to 4.0 m/s: moderate site, 4.0 to 5.0 m/s: good site and above 5.0 m/s: excellent site [46]. It should be noted that currently available small wind turbines typically begin converting wind kinetic energy to electricity at wind speeds of around 3 m/s, with power generation increasing with the cube of the wind speed (v³).

2.2.3. Scenario 3: Hybrid: PV + Wind

In addition to evaluating PV and small wind turbine systems individually, a combined scenario incorporating both systems was also analysed. This configuration can provide a more balanced and reliable annual energy yield and add redundancy to the energy supply. While the wind turbine’s energy output is relatively evenly distributed throughout the year, with a modest increase during the winter months due to stronger and more frequent winds, PV generation exhibits a pronounced seasonal variation. PV systems typically produce their highest energy yields during the long, sunny days of summer, while output decreases significantly in winter due to shorter daylight hours, lower solar angles, and increased cloud cover. Additionally, wind turbines offer the advantage of generating electricity during night-time hours, complementing the daytime-only production of PV modules. This hybrid approach, therefore, has the potential to smooth seasonal and daily variability in renewable generation, enhancing the overall stability and resilience of the hydrogen-enabled microgrid system.

2.3. Site and Climate Context

The project site in Gars am Kamp, Austria, is already experiencing clear effects of climate change, consistent with national trends. Almost all of the warmest years on record for Austria have occurred within the last 25 years, with 2024 again ranking among the warmest years since the beginning of meteorological observations. Since pre-industrial times (in comparison with the period of 1881–1910), the annual mean temperature in Austria has increased by approximately 3.1 °C [47]. These changes affect not only the frequency of warm days and tropical nights but also the occurrence of ice days (days with the maximum temperature below 0 °C) and frost days (days with the minimum temperature below 0 °C), as well as precipitation patterns. The winter season 2024/25 was among the driest on record, with up to 80% less precipitation and a 90% reduction in snow depth compared to historical averages [48]. Similar temperature and precipitation anomalies have been recorded in the region surrounding the project site.

Climate scenarios for the KLAR! region Horn, which includes the station Gars-Thunau, indicate ongoing warming alongside shifts and reductions in precipitation. By 2018, the regional temperature was already 2.3 °C above the 1971–2000 average, with projections forecasting further increases between 1 °C and 4 °C depending on mitigation efforts [49]. Increased hourly heavy rainfall events (+15% over the last 40 years) have been documented, although long-term trends in total annual precipitation remain uncertain [50,51]. Depending on climate protection ambitions, the maximum 5-day precipitation in the KLAR! region Horn can increase by 7% to 11% [49].

Hourly meteorological data from stations near Gars am Kamp show a decline in ice days over the last 13 years, while frost days have slightly increased [52]. An analysis of heating operation data revealed that switch-point heaters are triggered under various weather conditions, generally around temperatures near freezing point combined with precipitation events. However, the limited operational data of the switch-point heating system—spanning only one year—indicates that no single climatic variable independently triggers heater activation, making it difficult to accurately predict future heating demand. These climate developments underscore the importance of adaptive and resilient energy solutions for railway infrastructure, as shifts in temperature and precipitation patterns will influence both heating demand and renewable generation profiles.

3. Results

The energy demand for the switch-point heating system at the station during the last heating season is quantified based on operational data and system specifications. The total power demand is 13.8 kW, with approximately 144 h of operation, resulting in a total annual energy demand of about 2 MWh, as shown in Figure 3. This demand is strongly seasonal, with heating requirements concentrated in the winter months from November until February. Renewable energy supply is primarily derived from a 10 kWp PV system installed on a station building rooftop with an east–west orientation and a tilt angle of 20°, optimised for available space and solar exposure. Simulation of the PV system output predicts an annual yield of approximately 10.3 MWh, as shown in Figure 6, providing a significant surplus relative to the heating load.

The contribution of wind energy, using a 5 kW small wind turbine installed in proximity to the site, is limited by the average annual wind speed of approximately 3 m/s at 10 m hub height, classifying the location as marginal for wind power generation. Annual wind energy supply is estimated at around 1.6 MWh, with a relatively even seasonal distribution and increased output in winter; see Figure 7.

In addition to the standalone PV and wind scenarios, this study also investigated a hybrid configuration combining photovoltaic panels and a small wind turbine. As illustrated in Figure 8, the combined generation profile reveals the complementary nature of the two energy sources. While PV output dominates the annual production, wind energy contributes steadily throughout the year and becomes particularly relevant during the winter months, when solar irradiation is low. In several winter weeks, the simulated power generation of the small wind turbine even exceeds the output of the PV system, providing valuable supplemental energy during periods of peak heating demand.

Despite this seasonal advantage, the overall contribution of wind energy remains limited at the specific site, primarily due to the low average annual wind speed and the resulting modest annual energy yield. Nevertheless, it is important to emphasise that at other sites with stronger and more consistent wind resources, hybrid systems may provide significant benefits. They include a more evenly distributed production profile throughout the year, increased system redundancy and enhanced operational resilience, particularly in off-grid applications where uninterrupted power supply is critical. Wind turbines also offer the advantage of night-time energy supply, complementing the daytime-only output of PV systems.

3.1. Hydrogen Production and Energy Balance

Throughout the year, hydrogen is produced during periods of surplus PV generation, primarily in summer, and stored for use in the winter season. This design directly addresses the pronounced seasonality of switch-point heating demand, which peaks during cold spells from late autumn to early spring. Owing to its high energy density and long-term storability, hydrogen is well suited to bridging this gap, ensuring reliable heating operation even during extended periods of low solar irradiance or weak wind conditions. In the system model, hydrogen production is limited by a maximum usable storage capacity of 150 kg. As illustrated in Figure 9, the overall energy balance indicates that hydrogen serves as an effective seasonal storage medium, buffering the mismatch between high summer renewable energy supply and winter heating load.

3.2. System Dimensioning and Cost Analysis

A techno-economic assessment was carried out to evaluate and compare the economic performance of the hydrogen-enabled microgrid under two storage configurations: compressed hydrogen and metal hydride. The analysis includes an overview of capital expenditures (CAPEX) based on supplier quotations available to the authors and operational expenditures (OPEX) derived from literature.

Table 2. CAPEX and OPEX overview and nominal specifications of major system components for the hydrogen-enabled microgrid.

System	Component	Value	CAPEX		OPEX
Hydrogen	Electrolyser (AEM)	5 kW	19,200 €	*	34 €/(kg/d)/y	[53]
	Electrolyser Power Module	-	4200 €	*	-
	Water Treatment	-	5300 €	*	-
	Hydrogen Purification	-	6000 €	*	-
	Fuel Cell (PEM)	20 kW	60,000 €	*	0.1 €/kWh	[53]
	Compressor **	2 Nm3/h	40,000 €	*	4%CAPEX/y	[54]
	Storage (Compressed H2)	150 kg H2	77,000 €	*	2%CAPEX/y	[10]
	Storage (Metal Hydride)	150 kg H2	300,000 €	*	-
	Measurement and Control	-	9800 €	*	-
	Safety	-	7000 €	*	-
	Hydrogen Accessory, Work	-	17,000 €	*	-
	Regulatory Submission	-	30,000 €	*	-
Battery	Battery Storage	20 kWh	10,000 €	*	10 €/kWh/y	[10]
PV	Modules	10 kWp	2500 €	*	24 €/kW/y	[10]
	PV Accessory, Work	-	7800 €	*	-
Wind	Wind Turbine	5 kW	18,000 €	*	3%CAPEX/y	[10]
	Wind Accessory, Work	-	14,500 €	*	-
Water	Rainwater Treatment	-	10,400 €	*	-
System	Integration	-	7500 €	*	-

* Values from supplier quotations. ** Compressor only relevant for compressed hydrogen storage.

presents the nominal system components with associated cost data.

The hydrogen production and utilisation system comprise a 5 kW AEM (Anion Exchange Membrane) electrolyser with an associated power electronics module, integrated hydrogen purification and water treatment units with total investment costs of EUR 34,700, and a 20 kW PEM fuel cell for energy conversion, totalling EUR 60,000. The sizing of this system was guided by the objective of balancing renewable energy availability with heating system requirements under average seasonal conditions. The fuel cell was selected to reliably meet the 13.8 kW peak heating load while operating within a partial-load range to avoid efficiency loss. Similarly, the electrolyser was dimensioned to utilise excess summer PV generation without oversizing.

In the compressed hydrogen configuration, the system employs a compressor and ten high-pressure storage bundles, each capable of storing up to 17 kg of hydrogen at 300 bar, with a total cost of EUR 77,000. Although the annual hydrogen demand is lower, ten storage bundles are assumed to ensure operational safety margins and account for the fact that the full nominal capacity of each bundle cannot be fully utilised in practice. In contrast, the metal hydride scenario utilises a 20-foot container-based storage solution featuring an integrated thermal management, with an estimated cost of EUR 300,000.

This hydrogen subsystem constitutes the dominant portion of total capital expenditure. In the compressed hydrogen configuration, it accounts for nearly 80% (Figure 10) of the total investment, primarily driven by the costs of high-pressure storage infrastructure—including the compressor—and the fuel-cell system. In the metal hydride scenario, this share rises to more than 85% (Figure 11), reflecting the significantly higher capital cost associated with metal hydride storage technology.

For PV, an installed capacity of 10 kWp was considered, with an estimated module cost of EUR 2500 and additional EUR 7800 for accessory equipment and installation, resulting in a total CAPEX of approximately EUR 10,300. The battery storage system was designed with a nominal energy capacity of 20 kWh and a system cost of EUR 10,000, including minor accessory costs. The total investment cost for the small wind energy system, including a 5 kW wind turbine, foundation, mast and installation work, amounts to approximately EUR 32,500. This encompasses both the turbine hardware and the necessary structural and electrical components required for safe and functional integration. In comparison, the wind energy system incurs more than triple the investment cost of the PV system, highlighting the cost-efficiency advantage of photovoltaic solutions at the studied location.

The footprint of the hydrogen infrastructure is estimated at approximately 25 to 30 m², while the PV system requires around 60 m², both of which are feasible within the available space at the railway station.

Water supply for electrolysis is based on rainwater harvesting with water treatment equipment at a cost of EUR 10,400, and mains water redundancy. Water demand is estimated at approximately 3.5 m³/year, based on a consumption of 25 litre/kg_H2. This value reflects not only the stoichiometric requirement of 9 litre/kg_H2 but also accounts for additional process demands such as purification, cooling, and auxiliary systems. Consequently, the total water consumption of the system must be assessed based on the overall operational requirements rather than the theoretical minimum alone. The average annual rainfall across the area of Lower Austria is approximately 670 mm, corresponding to a potential rainwater yield of 0.67 m³ per square metre of horizontal catchment area [51]. Based on this figure, a roof surface of around 5 m² would theoretically suffice to collect 3.5 m³ of water per year. However, when accounting for losses due to evaporation, runoff inefficiencies, and filtration requirements, a slightly larger collection area—approximately 10 m²—is recommended to reliably meet the system’s annual water demand, which can be easily accommodated at the case-study location.

While the CAPEX of the hydrogen microgrid system are analysed in detail, the as-assessment of long-term economic viability must also consider OPEX. At this concept stage, precise figures are difficult to quantify due to the lack of operational data from an actual installed system. However, preliminary estimates from the literature [10,53,54] suggest that hydrogen systems (fuel cells, electrolyser) and the compressor will account for a significant proportion of the expected operating expenses due to periodic maintenance and system monitoring needs. These costs can vary substantially depending on site-specific factors such as accessibility, required safety infrastructure, and personnel availability.

Systems utilising metal hydride storage—where no compression unit is required—are anticipated to yield significantly lower operational costs over the system lifetime. This benefit underscores one of the primary economic advantages of the metal hydride configuration, particularly in remote or labour-intensive contexts, even though its capital cost is comparatively higher. In terms of comparative investment costs, the total CAPEX for the compressed hydrogen system is estimated at approximately EUR 346,000, while the metal hydride configuration amounts to EUR 529,000 and identifies the hydrogen system—particularly the storage—as the largest cost driver in hydrogen-enabled microgrids.

While the capital-intensive nature of hydrogen microgrids remains a challenge, the costs for electrolysers and fuel-cell system could fall as production and policy incentives increase. Additionally, the environmental and resilience benefits of the system—particularly in remote or non-electrified railway applications—may justify these costs from a broader sustainability perspective.

4. Discussion

This study evaluated the feasibility of a hydrogen-enabled microgrid for powering a switch-point heating system at a rural railway station in Austria. The concept leverages solar and wind energy in combination with hydrogen as seasonal storage to address the temporal mismatch between renewable energy supply and heating demand. The findings confirm that hydrogen integration provides an effective strategy for long-duration energy storage, critical for maintaining autonomous operation throughout the year.

The comparative assessment of different renewable generation configurations, as has been observed in previous studies [29,55], highlights significant trade-offs. The wind-only scenario, though technically viable, suffers from suboptimal wind conditions at the site—characterised by an average annual speed of just 3 m/s at 10 m hub height. Moreover, the economic analysis indicates that the additional capital costs associated with installing a wind turbine—including the foundation, mast, and electrical integration—do not justify the relatively small gains in energy supply under current conditions. Therefore, while the hybrid PV–wind system shows moderate improvement in supply reliability, the PV-only system remains the most effective solution for this location, offering greater simplicity, lower costs and a consistent seasonal surplus. This aligns with the findings in [56], which indicate that the location plays a crucial role in determining the optimal solution for renewable power-generation systems. However, solar power production is inherently intermittent and highly seasonal, necessitating substantial energy storage to bridge extended winter periods with limited irradiance. Hydrogen storage, produced via electrolysis and reconverted via a fuel-cell system, addresses this challenge by storing excess summer energy chemically for deferred winter use. The modelled system—with a 5 kW electrolyser and annual hydrogen demand of roughly 140 kg—provides sufficient coverage under typical meteorological conditions at the case-study location. These findings can be compared to results from similar hydrogen microgrid studies in the literature [25,26,27,28,29], which have demonstrated comparable storage capacities and system configurations but different load applications for off-grid solutions and seasonal energy shifting, thereby reinforcing the validity and relevance of the proposed design.

System dimensioning underscores the importance of balancing component sizing, operational flexibility and cost [22]. The choice between compressed hydrogen and metal hydride storage introduces trade-offs between capital expenditure, safety, and operational complexity [57]. Compressed hydrogen systems are cost-effective upfront but require high-pressure compressors and add technical and safety burdens. Metal hydride storage, while substantially more expensive, avoids the need for compressors and offers potential advantages for permitting and safety management [58]. Notably, the hydrogen system represents the largest share of the system’s total CAPEX—nearly 80% in the compressed hydrogen configuration and more than 85% in the metal hydride case—primarily due to high component costs. However, further advances in electrolyser and fuel-cell technologies, coupled with cost reductions driven by economies of scale and policy incentives, are expected to improve system economics over time. The maintenance requirements and OPEX are currently only approximated, as no operational data from an installed system is available. These costs are expected to vary significantly depending on factors such as personnel needs and the distance of the installation from the nearest maintenance facility. Moreover, pilot projects typically involve elevated operational costs due to setup complexity, the novelty of the technology, and the need for additional oversight [59]. It should be emphasised that this concept study has not yet incorporated energy supply redundancy or system fault tolerance into the design. For the pilot implementation, ensuring a backup energy supply—such as connection to the public grid—is essential to guarantee uninterrupted heating operation. This backup system would be especially vital during periods of unusual energy demand, equipment failure or severe weather events. Furthermore, contingency measures could include the delivery of hydrogen from centralised production facilities as an emergency supply option in cases where prolonged low renewable generation limits on-site hydrogen production. Redundancy can also be enhanced through the duplication of critical components—such as installing dual electrolyser or fuel cell units—to maintain system operability even in the event of a component failure.

While hydrogen technologies still face cost and deployment challenges, recent pilot projects and national strategies in Europe highlight growing support for their integration into transport and energy systems. This study focuses on stationary hydrogen use, which avoids the complexity of vehicular applications and offers a practical near-term solution for decarbonizing fixed rail infrastructure such as switch-point heating. Its proven durability reinforces this suitability: benchmarks and the literature [10,20,53,60] indicate that current electrolyser and fuel-cell systems achieve lifetimes of more than 20,000 operating hours or 10 years with degradation rates below 10%, with future targets aiming to reduce degradation and extend lifetimes even further. Combined with demonstrated high availability, these performance indicators underline the technical maturity and reliability of hydrogen components for stationary, safety-critical applications in remote railway environments.

To support the sustainability claims of the proposed hydrogen microgrid, a preliminary estimate was conducted to determine the CO₂ emissions saved. Assuming the switch-point heating system’s annual electricity demand of 2 MWh and replacing Austrian national grid electricity with an average emission factor of 0.167 kg CO₂/kWh [61], the system would save approximately 334 kg CO₂ per year. Although this absolute value is modest at the single-site scale, the approach is inherently scalable across multiple remote rail segments. More significantly, the system offers two key strategic and environmental benefits: it decreases reliance on conventional grid electricity and facilitates a greater integration of locally generated renewable energy. However, this estimate only considers a reduction in emissions during the operational phase; emissions associated with the production and manufacturing of system components have not been included and represent a limitation of this assessment.

The observed regional warming trend suggests a potential long-term reduction in heating demand for switch-point systems at the project site [49]. Milder winters could de-crease the frequency and duration of freezing conditions that necessitate heating, thereby reducing overall energy demand. However, the increased variability in weather patterns, marked by a general decline in total precipitation alongside an increased likelihood of intense, short-duration rainfall events and the complexity of factors triggering heater activation introduce uncertainty into future demand forecasting [50]. This variability underscores the need for a flexible and adaptive energy system capable of responding to sudden cold spells with simultaneous precipitation, despite a general warming trend. Climate projections indicating ongoing temperature increases and altered precipitation patterns further emphasise the dynamic nature of the renewable resource base, potentially impacting the timing and availability of solar and wind energy critical for hydrogen production [62]. Consequently, the design and operation of hydrogen-enabled microgrids must incorporate climate resilience, ensuring sustained reliability and efficiency under changing environmental conditions. Integrating climate data into system modelling and control strategies is thus essential to optimise performance and maintain uninterrupted switch-point heating in the face of evolving climatic challenges.

Limitations and Future Work

This concept study provides a technically grounded feasibility analysis of a hydrogen-enabled microgrid for powering a switch-point heating system at a rural railway station, but several limitations must be acknowledged.

The system modelling is currently based on calculated energy flows and theoretical component efficiencies. These figures reflect ideal operating conditions and do not account for real-world degradation or partial load efficiencies. As no operational hydrogen microgrid currently exists at the studied site, real-world performance data is not available. Therefore, the results should be interpreted as indicative system-level feasibility. Empirical validation using real-world operational data from similar microgrid systems or pilot installations is planned to strengthen model reliability and refine key assumptions.

Control and energy management strategies were beyond the scope of this initial concept study but represent an essential focus for future work. While this study emphasises system dimensioning and energy balancing using static operational profiles, the optimal operation of a hydrogen-enabled microgrid relies on advanced supervisory control to coordinate renewable generation, battery buffering, electrolyser scheduling, hydrogen storage and fuel-cell dispatch aligning with strategies outlined in related hydrogen-integrated microgrid studies [12]. To achieve this, advanced control algorithms—such as rule-based (e.g., Fuzzy Logic) or optimisation-based energy management strategies (e.g., Pontryagin’s Minimum Principle)—will be developed and tested. Their integration is essential for ensuring efficient energy flow, prolonging system lifetime, and minimising operational costs. Furthermore, electrolyser and fuel-cell capacities were selected based on practical system constraints and peak load requirements but without formal sensitivity or cost–performance optimisation. Future work will incorporate simulation-based optimisation methods to evaluate trade-offs in component sizing under varying load and resource profiles.

Average meteorological profiles were used for energy balancing. PV generation was simulated using regional irradiance data [41], while wind estimates were derived from turbine data from our own test site, adapted for local terrain and wind conditions [45]. While this provides a reasonable approximation of long-term trends, there are resulting uncertainties, particularly for short-term or extreme events. Future phases will include site-specific resource measurements and dynamic simulations under adverse conditions to validate this assumption. While this study focuses on a rural railway station in Lower Austria, the methodology and system design are broadly applicable to other non-electrified rail locations. Key factors such as PV yield, wind availability and heating demand are site-specific and must be adapted accordingly. Regions with lower solar irradiance or harsher winters may require larger PV arrays or added wind capacity. As heating demand strongly influences hydrogen production and storage sizing, site-specific climate and operational data are essential. A modular system architecture is suggested to enable flexible adaptation to local conditions.

Finally, operational costs and component lifetimes were only roughly estimated based on literature values due to limited operational data. Lifecycle metrics such as replacement intervals and system longevity will be integrated in subsequent stages, along with financial indicators like Net Present Value (NPV) and Levelized Cost of Energy (LCOE). It should be noted that cost is not the primary decision criterion in this context. The main objective of the proposed microgrid is to enable autonomous, grid-independent operation, particularly for remote, non-electrified rail infrastructure where reliability during extreme winter conditions is critical. Self-sufficiency and resilience take precedence over strict cost minimization, and the system is intentionally designed to tolerate moderate cost premiums in exchange for increased operational independence. As a concept study, the focus lies in proving technical feasibility and functional adequacy, while detailed economic optimisation is reserved for future implementation phases.

These limitations reflect the early-stage nature of this study and will be progressively addressed in follow-up research activities.

5. Conclusions

This study confirms the technical feasibility and strategic benefits of a hydrogen-enabled microgrid to power a switch-point heating system at a rural, non-electrified railway station in Austria. Thus, it not only decreases reliance on the national power grid but also places particular emphasis on increasing the proportion of renewable energy sources. The key finding is the effectiveness of hydrogen as a long-duration storage medium, capable of bridging the seasonal mismatch between surplus summer supply and peak winter heating demand. Among three evaluated scenarios, the PV-only configuration proves most effective under current site conditions, offering technical simplicity, economic viability and sufficient power generation. Wind integration, while beneficial in theory due to winter and night time generation, provides limited added value given the site’s low wind speeds. Nevertheless, hybrid systems could be advantageous in regions with stronger wind potential. Cost assessments reveal that hydrogen storage and fuel-cell components dominate capital expenditures, with compressed hydrogen storage offering lower upfront costs compared to metal hydride systems. Despite the higher investment, future cost reductions driven by technology advances and policy incentives are expected to enhance economic viability. In summary, this concept study offers a replicable and adaptable framework for implementing hydrogen-enabled microgrids in cold-climate railway infrastructure. The findings illustrate that such systems offer both environmental and operational benefits, including reduced CO₂ emissions, improved energy resilience and decreased dependence on the national power grid. By leveraging these strengths, hydrogen-enabled microgrids can play a transformative role in the decarbonisation and modernisation of critical transportation infrastructure.