Hydrogen fuel cell backup power is a modern way to ensure an uninterrupted and decentralised supply of electricity. A stationary and mobile fuel cell, commonly referred to as a hydrogen generator, is used to produce electricity during power outages or other emergency situations. These fuel cell backups are designed to provide a reliable and efficient source of electricity for critical loads, such as hospitals, data centres, and other critical infrastructures. Hydrogen generators are typically used in situations where a reliable and efficient source of electricity is needed, and in cases when conventional diesel generators are not the priority. These generators can also be used in remote locations where access to the grid is limited or unavailable, or in applications where the use of fossil fuels is not practical or desirable. The article covers the thematic related to comparison of diesel and hydrogen generators, with regards to advantages and shortcomings of the latter, as well as provides an insight into possible use of hydrogen generators in Latvia.

The management of municipal solid waste remains a critical environmental and energy challenge across the European Union (EU), where a significant portion of waste still ends up in landfills, generating landfill gas (LFG) rich in methane and harmful impurities. In Latvia, despite national strategies to enhance circularity, untreated LFG is underutilized due to inadequate purification infrastructure, particularly in meeting biomethane standards. This study addressed this gap by proposing and evaluating an innovative, multistep LFG purification system tailored to Latvian conditions, with the aim of enabling the broader use of LFG for energy cogeneration and potentially biomethane injection. The research objective was to design, describe, and preliminarily assess a pilot-scale LFG purification prototype suitable for deployment at Latvia’s largest landfill facility—Landfill A. The methodological approach combined chemical composition analysis of LFG, technical site assessments, and engineering modelling of a five-step purification system, including desulfurization, cooling and moisture removal, siloxane filtration, pumping stabilization, and activated carbon treatment. The system was designed for a nominal gas flow rate of 1500 m³/h and developed with modular scalability in mind. The results showed that raw LFG from Landfill A contains high concentrations of hydrogen sulfide, siloxanes, and volatile organic compounds (VOCs), far exceeding permissible thresholds for biomethane applications. The designed prototype demonstrated the technical feasibility of reducing hydrogen sulfide (H₂S) concentrations to <7 mg/m³ and siloxanes to ≤0.3 mg/m³, thus aligning the purified gas with EU biomethane quality requirements. Infrastructure assessments confirmed that existing electricity, water, and sewage capacities at Landfill A are sufficient to support the system’s operation. The implications of this research suggest that properly engineered LFG purification systems can transform landfills from passive waste sinks into active energy resources, aligning with the EU Green Deal goals and enhancing local energy resilience. It is recommended that further validation be carried out through long-term pilot operation, economic analysis of gas recovery profitability, and adaptation of the system for integration with national gas grids. The prototype provides a transferable model for other Baltic and Eastern European contexts, where LFG remains an underexploited asset for sustainable energy transitions.

This study evaluates the technical, design, and economic feasibility of large-scale hydrogen storage in deep water-bearing geological formations (aquifers), presenting it as a scalable solution for seasonal energy storage within the European Union’s decarbonization framework. A techno-economic model was developed for a 1 BCM facility, integrating geomechanical, microbial, and thermodynamic criteria. The results indicate a recoverable hydrogen fraction of 70–85%, with dissolution and microbial conversion losses limited to below 10% under optimized operational regimes. Geochemical and microbiological modelling demonstrated that sulfate-reducing and methanogenic bacterial activity can be reduced by 80–90% through controlled salinity and pH management. The proposed design, incorporating high-permeability sandstone reservoirs (100–300 mD), hydrogen-resistant materials, and fibre-optic monitoring ensures stable containment at 60–100 bar pressure and enables multi-cycle operation with minimal leakage (<0.05% per year). Economically, the baseline Levelized Cost of Hydrogen Storage (LCOHS) for aquifers was found to be ~0.29 EUR/kWh, with potential reductions to ~0.18 EUR/kWh through optimized drilling, modularized compression systems, and microbial mitigation. The lifecycle carbon footprint (0.20–0.36 kg CO₂-eq/kg H₂) is competitive with other geological storage methods, while offering superior scalability and strategic flexibility.

The study investigates the optimisation of Balance of Plant (BOP) subsystems in Proton Exchange Membrane (PEM) electrolyser systems for green hydrogen production. The research highlights that BOP is not a secondary support unit, but a core contributor to overall efficiency, reliability, safety, and cost performance. Literature-based evidence indicates that 40–60 % of the total installed PEM electrolyser CAPEX is linked to BOP components rather than the stack itself. BOP inefficiencies can reduce net system efficiency by up to 10 percentage points, suggesting that high stack performance may still lead to weak plant-level results. Key BOP subsystems assessed include water purification, thermal management, power electronics, gas handling and purification, compression and storage, and control/safety systems. PEM electrolysis requires ultrapure water with conductivity below 0.1 µS/cm and stable operating temperatures typically between 50 and 80 °C. A quantitative case study of a 10 MW PEM plant is used to illustrate subsystem-level impacts on cost and energy consumption. In this case study, BOP energy consumption is approximately 6–10 kWh/kg H₂, with major losses from power electronics (3–4 kWh/kg) and compression/storage (2–4 kWh/kg). Total electricity use is assumed at 55 kWh/kg H₂, including BOP losses. With 6,000 operating hours/year, the plant produces about 1.09 million kg H₂/year (≈1,091 t/year). Under a base electricity price of 50 EUR/MWh, annual electricity cost reaches ~3.0 million EUR/year. Total CAPEX is assumed at 900 EUR/kW, resulting in 9.0 million EUR investment for the 10 MW plant. Using a 20-year lifetime and 8 % discount rate, the calculated LCOH is approximately 3.8 EUR/kg H₂. The results confirm that BOP optimisation is essential for reducing parasitic losses, improving net efficiency, and lowering the levelized cost of hydrogen.

The study examines the performance and analytical potential of integrated smart electricity, natural gas/biomethane, and water metering systems in a single-family house under Latvian climatic conditions. The analyzed building is a 100 m², single-story, insulated dwelling heated by a natural gas/biomethane boiler, representing a typical residential configuration. High-resolution consumption data were collected and analyzed to assess seasonal patterns, system reliability, and cross-utility interactions. The results demonstrate data availability above 95 % for all utilities, confirming the technical feasibility of integrated smart metering. Clear seasonal electricity and gas consumption profiles were identified, with strong heating-driven variability. Correlation analysis reveals significant coupling between electricity and gas consumption during the heating season, as well as a measurable linkage between gas and water use related to domestic hot water preparation. The findings confirm that integrated multi-utility smart metering provides substantially greater analytical value than isolated systems. The study contributes empirical evidence supporting holistic residential resource monitoring and informs future smart energy system deployment in cold-climate regions.

This study investigates the quality management priorities and operational practices of the energy company “Gren”, focusing on how standardised management systems, sustainability principles, and construction project development are integrated into its strategic and day-to-day activities. Using qualitative document analysis, the research examines corporate reports, regulatory frameworks, project descriptions, and relevant ISO standards to identify recurring patterns in how quality, safety, environmental considerations, and risk management are embedded within the company’s operations. The findings reveal five dominant thematic areas: quality management systems, environmental and safety practices, construction project development, sustainability initiatives, and risk management processes. Construction activities and technological modernisation appear as the most prominent themes, reflecting ongoing focus of “Gren” on infrastructure upgrades and energy efficiency improvements. The company’s extensive use of ISO standardisation demonstrates a structured, integrated approach to quality and compliance, while risk management practices show a proactive alignment with environmental and operational challenges. Sustainability, although less frequently referenced, functions as a cross-cutting strategic principle shaping long-term development. The study concludes that the effectiveness in quality management of “Gren” derives from integrating standardised systems with continuous technological advancement and sustainability-oriented project planning. Limitations include reliance on secondary data and the evolving nature of several ongoing construction projects. The findings provide insights relevant to energy companies navigating modernisation, regulatory compliance, and sustainable development objectives.