Italy

Due to the emissions reduction commitments that Mexico compromised in the Paris Agreement several clean fuel and renewable energy technologies need to penetrate the market to accomplish the environmental goals. Therefore there is a need to develop achievable and realistic policies for such technologies to ease the decision-making on national energy strategies. Several countries are starting to develop large-scale green hydrogen production projects to reduce the carbon footprint of the multiple sectors within the country. The conversion sectors namely power and refinery are fundamental sectors to decarbonise due to their energy supply role. Nowadays the highest energy consumables of the country are hydrocarbons (more than 90%) causing a particular challenge for deep decarbonisation. The purpose of this study is to use a multi-regional energy system model of Mexico to analyse a decarbonisation scenario in line with the latest National Energy System Development Program. Results show that if the country wants to succeed in reducing 22% of its GHG emissions and 51% of its short-lived climate pollutants emissions green hydrogen could play a role in power generation in regions with higher energy demand growth rates. These results show regarding the power sector that H2 could represent 13.8 GW or 5.1% of the total installed capacity by 2050 while for the refinery sector H2 could reach a capacity of 157 PJ/y which is around 31.8% of the total share and it is mainly driven by the increasing demands of the transport industry and power sectors. Nevertheless as oil would still represent the largest energy commodity CCS technologies would have to be deployed for new and retrofitted refinery facilities.

The integration of an increasing share of Renewable Energy Sources (RES) requires the availability of suitable energy storage systems to improve the grid flexibility and Compressed Air Energy Storage (CAES) systems could be a promising option. In this study a CO2 -free Diabatic CAES system is proposed and analyzed. The plant configuration is derived from a down-scaled version of the McIntosh Diabatic CAES plant where the natural gas is replaced with green hydrogen produced on site by a Proton Exchange Membrane electrolyzer powered by a photovoltaic power plant. In this study the components of the hydrogen production system are sized to maximize the self-consumption share of PV energy generation and the effect of the design parameters on the H2 -CAES plant performance are analyzed on a yearly basis. Moreover a comparison between the use of natural gas and hydrogen in terms of energy consumption and CO2 emissions is discussed. The results show that the proposed hydrogen fueled CAES can effectively match the generation profile and the yearly production of the natural gas fueled plant by using all the PV energy production while producing zero CO2 emissions.

Fuel cell electric vehicles are a promising solution for reducing the environmental impacts of the automotive sector; however there are still some key points to address in finding the most efficient and less impactful implementation of this technology. In this work three electrical architectures of fuel cell electric vehicles were modeled and compared in terms of the environmental impacts of their manufacturing and use phases. The three architectures differ in terms of the number and position of the DC/DC converters connecting the battery and the fuel cell to the electric motor. The life cycle assessment methodology was employed to compute and compare the impacts of the three vehicles. A model of the production of the main components of vehicles and fuel cell stacks as well as of the production of hydrogen fuel was constructed and the impacts were calculated using the program SimaPro. Eleven impact categories were considered when adopting the ReCiPe 2016 midpoint method and the EF (adapted) method was exploited for a final comparison. The results highlighted the importance of the converters and their influence on fuel consumption which was identified as the main factor in the comparison of the environmental impacts of the vehicle.

In this work the Design and Operation of Integrated Technologies (DO-IT) framework is developed a comprehensive tool to support short- and long-term technology investment and operation decisions for integrated energy generation conversion and storage technologies in buildings. The novelty of this framework lies in two key aspects: firstly it integrates essential open-source modelling tools covering energy end uses in buildings technology performance and cost and energy system design optimisation into a unified and easily-reproducible framework. Secondly it introduces a novel optimisation tool with a concise and generic mathematical formulation capable of modelling multi-energy vector systems capturing interdependencies between different energy vectors and technologies. The model formulation which captures both short- and long-term energy storage facilitates the identification of smart design and operation strategies with low computational cost. Different building energy demand and price scenarios are investigated and the economic and energy benefits of using a holistic multi-energy-vector approach are quantified. Technology combinations under consideration include: (i) a photovoltaic-electric heat pump-battery system (ii) a photovoltaic-electric heat pump-battery-hot water cylinder system (iii) a photovoltaic-electrolyser‑hydrogen storage-fuel cell system and (iv) a system with all above technology options. Using a university building as a case study it is shown that the smart integration of electricity heating cooling and hydrogen generation and storage technologies results in a total system cost which is >25% lower than the scenario of only importing grid electricity and using a fuel oil boiler. The battery mitigates intra-day fluctuations in electricity demand and the hot-water cylinder allows for efficiently managing heat demand with a small heat pump. In order to avoid PV curtailment excess PV-generated electricity can also be stored in the form of green hydrogen providing a long-term energy storage solution spanning days weeks or even seasons. Results are useful for end-users investment decision makers and energy policy makers when selecting building-integrated low-carbon technologies and relevant policies.

Green hydrogen can be efficiently produced in regions rich in renewable sources far from the European largeproduction sites and delivered to the continent for utilization in the industrial and mobility sectors. In this work the transportation of hydrogen from North Africa to North Italy in its liquefied form is considered. A technoeconomic assessment is performed on its value chain which includes liquefaction storage maritime transport distribution regasification and compression. The calculated transport cost for the industrial application (delivery to a hydrogen valley) ranges from 6.14 to 9.16 €/kg while for the mobility application (delivery to refueling stations) the range is 10.96–17.71 €/kg. In the latter case the most cost-effective configuration involves the distribution of liquefied hydrogen and regasification at the refueling stations. The liquefaction process is the cost driver of the value chain in all the investigated cases suggesting the importance of its optimization to minimize the overall transport cost.

Hydrogen is a key energy carrier that could play a crucial role in the transition to a low-carbon economy. Hydrogen-related technologies are considered flexible solutions to support the large-scale implementation of intermittent energy supply from renewable sources by using renewable energy to generate green hydrogen during periods of low demand. Therefore a short-term increase in demand for hydrogen as an energy carrier and an increase in hydrogen production are expected to drive demand for large-scale storage facilities to ensure continuous availability. Owing to the large potential available storage space underground hydrogen storage offers a viable solution for the long-term storage of large amounts of energy. This study presents the results of a survey of potential underground hydrogen storage sites in Italy carried out within the H2020 EU Hystories “Hydrogen Storage In European Subsurface” project. The objective of this work was to clarify the feasibility of the implementation of large-scale storage of green hydrogen in depleted hydrocarbon fields and saline aquifers. By analysing publicly available data mainly well stratigraphy and logs we were able to identify onshore and offshore storage sites in Italy. The hydrogen storage capacity in depleted gas fields currently used for natural gas storage was estimated to be around 69.2 TWh.

In the sustainability context the performance of energy-producing technologies using different energy sources needs to be scored and compared. The selective criterion of a higher level of useful energy to feed an ever-increasing demand of energy to satisfy a wide range of endo- and exosomatic human needs seems adequate. In fact surplus energy is able to cover energy services only after compensating for the energy expenses incurred to build and to run the technology itself. This paper proposes an energy sustainability analysis (ESA) methodology based on the internal and external energy use of a given technology considering the entire energy trajectory from energy sources to useful energy. ESA analysis is conducted at two levels: (i) short-term by the use of the energy sustainability index (ESI) which is the first step to establish whether the energy produced is able to cover the direct energy expenses needed to run the technology and (ii) long-term by which all the indirect energy-quotas are considered i.e. all the additional energy requirements of the technology including the energy amortization quota necessary for the replacement of the technology at the end of its operative life. The long-term level of analysis is conducted by the evaluation of two indicators: the energy return per unit of energy invested (EROI) over the operative life and the energy payback-time (EPT) as the minimum lapse at which all energy expenditures for the production of materials and their construction can be repaid to society. The ESA methodology has been applied to the case study of H2 production at small-scale (10–15 kWH2) comparing three different technologies: (i) steam-methane reforming (SMR) (ii) solar-powered water electrolysis (SPWE) and (iii) two-stage anaerobic digestion (TSAD) in order to score the technologies from an energy sustainability perspective.

The shift from fossil fuels to renewable energy systems represents a pivotal step toward the realization of a sustainable society. This study aims to analyze representative scientific literature on eco-sustainable energy production in the healthcare sector particularly in hospitals. Given hospitals’ substantial electricity consumption the adoption of renewable energy offers a reliable low-CO2 emission solution. The COVID-19 pandemic has underscored the urgency for energyefficient and environmentally-responsible approaches. This brief review analyzes the development of experimental simulation and optimization projects for sustainable energy production in healthcare facilities. The analysis reveals trends and challenges in renewable energy systems offering valuable insights into the potential of eco-sustainable solutions in the healthcare sector. The findings indicate that hydrogen storage systems are consistently coupled with photovoltaic panels or solar collectors but only 14% of the analyzed studies explore this potential within hospital settings. Hybrid renewable energy systems (HRES) could be used to meet the energy demands of healthcare centers and hospitals. However the integration of HRES in hospitals and medical buildings is understudied.

Legislation regulating the sustainability requirements for hydrogen technologies relies more and more on life cycle assessments (LCAs). Due to different scopes and development processes different pieces of EU legislation refer to different LCA methodologies with differences in the way multifunctional processes (i.e. co-productions recycling and energy recovery) are treated. These inconsistencies arise because incentive mechanisms are not standardized across sectors even though the end product hydrogen remains the same. The goal of this paper is to compare the life-cycle greenhouse gas (GHG) emissions of hydrogen from four production pathways depending on the multifunctional approach prescribed by the different EU policies (e.g. using substitution or allocation). The study reveals a large variation in the LCA results. For instance the life-cycle GHG emissions of hydrogen co-produced with methanol is found to vary from 1 kg CO2-equivalent/kg H2 (when mass allocation is considered) to 11 kg CO2-equivalent/kg H2 (when economic allocation is used). These inconsistencies could affect the market (e.g. hydrogen from a certain pathway could be considered sustainable or unsustainable depending on the approach) and the environment (e.g. pathways that do not lead to a global emission reduction could be promoted). To mitigate these potential negative effects we urge for harmonized and strict guidelines to assess the life-cycle GHG emissions of hydrogen technologies in an EU policy context. Harmonization should cover international policies too to avoid the same risks when hydrogen will be traded based on its GHG emissions. The appropriate methodological approach for each production pathway should be chosen by policymakers in collaboration with the LCA community and stakeholders from the industry based on the potential market and environmental consequences of such choice.

The main purpose of this article is to provide a short review of proton exchange membrane electrolyzer (PEMEL) modeling used for power electronics control. So far three types of PEMEL modeling have been adopted in the literature: resistive load static load (including an equivalent resistance series-connected with a DC voltage generator representing the reversible voltage) and dynamic load (taking into consideration the dynamics both at the anode and the cathode). The modeling of the load is crucial for control purposes since it may have an impact on the performance of the system. This article aims at providing essential information and comparing the different load modeling.

Hydrogen is an important raw material in chemical industries and the steam reforming of light hydrocarbons (such as methane) is the most used process for its production. In this process the use of a catalyst is mandatory and if compared to precious metal-based catalysts Ni-based catalysts assure an acceptable high activity and a lower cost. The aim of a distributed hydrogen production for example through an on-site type hydrogen station is only reachable if a novel reforming system is developed with some unique properties that are not present in the large-scale reforming system. These properties include among the others (i) daily startup and shutdown (DSS) operation ability (ii) rapid response to load fluctuation (iii) compactness of device and (iv) excellent thermal exchange. In this sense the catalyst has an important role. There is vast amount of information in the literature regarding the performance of catalysts in methane steam reforming. In this short review an overview on the most recent advances in Ni based catalysts for methane steam reforming is given also regarding the use of innovative structured catalysts.

The steel industry is among the highest carbon-emitting industrial sectors. Since the steel production process is already exhaustively optimized alternative routes are sought in order to increase carbon efficiency and reduce these emissions. During steel production three main carbon-containing off-gases are generated: blast furnace gas coke oven gas and basic oxygen furnace gas. In the present work the addition of renewable hydrogen by electrolysis to those steelworks off-gases is studied for the production of methane and methanol. Different case scenarios are investigated using AspenPlusTM flowsheet simulations which differ on the end-product the feedstock flowrates and on the production of power. Each case study is evaluated in terms of hydrogen and electrolysis requirements carbon conversion hydrogen consumption and product yields. The findings of this study showed that the electrolysis requirements surpass the energy content of the steelwork’s feedstock. However for the methanol synthesis cases substantial improvements can be achieved if recycling a significant amount of the residual hydrogen.

In this study a techno-economic analysis tool for conducting detailed feasibility studies on the deployment of green hydrogen hubs for fuel cell bus fleets is developed. The study evaluates and compares five green hydrogen hub configurations’ operational and economic performance under a typical metropolitan bus fleet refuelling schedule. Each configuration differs based on its electricity sourcing characteristics such as the mix of energy sources capacity sizing financial structure and grid interaction. A detailed comparative analysis of distinct green hydrogen hub configurations for decarbonising a fleet of fuel-cell buses is conducted. Among the key findings is that a hybrid renewable electricity source and hydrogen storage are essential for cost-optimal operation across all configurations. Furthermore bi-directional grid-interactive configurations are the most costefficient and can benefit the electricity grid by flattening the duck curve. Lastly the paper highlights the potential for cost reduction when the fleet refuelling schedule is co-optimized with the green hydrogen hub electricity supply configuration.

Hydrogen Refueling Stations (HRS) are a key infrastructure to the successful deployment of hydrogen mobility. Their cost-effectiveness will represent an increasingly crucial issue considering the foreseen growth of vehicle fleets from few captive fleets to large-scale penetration of hydrogen vehicles. In this context a detailed component-oriented cost model is important to assess HRS costs for different design concepts layout schemes and possible customizations respect to aggregate tools which are mostly available in literature. In this work an improved version of a previously developed component-oriented scale-sensitive HRS cost model is applied to 5 different European HRS developed within the 3Emotion project with different refueling capacities (kgH2/day) hydrogen supply schemes (in-situ production or delivery) storage volumes and pressures and operational strategies. The model output allows to assess the upfront investment cost (CAPEX) the annual operational cost (OPEX) and the Levelized Cost of Hydrogen (LCOH) at the dispenser and identify the most crucial cost components. The results for the five analyzed HRS sites show an LCOH at the nozzle of around 8-9 €/kg for delivery based HRSs which are mainly dominated by the H2 retail price and transport service price and around 11-12 €/kg for on-site producing HRS for which the electrolyzer CAPEX and electricity price plays a key role in the cost structure. The compression storage and dispensing sections account for between 1-3 €/kg according to the specific design & performance requirements of the HRS. The total LCOH values are comparable with literature standard market prices for similar scale HRSs and with the 3Emotion project targets.

This paper examines the changes in the performance level and pollutant emissions of a combustion chamber for turbofan engines. Two different fuels are compared: a conventional liquid fuel of the JET-A (kerosene) class and a hydrogen-based gaseous fuel. A turbofan engine delivering a 70 kN thrust at cruise conditions and 375 kN thrust at takeoff is considered. The comparison is carried out by investigating the combustion pattern with different boundary conditions the latter assigned along a typical flight mission. The calculations rely on a combined approach with a preliminary lumped parameter estimation of the engine performance and thermodynamic properties under different flight conditions (i.e. take-off climbing and cruise) and a CFD-based combustion simulation employing as boundary conditions the outputs obtained from the 0-D computations. The results are discussed in terms of performance thermal properties distributions throughout the combustor and of pollutant concentration at the combustor outflow. The results demonstrate that replacing the JET-A fuel with hydrogen does not affect the overall engine performance significantly and stable and efficient combustion takes place inside the burner although a different temperature regime is observable causing a relevant increase in thermal NO emissions.

The world is experiencing the effects of climate change at an increasing rate including rising average global temperature caused primarily by greenhouse gas (GHG) emissions. Energy-intensive industries (EIIs) are major contributors to greenhouse gas emissions. The pulp and paper industry (PPI) is among the top five most energyintensive industries and it accounts for approximately 6 % of global industrial energy use and 2 % of direct industrial CO2 emissions. Therefore it is important to decarbonize this industrial sector to achieve the climate policy goal of achieving net-zero emissions as per the Paris Agreement. This paper presents a comprehensive review of the decarbonization options also known as decarbonization pathways for the pulp and paper industrial sector. These pathways are selected from available literature and they mainly include energy efficiency measures (EEMs) paper recycling switching to carbon-neutral fuels such as biomass and hydrogen electrification of heat supply and carbon capture & storage (CCS) among other emerging technologies. After identifying each decarbonization pathway is discussed in detail with its drivers and barriers to implementation. The Analytical Hierarchy Process AHP a multi-criteria decision-making MCDM technique is carried out to rank the decarbonization pathways on five distinct criteria: cost emission reduction potential technological readiness level (TRL) implementation time and scalability. The ranking is carried out in four distinct criteria weight regimes to present clear choices on different criterion weights. This review paper aims to add to the existing literature to provide clear indications in choosing the pathways toward the decarbonization effort in the pulp & paper industry under various strategic priorities.

Biogas is a crucial renewable energy source for green hydrogen (H2) production reducing greenhouse gas emissions and serving as a carbon-free energy carrier with higher specific energy than traditional fuels. Currently methane reforming dominates H2 production to meet growing global demand with biogas/landfill gas (LFG) reform offering a promising alternative. This study provides a comprehensive simulation-based evaluation of Steam Methane Reforming (SMR) and Dry Methane Reforming (DMR) of biogas/LFG using Aspen Plus. Simulations were conducted under varying operating conditions including steam-to-carbon (S/C) for SMR and steam-to-carbon monoxide (S/CO) ratios for DMR reforming temperatures pressures and LFG compositions to optimize H2 yield and process efficiency. The comparative study showed that SMR attains higher specific H2 yields (0.14–0.19 kgH2/Nm3 ) with specific energy consumption between 0.048 and 0.075 MWh/kg of H2 especially at increased S/C ratios. DMR produces less H2 than SMR (0.104–0.136 kg H2/Nm3 ) and requires higher energy inputs (0.072–0.079 MWh/kg H2) making it less efficient. Both processes require an additional 1.4–2.1 Nm3 of biogas/LFG per Nm3 of feed for energy. These findings provide key insights for improving biogas-based H2 production for sustainable energy with future work focusing on techno–economic and environmental assessments to evaluate its feasibility scalability and industrial application.

Tilos a Greek island in the Mediterranean Sea hosts a pioneering hybrid energy system combining an 800-kW wind turbine and a 160-kWp photovoltaic (PV) field. The predominance of wind power makes the energy production of the island almost constant during the year while the consumption peaks in summer in correspondence with the tourist season. If the island wants to achieve complete selfsufficiency seasonal storage becomes compulsory. This study makes use of measured production data over 1 year to understand the best combination of renewable energy generation and storage to match energy production with consumption. A stochastic optimization based on a differential evolution algorithm is carried out to showcase the configuration that minimizes the levelized cost of required energy (LCORE) in different scenarios. System performance is simulated by progressively increasing the size of the storage devices including a combination of Lithium-ion batteries and power-to-gas-topower (P2G2P) technologies and the PV field. An in-depth market review of current and forecasted prices for RES and ESS components supports the economic analysis including three time horizons (current and projections to 2030 and 2050) to account for the expected drop in component prices. Currently the hybrid storage system combining BESS and P2G2P is more cost-effective (264 €/MWh) than a BESS-only system (320 €/MWh). In the mid-term (2030) the expected price drop in batteries will shift the optimal solution towards this technology but the LCORE reached by the hybrid storage (174 €/MWh) will still be more economical than BESS-only (200 €/MWh). In the long term (2050) the expected price drop in hydrogen technologies will push again the economic convenience of P2G2P and further reduce the LCORE (132.4 €/MWh).

Hydrogen and electric buses are considered effective options for decarbonizing the public transportation sector positioning them as a leader in this transition. This study models the environmental and economic performances of a set of bus powertrain technologies considering a real case-study of suburban public transport in Italy and including fuel cell electric vehicles (FCEV) battery electric vehicles (BEV) biomethane-powered vehicles (CBM) natural gas (CNG) and diesel buses. The environmental performances of FCEV and BEV are significantly influenced by the energy source used for hydrogen production or battery charging. Specifically using the electricity mix for FCEV leads to the highest greenhouse gas emissions and fossil fuel demand. In contrast BEV show better environmental performance than conventional powertrains especially when powered by photovoltaics. When powered by photovoltaics BEV reveal similar results to FCEV in terms of environmental impacts except for resource depletion where both perform poorly. Transitioning from diesel to BEV or FCEV can enhance local air quality regardless of the energy source. The economic analysis indicates that FCEV are the most expensive option followed by BEV both of which are currently costlier than diesel and CNG systems. CBM from waste streams emerges as a cost-effective and environmentally friendly solution. This study suggests prioritizing biomethane derived from biowaste manure and residual biomass (excluding energy crops) as a part of the fuels for public transport decarbonization in the EU to advance EU decarbonization goals despite limitations due to resource availability. Furthermore BEV powered by renewables should be prioritized whenever their range is adequate.

Hydrogen produced through natural gas reforming with carbon capture and storage (blue H2) is expected to supply up to 30 % of global low-carbon hydrogen by 2030. However wide variability in reported findings creates uncertainty about its future role. To address this the present techno-economic-environmental study from a lifecycle perspective evaluates whether blue hydrogen can meet carbon footprint thresholds (3 and 3.4 kg CO2 eq./ kg H2) required to qualify as low-carbon hydrogen. Several configurations of either chemical absorption or lowtemperature CO2 separation techniques integrated with auto-thermal reforming are modeled. Results show that low-temperature separation can achieve comparable or even superior energetic performance to conventional capture methods with cold gas and overall efficiencies reaching up to 80 % and 78 % respectively. The economic analysis estimates the levelized cost of blue hydrogen at 3.5–4 €/kg under 2024 EU average nonhousehold consumer natural gas and electricity prices and 2.4–2.8 €/kg under Italy’s 2024 wholesale prices. From an environmental standpoint life-cycle assessment indicates an average carbon footprint of 2.5 kg CO2 eq./ kg H2 assuming photovoltaic electricity for auxiliary power and excluding more carbon-intensive natural gas supply chains. The findings highlight that partial electrification of the CO2 separation unit use of renewable electricity and maximizing capture rates are key factors essential for producing compliant blue H2. Furthermore adopting ultra-low-emission natural gas supply chains could reduce blue H2′s carbon footprint to the level of green H2 suggesting that the introduction of certificate-of-origin schemes for natural gas can guarantee blue H2 with minimal emissions.

Hydrogen-fueled Internal Combustion Engines (H2-ICEs) are typically operated with lean mixtures to minimize NOx emissions and reduce the risk of abnormal combustion events. Due to hydrogen’s low Lewis number premixed hydrogen-air flames in lean conditions exhibit strong thermodiffusive instabilities which make the numerical simulation of the combustion process particularly challenging. Indeed the intensity of these instabilities is significantly influenced by thermodynamic parameters – such as mixture temperature pressure and dilution rate – resulting in substantial variations in combustion behaviour across different operating conditions. Therefore they have to be properly considered not only to ensure model robustness but also to improve model accuracy over a wider range of operations. In this study the combustion process in a Direct Injection H2-ICE was analyzed using 3D-CFD simulations relying on a flamelet-based combustion model. Two sets of lookup flame speed maps were defined: laminar flame speed (SL) maps derived from standard 1D-CFD simulations in homogeneous reactor and freely propagating flame speed (SM) maps which account for the effects of thermodiffusive instabilities. The model that uses SL maps required the recalibration of some combustion model parameters when changing the dilution rate to ensure consistency with experimental data. Instead the model relying on SM maps featured a noticeable accuracy across different air-to-fuel ratios without the need for recalibration any combustion model parameter highlighting the key role of thermodiffusive flame instabilities on the combustion process. Based on these findings the impact of such instabilities was evaluated throughout the entire combustion process from both global and local perspectives. The relevance of thermodiffusive instabilities was observed to increase with the air-to-fuel ratio thereby enhancing combustion speed in leaner mixtures. Additionally the implementation of thermodiffusive instabilities was found to affect also preferred direction of flame propagation as stronger instabilities were identified in the leanest and low-temperature portions of the flame front. Novelty and significance This study addresses a critical knowledge gap regarding the role of thermodiffusive flame instabilities in accurately replicating the combustion process of a direct-injection internal combustion engine within a RANS simulation framework. Indeed while these instabilities have been shown to significantly enhance the mixture consumption rate in quiescent environments at low to moderate pressures and temperatures particularly in lean mixtures their impact on the burn rate under engine-like conditions has not yet been systematically investigated to the best of the authors’ knowledge. This work provides a comprehensive analysis of the significance of these instabilities in the combustion process of a direct-injection hydrogen internal combustion engine. The analysis is conducted from both a global perspective assessing their overall influence on the combustion process and a local perspective examining how they alter flame front characteristics when incorporated into the model.

The governance of the EU energy sector has gradually evolved over time to reflect and support the closer integration of the Internal Electricity Market. As the EU energy sector faces new challenges both at the local and cross-border levels its governance might once again need to be reviewed to ensure that it remains fit for the future. This Policy Brief highlights three opportunities for streamlining the governance of the electricity (and gas) sector(s) at the cross-border level related to: (i) the ‘all TSOs’ or ‘all relevant TSOs’ processes; (ii) the regulatory oversight of EU-wide entities; and (iii) the operation of the electricity market coupling. Other areas for improvement in the current governance framework may also emerge and one suggestion relates to the dual role of the ENTSOs both as (i) entities responsible for a number of essential tasks for the energy sector and (ii) associations with TSOs as their members.

The paper investigates the potential of co-electrolysis as a viable pathway for hydrogen production and industrial decarbonization expanding on previous studies on water electrolysis. The analysis adopts a general and critical perspective aiming to assess the realistic scope of this technology with regard to current energy and environmental needs. Although co-electrolysis theoretically offers improved efficiency by simultaneously converting H2O and CO2 into syngas the practical advantages are difficult to consolidate. The study highlights that the energetic margins of the process remain relatively narrow and that several key aspects including system irreversibility and the limited availability of CO2 in many contexts significantly constrain its applicability. Despite the growing interest and promising technological developments co-electrolysis still faces substantial challenges before it can be implemented on a larger scale. The findings suggest that its success will depend on targeted integration strategies advanced thermal management and favorable boundary conditions rather than on the intrinsic efficiency of the process alone. However there are specific sectors where assessing the implementation potential of co-electrolysis could be of interest a perspective this paper aims to explore.

Pressure collapse in sloshing cryogenic liquid hydrogen tanks is a challenge for existing models which often diverge from experimental data. This paper presents a novel lumped-parameter model that overcomes these limitations. Based on a control volume analysis our approach simplifies the complex non-equilibrium physics into a single dimensionless ordinary differential equation governing the liquid’s temperature. We demonstrate this evolution is controlled by one key parameter: the interfacial Nusselt number (). A method for estimating directly from pressure data is also provided. Validated against literature data the model predicts final tank temperatures with deviation of 0.88K (<5% relative error) from measurements thereby explaining the associated pressure collapse. Furthermore our analysis reveals that the Nusselt number varies significantly during a single sloshing event—with calculated values ranging from a peak of 5.81 × 105 down to 7.58 × 103—reflecting the transient nature of the phenomenon.

Massive theoretical and applied research is underway worldwide to assess the viability of transporting natural gas-hydrogen blends in pipelines. For the first time this work derives simplified but closed-form equations that describe how changes in gas properties due to hydrogen blending at different volumes map to specific changes in pressure drop compressor power and linepack. These first-of-their-kind equations which are extensively validated against transient gas flow models enabled three unprecedented and unique findings. The first finding which quantifies how a change in demand maps to a change in delay and swing on the supply side reveals that pressure swings increase monotonically with an increase in hydrogen blending volume translating into an increase in pipeline fatigue and risk of failure. The second finding crucially shows that pressure drop does not monotonically increase with an increase in hydrogen blending volume; in fact it is highest at around 85 % hydrogen volume not at 100 %. The third finding shows that the decrease in linepack as a result of an increase in hydrogen volume is not only related to the gross calorific value of the gas mixture but also to the pressure-tocompressibility factor ratio suggesting that smaller parallel pipelines can offset this linepack reduction compared to a single larger pipeline.