Norway

The energy transition with transformation into predominantly renewable sources requires technology development to secure power production at all times despite the intermittent nature of the renewables. Micro gas turbines (MGTs) are small heat and power generation units with fast startup and load-following capability and are thereby suitable backup for the future’s decentralized power generation systems. Due to MGTs’ fuel flexibility a range of fuels from high-heat to lowheat content could be utilized with different greenhouse gas generation. Developing micro gas turbines that can operate with carbon-free fuels will guarantee carbon-free power production with zero CO2 emission and will contribute to the alleviation of the global warming problem. In this paper the redevelopment of a standard 100-kW micro gas turbine to run with methane/hydrogen blended fuel is presented. Enabling micro gas turbines to run with hydrogen blended fuels has been pursued by researchers for decades. The first micro gas turbine running with pure hydrogen was developed in Stavanger Norway and launched in May 2022. This was achieved through a collaboration between the University of Stavanger (UiS) and the German Aerospace Centre (DLR). This paper provides an overview of the project and reports the experimental results from the engine operating with methane/hydrogen blended fuel with various hydrogen content up to 100%. During the development process the MGT’s original combustor was replaced with an innovative design to deal with the challenges of burning hydrogen. The fuel train was replaced with a mixing unit new fuel valves and an additional controller that enables the required energy input to maintain the maximum power output independent of the fuel blend specification. This paper presents the test rig setup and the preliminary results of the test campaign which verifies the capability of the MGT unit to support intermittent renewable generation with minimum greenhouse gas production. Results from the MGT operating with blended methane/hydrogen fuel are provided in the paper. The hydrogen content varied from 50% to 100% (volume-based) and power outputs between 35 kW to 100kW were tested. The modifications of the engine mainly the new combustor fuel train valve settings and controller resulted in a stable operation of the MGT with NOx emissions below the allowed limits. Running the engine with pure hydrogen at full load has resulted in less than 25 ppm of NOx emissions with zero carbon-based greenhouse gas production.

This paper evaluates the predictive capabilities of the advanced consequence model FLACS-CFD for deflagrations involving hydrogen. Two modelling approaches are presented: the extensively validated model system originally developed for hydrocarbons included in FLACS-CFD 22.1 and a Markstein number dependent model implemented in the in-house version FLACS-CFD 22.1 IH. The ability of the models to predict the overpressure and the flame arrival time for scenarios with different concentrations of hydrogen and thus different Lewis and Markstein numbers is assessed. Furthermore the effect of adding methane or nitrogen on overpressure for different regimes of premixed combustion are investigated. The validation dataset includes deflagrations in the open or in congested open areas and vented deflagrations in empty or congested enclosures. The overpressure predictions by FLACS-CFD 22.1 IH are found to be more accurate than those obtained with FLACS-CFD 22.1 for scenarios with varying hydrogen concentrations and/or added nitrogen or methane in the mixture. The predictions by FLACS-CFD 22.1 IH for lean hydrogen mixtures are within a factor of 2 of the values observed in the experiments. Further development of the model is needed for more accurate prediction of deflagrations involving rich hydrogen mixtures as well as scenarios with other fuels and/or conditions where the initial pressure or temperature deviate significantly from ambient conditions.

Understanding what people think about hydrogen energy and how this influences their acceptance of the associated technology is a critical area of research. The public’s willingness to adopt practical applications of hydrogen energy such as hydrogen fuel-cell vehicles (HFCVs) is a key factor in their deployment. To analyse the direct and indirect effects of key attitudinal variables that could influence the intention to use HFCVs in Spain an online questionnaire was administered to a representative sample of the Spanish population (N = 1000). A path analysis Structural Equation Model (SEM) was applied to determine the effect of different attitudinal variables. A high intention to adopt HFCVs in Spain was found (3.8 out of 5) assuming their wider availability in the future. The path analysis results indicated that general acceptance of hydrogen technology and perception of its benefits had the greatest effect on the public’s intention to adopt HFCVs. Regarding indirect effects the role of trust in hydrogen technology was notable having significant mediating effects not only through general acceptance of hydrogen energy and local acceptance of hydrogen refuelling stations (HRS) but also through positive and negative emotions and benefits perception. The findings will assist in focusing the future hydrogen communication strategies of both the government and the private (business) sector.

Hydrogen is considered a promising solution for global decarbonisation as an alternative to fossil fuels. However it can interact with and brittle most metallic materials and is highly flammable. These properties call for a systematic investigation of physical and chemical hazards and for the definition of a comprehensive risk management and monitoring framework including proper maintenance planning. This study aims at establishing a hydrogen monitoring scheme and it provides a descriptive bibliometric and interpretative review of the current state-of-the-art of suitable techniques to ensure the safe handling of hydrogen systems. The descriptive analysis outlines the technologies available to supervise the hydrogen-material interactions and detect hydrogen leaks and flames. The bibliometric analysis shows quantitative data to identify the most relevant research groups. The interpretative study discusses the findings and examines the possibility of combining the identified techniques with maintenance programs to prevent catastrophic events.

LNG carriers play a crucial role in the shipping industry meeting the global demand for natural gas (NG). However the energy losses resulting from the propulsion system and the excess boil-off gas (BOG) cannot be overlooked. The present article investigates the H2 production on board LNG carriers employing both the engine's waste heat (WH) and the excess BOG. Conventional (ORC) and dual-pressure (2P-ORC) organic Rankine cycles coupled separately with a solid oxide electrolysis (SOEC) have been simulated and compared. The hydrogen (H2) produced is then compressed at 150 bar for subsequent use as required. According to the results the 2P-ORC generates 14.79 % more power compared to ORC allowing for an increased energy supply to the SOEC; hence producing more H2 (34.47 kg/h compared to 31.14 kg/h). Including the 2P-ORC in the H2 production plant results in a cheaper H2 cost by 0.04 $/kgH2 compared to ORC a 1.13 %LHV higher system efficiency when leveraging all the available waste heat. The plant including 2P-ORC exploits more than 86 % of the of the available waste compared to 70 % when using ORC. Excluding the compression system decreases the capital cost by almost the half regardless of the WH recovery system used yet it plays in favour of the plant with ORC making the cost of H2 cheaper by 0.29 $/kgH2 in this case. Onboard H2 production is a versatile process independent from the propulsion system ensuring the ship's safety and availability throughout a sea journey.

The European Union aims to increase its climate ambition and achieve climate neutrality by 2050. This necessitates expanding offshore wind energy and green hydrogen production especially for hard-to-abate industrial sectors. A study examines the impact of green hydrogen on offshore wind projects specifically focusing on a potential future North Sea offshore grid. The study utilizes data from the TYNDP 2020 Global Ambition scenario 2040 considering several European countries. It aims to assess new transmission and generation capacity utilization and understand the influencing factors. The findings show that incorporating green hydrogen production increases offshore wind utilization and capture prices. The study estimates that by 2040 the levelized cost of hydrogen could potentially decrease to e1.2-1.6/kg H2 assuming low-cost electricity supply and declining capital costs of electrolysers. These results demonstrate the potential benefits and cost reductions of integrating green hydrogen production into North Sea offshore wind projects.

This paper establishes a framework of boundary conditions for implementing hydrogen energy systems in ships identifying what is feasible within maritime constraints. To support a comprehensive understanding of hydrogen systems onboard vessels an extensive technical review of hydrogen storage and power systems is provided covering the entire power value chain. Key aspects include equipment arrangement integration of fuel cell powertrain and presentation of the complete storage system in compliance with regulations. Engineering considerations such as material selection and insulation equipment specifications (e.g. pressure relief valves and hydrogen purity) and system configurations are analysed. Key findings reveal that fuel cells must achieve operational lifespans exceeding 46000 h to be viable for maritime applications. Additionally reliance solely on volumetric energy density underestimates storage needs necessitating provisions for cofferdams ullage space tank heels and hydrogen conditioning areas. Regulatory gaps are identified including inadequate safety provisions and inappropriate material guidelines.

Chapters:<br/>♦ Introduction by Rainer Quitzow and Yana Zabanova<br/>♦ The EU in the Global Hydrogen Race: Bringing Together Climate Action Energy Security and Industrial Policy by Yana Zabanova<br/>♦ Germany’s Hydrogen Strategy: Securing Industrial Leadership in a Carbon–Neutral Economy by Almudena Nunez and Rainer Quitzow<br/>♦ France’s Hydrogen Strategy: Focusing on Domestic Hydrogen Production to Decarbonise Industry and Mobility by Ines Bouacida<br/>♦ International Dimension of the Polish Hydrogen Strategy. Conditions and Potential for Future Development by Michał Smoleń and Wojciech Żelisko<br/>♦ Hydrogen Affairs in Hungary’s Politically Confined Ambition byJohn Szabo<br/>♦ Spain’s Hydrogen Ambition: Between Reindustrialisation and Export-Led Energy Integration with the EU by Ignacio Urbasos and Gonzalo Escribano<br/>♦  Italian Hydrogen Policy: Drivers Constraints and Recent Developments by Andrea Prontera<br/>♦  Hydrogen Policy in the Netherlands: Laying the Foundations for a Scalable Hydrogen Value Chain by Roelof Stam Coby van der Linde and Pier Stapersma<br/>♦ Hydrogen Strategy of Sweden: Unpacking the Multiple Drivers and Potential Barriers to Hydrogen Development by Stefan Ćetković and Janek Stockburger<br/>♦  Norway’s Hydrogen Strategy: Unveiling Green Opportunities and Blue Export Ambitions by Jon Birger Skjærseth Per Ove Eikeland Tor Håkon Jackson Inderberg and Mari Lie Larsen<br/>♦ The Geopolitics of Hydrogen in Europe: The Interplay between EU and Member State Policies by Rainer Quitzow and Yana Zabanova

In light of offshore wind expansions in the North and Baltic Seas in Europe further ideas on using offshore space for renewable-based energy generation have evolved. One of the concepts is that of energy islands which entails the placement of energy conversion and storage equipment near offshore wind farms. Offshore placement of electrolysers will cause interdependence between the availability of electricity for hydrogen production and for power transmission to shore. This paper investigates the trade-offs between integrating energy islands via electricity versus hydrogen infrastructure. We set up a combined capacity expansion and electricity dispatch model to assess the role of electrolysers and electricity cables given the availability of renewable energy from the islands. We find that the electricity system benefits more from connecting close-to-shore wind farms via power cables. In turn electrolysis is more valuable for far-away energy islands as it avoids expensive long-distance cable infrastructure. We also find that capacity investment in electrolysers is sensitive to hydrogen prices but less to carbon prices. The onshore network and congestion caused by increased activity close to shore influence the sizing and siting of electrolysers.

The hydrogen economy is receiving increasing attention as a complement to electrification in the global energy transition. Clean hydrogen production is often viewed as a competition between natural gas reforming with CO2 capture and electrolysis using renewable electricity. However solid fuel gasification with CO2 capture presents another viable alternative especially when considering the potential of biomass to achieve negative CO2 emissions. This study investigates the techno-economic potential of hydrogen production from large-scale coal/ biomass co-gasification plants with CO2 capture. With a CO2 price of 50 €/ton the benchmark plant using commercially available technologies achieved an attractive hydrogen production cost of 1.78 €/kg with higher CO2 prices leading to considerable cost reductions. Advanced configurations employing hot gas clean-up membrane-assisted water-gas shift and more efficient gasification with slurry vaporization and a chemical quench reduced the hydrogen production cost to 1.50–1.62 €/kg with up to 100% CO2 capture. Without contingencies added to the pre-commercial technologies the lowest cost reduces to 1.43 €/kg. It was also possible to recover waste heat in the form of hot water at 120 ◦C for district heating potentially unlocking further cost reductions to 1.24 €/kg. In conclusion gasification of locally available solid fuels should be seriously considered next to natural gas and electrolysis for supplying the emerging hydrogen economy.

Economical offshore wind developments depend on alternatives for cost-efficient transmission of the generated energy to connecting markets. Distance to shore availability of an offshore power grid and scale of the wind farm may impede export through power cables. Conversion to H2 through offshore electrolysis may for certain offshore wind assets be a future option to enable energy export. Here we analyse the cost sensitivity of offshore electrolysis for harvesting offshore wind in the North Sea using a technology-detailed multi-carrier energy system modelling framework for analysis of energy export. We include multiple investment options for electric power and hydrogen export including HVDC cables new hydrogen pipelines tie-in to existing pipelines and pipelines with linepacking. Existing hydropower is included in the modelling and the effect on offshore electrolysis from increased pumping capacity in the hydropower system is analysed. Considering the lack of empirical cost data on offshore electrolysis as well as the high uncertainty in future electricity and H2 prices we analyse the cost sensitivity of offshore electrolysis in the North Sea by comparing costs relative to onshore electrolysis and energy prices relative to a nominal scenario. Offshore electrolysis is shown to be particularly sensitive to the electricity price and an electricity price of 1.5 times the baseline assumption was needed to provide sufficient offshore energy for any significant offshore electrolysis investments. On the other hand too high electricity prices would have a negative impact on offshore electrolysis because the energy is more valuable as electricity even at the cost of increased wind power curtailment. This shows that there is a window-of-opportunity in terms of onshore electricity where offshore electrolysis can play a significant role in the production of H2 . Pumped hydropower increases the maximum installed offshore electrolysis at the optimal electricity and H2 prices and makes offshore electrolysis more competitive at low electricity prices. Linepacking can make offshore electrolysis investments more robust against low H2 and high electricity prices as it allow for more variable H2 production through storing excess energy from offshore. The increased electrolysis capacity needed for variable electrolyser operation and linepacking is installed onshore due to its lower CAPEX compared to offshore installations.

This study proposes a country-based life-cycle assessment (LCA) of several conversion pathways related 10 to both on grid-connected Power-to-X (PtX) fuels and advanced biofuel production for maritime transport 11 in Europe. We estimate the biomass resource availability (both agricultural and forest residues and 12 second-generation energy crops from abandoned cropland) electricity mix and a future-oriented 13 prospective LCA to assess how future climate change mitigation policies influence the results. Our results 14 indicate that the potential of PtX fuels to achieve well-to-wake greenhouse gas intensities lower than 15 those of fossil fuels is limited to countries with a carbon intensity of the electricity mix below 100 gCO2eq kWh-1 16 . The more ambitious FuelEU Maritime goal could be achieved with PtX only if connected to electricity sources below ca. 17 gCO2eq kWh-1 17 which can become possible for most of the national 18 electricity mix in Europe by 2050 if renewable energy sources will become deployed at large scales. For 19 drop-in and hydrogen-based biofuels biomass residues have a higher potential to reduce emissions than 20 dedicated energy crops. In Europe the potentials of energy supply from all renewable and low-carbon 21 fuels (RLFs) range from 32-149% of the current annual fuel consumption in European maritime transport. 22 The full deployment of RLFs with carbon capture and storage technologies could mitigate up to 184% of 23 the current well-to-wake shipping emissions in Europe. Overall our study highlights how the strategic use 24 of both hydrogen-based biofuels and PtX fuels can contribute to the climate mitigation targetsfor present 25 and future scenarios of European maritime transport.

With the aim of reducing carbon emissions and seeking independence from Russian gas in the wake of the conflict in Ukraine the use of hydrogen in the European Union is expected to rise in the future. In this regard hydrogen transport via pipeline will become increasingly crucial either through the utilization of existing natural gas infrastructure or the construction of new dedicated hydrogen pipelines. This study investigates the effects of hydrogen blending in existing pipelines on the European energy system by the year 2050 by introducing hydrogen blending sensitivities to the Global Energy System Model (GENeSYS-MOD). Results indicate that hydrogen demand in Europe is inelastic and limited by its high costs and specific use cases with hydrogen production increasing by 0.17% for 100%-blending allowed compared to no blending allowed. The availability of hydrogen blending has been found to impact regional hydrogen production and trade with countries that can utilize existing natural gas pipelines such as Norway experiencing an increase in hydrogen and synthetic gas exports from 44.0 TWh up to 105.9 TWh in 2050 as the proportion of blending increases. Although the influence of blending on the overall production and consumption of hydrogen in Europe is minimal the impacts on the location of production and dependence on imports must be thoroughly evaluated in future planning efforts.

This paper studies fast fueling of gaseous hydrogen into large hydrogen (H2) tanks suitable for maritime applications. Three modeling methods have been developed and evaluated: (1) Two-dimensional computational fluid dynamic (CFD) modeling (2) One-dimensional wall discretized modeling and (3) Zero-dimensional modeling. A detailed 2D CFD simulation of a small H2-tank was performed and validated with data from literature and then used to simulate a large H2-tank. Results from the 2D-model show non-uniform temperature distribution inside the large tank but not in the small H2-tank. The 1D-model can predict the mean temperature in small H2-tanks but not the inhomogeneous temperature field in large H2-tanks. The 0D-model is suitable as a screening tool to obtain rough estimates. Results from the modeling of the large H2-tank show that the heat transfer to the wall during fast filling is inhibited by heat conduction in the wall which leads to an unacceptably high mean hydrogen temperature.

This paper provides an in-depth examination of critical and strategic raw materials (CRMs) and their crucial role in the development of electrolyzer and fuel cell technologies within the hydrogen economy. It methodically analyses a range of electrolyzer technologies including alkaline proton-exchange membrane solid-oxide anion-exchange membrane and proton-conducting ceramic systems. Each technology is examined for its specific CRM dependencies operational characteristics and the challenges associated with CRM availability and sustainability. The study further extends to hydrogen storage and separation technologies focusing on the materials employed in high-pressure cylinders metal hydrides and hydrogen separation processes and their CRM implications. A key aspect of this paper is its exploration of the supply and demand dynamics of CRMs offering a comprehensive view that encompasses both the present sttate and future projections. The aim is to uncover potential supply risks understand strategies and identify potential bottlenecks for materials involved in electrolyzer and fuel cell technologies addressing both current needs and future demands as well as supply. This approach is essential for the strategic planning and sustainable development of the hydrogen sector emphasizing the importance of CRMs in achieving expanded electrolyzer capacity leading up to 2050.

This review presents state-of-the-art for representative sampling of hydrogen from hydrogen refueling stations. Documented sampling strategies are presented as well as examples of commercially available equipment for sampling at the hydrogen refueling nozzle. Filter media used for sampling is listed and the performance of some of the filters evaluated. It was found that the filtration efficiency of 0.2 and 5 mm filters were not significantly different when exposed to 200 and 300 nm particles. Several procedures for gravimetric analysis are presented and some of the challenges are identified to be filter degradation pinhole formation and conditioning of the filter prior to measurement. Lack of standardization of procedures was identified as a limitation for result comparison. Finally the review summarizes results including particulate concentration in hydrogen fuel quality data published. It was found that less than 10% of the samples were in violation with the tolerance limit.

Turquoise hydrogen from natural gas pyrolysis has recently emerged as a promising alternative for low-carbon hydrogen production with a high-value pure carbon by-product. However the implications of this technology on the broader energy system are not well understood at present. To close this literature gap this study presents an assessment of the integration of natural gas pyrolysis into a simplified European energy system. The energy system model minimizes the cost by optimizing investment and hourly dispatch of a broad range of electricity and fuel production transmission and storage technologies as well as imports/exports on the global market. Norway is included as a major natural gas producer and Germany as a major energy importer. Results reveal that pyrolysis is economically attractive at modest market shares where the carbon by-product can be sold into highvalue markets for 400 €/ton. However pyrolysis-dominated scenarios that employ methane as a hydrogen carrier also hold promise as they facilitate deep decarbonization without the need for vast expansions of international electricity hydrogen and CO2 transmission networks. The simplicity and security benefits of such pyrolysis-led decarbonization pathways justify the modest 11 % cost premium involved for an energy system where natural gas is the only energy trade vector. In conclusion there is a strong case for turquoise hydrogen in future energy systems and further efforts for commercialization of natural gas pyrolysis are recommended.

Environmental concerns regarding greenhouse gases have spurred research into alternative energy sources. One of the most prevalent waste products in the beverage industry is spent coffee grains (SCG) an estimated 60 million tons globally each year. These quantities justify the need to find effective ways to recycle this waste through the adoption of closed-loop circular economies (CE) and sustainable biofuel strategies. One promising approach is the conversion of SCG into biofuels particularly biohydrogen and biomethane through biological processes. However prior to commercialization it is critical to validate its potential profitability via technical and economic analyses such as techno-economic assessment (TEA). To this end in this study the profitability of two scenarios for biohydrogen and biomethane production has been assessed to explore feasible processing routes for SCG valorization. First a two-step dark fermentation and anaerobic digestion (DF-AD) process and second a two-step dark fermentation and photo fermentation (DF-PF) process. The profitability and sensitivity analysis results clarified that Scenario I should be chosen over Scenario II due to its higher net present value (NPV) of 138 million $ internal rate of return (IRR) of 15.3 % gross margin (GM) of 56.9 % return on investment (ROI) of 12.7 % and shorter payback period (PBP) of 6.2 years.

Hydrogen as an energy carrier is a promising alternative to fossil fuels and it becomes more and more popular in developed countries as a carbon-free fuel. The low boiling temperature of hydrogen (20 K or −253.15 ◦C) provides a unique opportunity to implement superconductors with a critical temperature above 20 K such as MgB2 or high-temperature superconductors. Superconductors increase efficiency and reduce the loss of energy which could compensate for the high price of LH2 to some extent. Norway is one of the pioneer countries with adequate infrastructure for using liquid hydrogen in the industry especially in marine technology where a superconducting propulsion system can make a remarkable impact on its economy. Using superconductors in the motor of a propulsion system can increase its efficiency from 95% to 98% when the motor operates at full power. The difference in efficiency is even greater when the motor does not work at full power. Here we survey the applications of liquid hydrogen and superconductors and propose a realistic roadmap for their synergy specifically for the Norwegian economy in the marine industry.

Hydrogen tanks used in transportation are equipped with thermal pressure relief devices to prevent a tank rapture in case of fire exposure. The opening of the pressure relief valve in such a scenario would likely result in an impinging and (semi-) confined hydrogen jet fire. Therefore twelve largescale experiments of hydrogen jet fires and one large-scale propane reference experiment have been conducted with various degrees of confinement orientations of the jet and distances from the nozzle to the impinging surface. Infrared and visible light videos temperatures heat fluxes and mass flow rate of hydrogen or propane were recorded in each experiment. It was found that the hydrogen flame can be visible under certain conditions. The main difference between an open impinging jet and an enclosed impinging jet fire is the extent of the high-temperature region in the steel target. During the impinging jet fire test 51% of the exposed target area exceeded 400C while 80% of the comparable area exceeded 400C during the confined jet fire test. A comparison was also made to an enclosed propane jet fire. The temperature distribution during the propane fire was more uniform than during the hydrogen jet fire and the localized hot spot in the impact region as seen in the hydrogen jet fires was not recorded.

Biohydrogen production from industrial wastewater has been a focus of interest in recent years. The in depth knowledge in lab scale parameters and emerging strategies are needed to be investigated in order to implement the biohydrogen production process at large scale. The operating parameters have great influence on biohydrogen productivity. With the aim to gain major insight into biohydrogen production process this review summarizes recent updates on dark fermentation inoculum pretreatment methods operating parameters (hydraulic retention time organic loading rate pH temperature volatile fatty acids bioreactor configuration nutrient availability partial pressure etc.). The challenges and limitations associated with the biohydrogen production are lack of biohydrogen producers biomass washout and accumulation of metabolites are discussed in detail. The advancement strategies to overcome these limitations are also briefly discussed.

In the wake of unprecedented global weather events and the ever-pressing urgency of climate change the discourse around energy transition has become more critical than ever.<br/>The United Kingdom once at the forefront of the energy transition movement finds itself at a crossroads. The initial rapid progress towards a low-carbon future is now facing hurdles threatening the achievement of the 'net zero by 2050' target.<br/>This revelation comes from the third edition of our UK Energy Transition Outlook (ETO) which leverages an independent model incorporating the UK's energy system's extensive connections with Europe and beyond.<br/>This report has a comprehensive analysis of:<br/>♦ Renewable energy technology scaling and costs<br/>♦ The continuing dependence on fossil fuel and need to decarbonize<br/>♦ Energy demand by sector and source<br/>♦ Energy efficiency<br/>♦ Energy supply<br/>♦ Electricity and infrastructure<br/>♦ Hydrogen<br/>♦ Energy expenditure<br/>♦ Policies driving the transition<br/>♦ Digitalization.

This study explores the potential of solar tracking technologies to enhance South Africa’s energy transition focusing on their role in supporting green hydrogen production for domestic use and export. Using the Global Energy System Model (GENeSYS-MOD) it evaluates four solar tracking technologies — horizontal axis tilted horizontal axis vertical axis and dual-axis — across six scenarios: tracking and non-tracking versions of a Business-as-Usual (BAU) scenario a 2 ◦C scenario and a high hydrogen demand and export (HighH2) scenario. The results identify horizontal axis tracking as the most cost-effective option followed by tilted horizontal axis tracking which is particularly prominent in the HighH2 scenario. Tracking systems enhance hydrogen production by extending power output and increasing electrolyzer full-load hours. In the HighH2 scenario they reduce hydrogen production costs in 2050 from 1.47 e/kg to 1.34 e/kg and system cost by 0.66% positioning South Africa competitively in the global hydrogen market. By integrating tracking technologies South Africa can align hydrogen production ambitions with renewable energy growth while mitigating grid and financial challenges. The research underscores the need for targeted energy investments and policies to maximize renewable energy and hydrogen potential ensuring a just energy transition that supports export opportunities domestic energy security and equitable socio-economic growth.

Hydrogen energy is critical in replacing fossil fuels and achieving net zero carbon emissions by 2050. Three measures can be implemented to promote hydrogen energy: reduce the cost of low-carbon hydrogen through technological improvements increase the production capacity of low-carbon hydrogen by stimulating investment and enhance hydrogen use as an energy carrier and in industrial processes by demand-side policies. This article examines how effective these measures are if successfully implemented in boosting the hydrogen market and reducing global economy-wide carbon emissions using a global computable general equilibrium model. The results show that all the measures increase the production and use of low-carbon hydrogen whether implemented alone or jointly. Notably the emissions reduced by joint implementation of all the measures in 2050 become 2.5 times the sum of emissions reduced by individual implementation indicating a considerable multiplier effect. This suggests supply and demand side policies be implemented jointly to maximize their impact on reducing emissions.

This paper presents multiple hydrogen electrolysers integrations in the power grid and their operational stra tegies for better performance. Electrolysers have been considered as electrical loads and multi-state load model for the operation of an electrolysers have been proposed. Strategy for the operation of multiple electrolysers at different positions in a grid are formulated and Multi-State Round Robin strategy is proposed. The proposed strategy is validated by implementing that to a coastal power grid and to meet the hydrogen energy demand of vessels at the ports. Simulation has been conducted modeling the grid and electrolysers in DIgSILENT Power factory. A comparison has been performed between two state load model and multi state load model considering Multi-State Round Robin operational strategy. Line loading and hydrogen production are the considered per formance indicators. The results show that the proposed model and strategy improves the hydrogen production and operational flexibility of the system.