Life cycle assessment of a renewable energy system with hydrogen-battery storage for a remote off-grid community

Remote areas usually do not have access to electricity from the national grid. The energy demand is often covered by diesel generators, resulting in high operating costs and significant environmental impacts. With reference to the case study of Ginostra (a village on a small island in the south of Italy), this paper analyses the environmental sustainability of an innovative solution based on Renewable Energy Sources (RES) integrated with a hybrid hydrogen-battery energy storage system. A comparative Life Cycle Assessment (LCA) has been carried out to evaluate if and to what extent the RES-based system could bring environmental improvements compared to the current diesel-based configuration. The results show that the impact of the RES-based system is less than 10% of that of the current diesel-based solution for almost all impact categories (climate change, ozone depletion, photochemical ozone formation, acidification, marine and terrestrial eutrophication and fossil resource use). The renewable solution has slightly higher values only for the following indicators: use of mineral and metal resources, water use and freshwater eutrophication. The climate change category accounts for 0.197 kg CO₂ eq./kWh in the renewable scenario and 1.73 kg CO₂ eq./kWh in the diesel-based scenario, which corresponds to a reduction in GHG emissions of 89%. By shifting to the RES-based solution, about 6570 t of CO₂ equivalent can be saved in 25 years (lifetime of the plant). In conclusion, the hydrogen-battery system could provide a sustainable and reliable alternative for power supply in remote areas.     

A life cycle impact analysis of various hydrogen production methods for public transportation sector

Reducing greenhouse gas emissions is an important task to reduce the adverse effects of climate change. A large portion of greenhouse gas emissions apparently originates from the transportation sector. Therefore, adopting cleaner technologies with lower emission footprints has become vital. For this reason, in this study, a life cycle impact analysis of hydrogen production technologies as an alternative to fossil fuels and the utilization of hydrogen in fuel cell electric buses is carried out. According to the results of this study, the operational contributions of internal combustion engines have a significant impact on life cycle impact analysis indicators. The global warming potentials of clean hydrogen production technologies result in much lower results compared to conventional hydrogen production technologies. Also, almost all indicators for biohydrogen production technologiess yield lower results because of the wastewater removal. The global warming potential results of hydrogen production methods are found to be 6.8, 1.9, 2.1, 0.5, 0.2, and 7.9 kg CO₂ eq./kg H₂ for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation and conventional hydrogen production, respectively. However, the chemicals used in PV and wind turbine production increased the ecotoxicological indicators. On the other hand, hydrogen utilization in buses is a better option environmentally. The global warming potentials for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation, conventional hydrogen, compressed natural gas bus, and diesel bus are found to be 0.060, 0.016, 0.018, 0.007, 0.006, 0.053, 0.082, and 0.125 kg CO₂ eq./p.km, respectively. The results are especially important in terms of reducing the effects at the source and optimizing the systems.     

Greenhouse-gas emissions from solar electric- and nuclear power: A life-cycle study

Solar- and nuclear-electricity-generation technologies often are deemed “carbon-free” because their operation does not generate any carbon dioxide. However, this is not so when considering their entire lifecycle of energy production; carbon dioxide and other gases are emitted during the extraction, processing, and disposal of associated materials. We determined the greenhouse gas (GHG) emissions, namely, CO₂, CH₄, N₂O, and chlorofluorocarbons due to materials and energy flows throughout all stages of the life of commercial technologies for solar-electric- and nuclear-power generation, based on data from 12 photovoltaic (PV) companies, and reviews of nuclear-fuel life cycles in the United States, Europe, and Japan. Previous GHG estimates vary widely, from 40 to 180 CO₂-eq./kWh for PV, and 3.5–100 CO₂-eq./kWh for nuclear power. Country-specific parameters account for many of these differences, which are exacerbated by outdated information. We conclude, instead, that lifetime GHG emissions from solar- and nuclear-fuel cycles in the United States are comparable under actual production conditions and average solar irradiation, viz., 22–49 g CO₂-eq./kWh (average US), 17–39 g CO₂-eq./kWh (south west) for solar electric, and 16–55 g CO₂-eq./kWh for nuclear energy. However, several factors may significantly change this picture within the next 5 years, and there are unanswered questions about the nuclear fuel cycle that warrant further analyses.     

Life cycle assessment of electricity generation in Mexico

This paper presents for the first time a Life Cycle Assessment (LCA) study of electricity generation in Mexico. The electricity mix in Mexico is dominated by fossil fuels, which contribute around 79% to the total primary energy; renewable energies contribute 16.5% (hydropower 13.5%, geothermal 3% and wind 0.02%) and the remaining 4.8% is from nuclear power. The LCA results show that 225 TWh of electricity generate about 129 million tonnes of CO₂ eq. per year, of which the majority (87%) is due to the combustion of fossil fuels. The renewables and nuclear contribute only 1.1% to the total CO₂ eq. Most of the other LCA impacts are also attributed to the fossil fuel options. The results have been compared with values reported for other countries with similar electricity mix, including Italy, Portugal and the UK, showing good agreement.     

Comparative environmental impact assessment of various fuels and solar heat for a combined cycle

In the present study, a comparative life cycle assessment (LCA) for evaluation of the environmental impacts of different fuels to generate electricity through a combined cycle is carried out. For this purpose, various heat sources including solar thermal, lignite, natural gas, oil, and hydrogen are investigated with LCA methods. The methods considered for the study include CML 2001 and ReCiPe Endpoint. The results of the present LCA study for both methods show that the hydrogen is the best fuel option according to the environmental impacts. The impact categories obtained from CML 2001 are the depletion of abiotic resources, eutrophication, global warming, marine sediment, and aquatic ecotoxicity, freshwater aquatic ecotoxicity and the competition of land. Furthermore, the human health, ecosystems and resource availability are investigated with the ReCiPe Endpoint method. The greenhouse gas emissions per kWh electricity generation are 0.19 kg CO₂ eq for solar, 1.21 kg CO₂ eq for lignite, 0.53 kg CO₂ eq for natural gas, 1.11 kg CO₂ eq for oil and 0.04 kg CO₂ eq for hydrogen according to the CML 2001 method.     

Lower electricity prices and greenhouse gas emissions due to rooftop solar: empirical results for Massachusetts

Monthly and hourly correlations among photovoltaic (PV) capacity utilization, electricity prices, electricity consumption, and the thermal efficiency of power plants in Massachusetts reduce electricity prices and carbon emissions beyond average calculations. PV utilization rates are highest when the thermal efficiencies of natural gas fired power plants are lowest, which reduces emissions of CO₂ and CH₄ by 0.3% relative to the annual average emission rate. There is a positive correlation between PV utilization rates and electricity prices, which raises the implied price of PV electricity by up to 10% relative to the annual average price, such that the average MWh reduces electricity prices by $0.26–$1.86 per MWh. These price reductions save Massachusetts rate-payers $184 million between 2010 and 2012. The current and net present values of these savings are greater than the cost of solar renewable energy credits which is the policy instrument that is used to accelerate the installation of PV capacity. Together, these results suggest that rooftop PV is an economically viable source of power in Massachusetts even though it has not reached socket parity.     

A liquefied energy chain for transport and utilization of natural gas for power production with CO2 capture and storage – Part 2: The offshore and the onshore processes

A novel energy and cost effective transport chain for stranded natural gas utilized for power production with CO₂ capture and storage is developed. It includes an offshore section, a combined gas carrier, and an integrated receiving terminal. In the offshore process, natural gas (NG) is liquefied to LNG by liquid carbon dioxide (LCO₂) and liquid inert nitrogen (LIN), which are used as cold carriers. The offshore process is self-supported with power, hot and cold utilities and can operate with little rotating equipment and without flammable refrigerants. In the onshore process, the cryogenic exergy in LNG is used to cool and liquefy the cold carriers, which reduces the power requirement to 319 kWh/tonne LNG. Pinch and exergy analyses are used to determine thermodynamically optimized offshore and onshore processes with exergy efficiencies of 87% and 71%, respectively. There are very low emissions from the processes. The estimated specific costs for the offshore and onshore process are 8.0 and 14.6 EUR per tonne LNG, respectively, excluding energy costs. With an electricity price of 100 EUR per MWh, the specific cost of energy in the onshore process is 31.9 EUR per tonne LNG.     

Life cycle assessment of the offshore wind farm alpha ventus

Due to better wind conditions at sea, offshore wind farms have the advantage of higher electricity production compared to onshore and inland wind farms. In contrast, a greater material input, leading to increased energy consumptions and emissions during the production phase, is required to build offshore wind farms. These contrary effects are investigated for the first German offshore wind farm alpha ventus in the North Sea. In a life cycle assessment its environmental influence is compared to that of Germany’s electricity mix.In comparison to the mix, alpha ventus had better indicators in nearly every investigated impact category. One kilowatt-hour electricity, generated by the wind farm, was burdened with 0.137 kWh Primary Energy-Equivalent and 32 g CO₂-Equivalent, which represented only a small proportion of the accordant values for the mix. Furthermore, the offshore foundations as well as the submarine cable were the main energy intensive components. The energetic and greenhouse gas payback period was less than one year.Therefore, offshore wind power, even in deep water, is compatible with the switch to sustainable electricity production relying on renewable energies. Additional research, taking backup power plants as well as increasingly required energy storage systems into account, will allow further calculation.     

Economic perspective of PV electricity in Oman

Solar and wind energies are likely to play an important role in the future energy generation in Oman. This paper utilizes average daily global solar radiation and sunshine duration data of 25 locations in Oman to study the economic prospects of solar energy. The study considers a solar PV power plant of 5-MW at each of the 25 locations. The global solar radiation varies between slightly greater than 4 kWh/m²/day at Sur to about 6 kWh/m²/day at Marmul while the average value in the 25 locations is more than 5 kWh/m²/day. The results show that the renewable energy produced each year from the PV power plant varies between 9000 MWh at Marmul and 6200 MWh at Sur while the mean value is 7700 MWh of all the 25 locations. The capacity factor of PV plant varies between 20% and 14% and the cost of electricity varies between 210 US$/MWh and 304 US$/MWh for the best location to the least attractive location, respectively. The study has also found that the PV energy at the best location is competitive with diesel generation without including the externality costs of diesel. Renewable energy support policies that can be implemented in Oman are also discussed.     

Environmental and energy efficiency assessments of offshore hydrogen supply chains utilizing compressed gaseous hydrogen,liquefied hydrogen,liquid organic hydrogen carriers and ammonia

Hydrogen has emerged as an eco-friendly energy to replace fossil fuels. But, it is difficult to store large capacity and to transport long distance due to a low volumetric energy density. In order to overcome the disadvantages of hydrogen, hydrogen supply chains are being widely studied and reported to compare which chains are better to be deployed. However, few studies have reported in terms of an environmental impact assessment. Therefore, in this study, an environmental impact is analyzed using a life cycle assessment (LCA) for offshore hydrogen supply chains linked to offshore wind farms, as well as an energy efficiency. The hydrogen supply chains include all stages of converting hydrogen produced on an offshore platform into compressed gaseous hydrogen (CGH₂), liquefied hydrogen (LH₂), liquid organic hydrogen carriers (LOHC), or ammonia (NH₃), transporting them to an onshore plant and storing as CGH₂. In particular, in order to calculate the amount of fuel consumed in ship transportation, the weight of cargo is estimated accordingly. The results vary depending on the electrical energy sources used and the transport distance. In almost all stages except for transport, electrical energy sources have a significant impact on the environmental load. The global warming potential (GWP), which is an alternate value of greenhouse gas emissions, is in the range of 1.15–10.11 kg CO₂ eq when the national electricity grid and the offshore wind power (W + G) are used together. On the other hand, it shows a much lower value as 1.15–2.05 kg CO₂ eq when using only offshore wind power (W). As the transport distance increased, it is significantly affected in some impact categories, i.e. GWP, acidification potential (AP), and eutrophication potential (EP). The contribution of transport gradually increased, and at 10,000 km, the value was 25.32–35.42 kg CO₂ eq for W + G and 24.88–27.49 kg CO₂ eq for W. Comparing the efficiency, CGH₂ is the highest at all transport distances, followed by NH₃, LOHC, and LH₂. Considering that CGH₂ is typically unfeasible for ship transport, hydrogen transport using NH₃ can be the most attractive option. Finally, it is found that the longer the transport distance, the greater the effect on chain efficiency. Accordingly, the efficiency of the chains sharply decreases as the transport distance increases.     

Implications of technological learning on the prospects for renewable energy technologies in Europe

The objective of this article is to examine the consequences of technological developments on the market diffusion of different renewable electricity technologies in the EU-25 until 2020, using a market simulation model (ADMIRE REBUS). It is assumed that from 2012 a harmonized trading system will be implemented, and a target of 24% renewable electricity (RES-E) in 2020 is set and met. By comparing optimistic and pessimistic endogenous technological learning scenarios, it is found that diffusion of onshore wind energy is relatively robust, regardless of technological development, but diffusion rates of offshore wind energy and biomass gasification greatly depend on their technological development. Competition between these two options and (existing) biomass combustion options largely determines the overall costs of electricity from renewables and the choice of technologies for the individual member countries. In the optimistic scenario, in 2020 the market price for RES-E is 1 €ct/kWh lower than in the pessimistic scenario (about 7 vs. 8 €ct/kWh). As a result, total RES-E production costs are 19% lower, and total governmental expenditures for RES-market stimulation are 30% lower in the optimistic scenario.     

Environmental and economic assessment of landfill gas electricity generation in Korea using LEAP model

As a measure to establish a climate-friendly energy system, Korean government has proposed to expand landfill gas (LFG) electricity generation capacity. The purpose of this paper is to analyze the impacts of LFG electricity generation on the energy market, the cost of generating electricity and greenhouse gases emissions in Korea using a computer-based software tool called ‘Long-range Energy Alternative Planning system’ (LEAP) and the associated ‘Technology and Environmental Database’. In order to compare LFG electricity generation with existing other generating facilities, business as usual scenario of existing power plants was surveyed, and then alternative scenario investigations were performed using LEAP model. Different alternative scenarios were considered, namely the base case with existing electricity facilities, technological improvement of gas engine and LFG maximum utilization potential with different options of gas engine (GE), gas turbine (GT), and steam turbine (ST). In the technological improvement scenario, there will be 2.86 GWh or more increase in electricity output, decrease of 45 million won (Exchange rate (1$=1200 won)). in costs, and increase of 10.3 thousand ton of CO₂ in global warming potentials due to same period (5 year) of technological improvement. In the maximum utilization potential scenario, LFG electricity generation technology is substituted for coal steam, nuclear, and combined cycle process. Annual cost per electricity product of LFG electricity facilities (GE 58MW, GT 53.5MW, and ST 54.5MW) are 45.1, 34.3, and 24.4 won/kWh, and steam turbine process is cost-saving. LFG-utilization with other forms of energy utilization reduces global warming potential by maximum 75% with compared to spontaneous emission of CH₄. LFG electricity generation would be the good solution for CO₂ displacement over the medium term and additional energy profits.     

Battery control for leveling the amount of electricity purchase in smart‐energy houses

An optimal operation method in smart‐energy houses with photovoltaics (PV) and a storage battery was investigated in a trial production system. In this method, the inverse current of the PV output is not conveyed to the commercial electricity system as operation conditions. Instead, the excess of the consumed PV power is applied to leveling the electricity purchase by appropriately charging and discharging the storage battery. To validate the proposed system, a lithium battery (4 kWh) and PV cell (3 kW) used in average individual houses was installed in a smart‐energy house in a local city (Kitami) in Japan. Another example was introduced into a wider area (Hokkaido, Japan). Accounting for the error between the weather forecast and actual solar radiation, the trial production system reduced the range in the electricity purchase amount by 75.0%, 77.0%, and 73.0% on a representative day in January, April, and July, respectively. The accuracy of the reduction effect in the trial production system, obtained in the proposed optimization analysis, ranged from 1.9% to 7.2%. Moreover, the CO₂ emissions were reduced by 1.990 kg‐CO₂/(Day‐House) in January, 2.910 kg‐CO₂/(Day‐House) in April, and 2.210 kg‐CO₂/(Day‐House) in July.     

Life cycle assessment of an onshore wind farm located at the northeastern coast of Brazil

This article assesses the life cycle emissions of a fictive onshore wind power station consisting of 141.5-MW wind turbines situated on the northeastern coast of Brazil. The objective is to identify the main sources of CO_2(eq)-emissions during the life cycle of the wind farm. The novelty of this work lies in the focus on Brazil and its emerging national manufacturing industry. With an electricity matrix that is primarily based on renewable energy sources (87% in 2010), this country emits eight times less CO₂ for the production of 1 kWh of electricity than the global average. Although this fact jeopardizes the CO₂ mitigation potential of wind power projects, it also reduces the carbon footprint of parts and components manufactured in Brazil. The analysis showed that reduced CO₂-emissions in the material production stage and the low emissions of the component production stage led to a favorable CO₂-intensity of 7.1 g CO₂/kWh. The bulk of the emissions, a share of over 90%, were unambiguously caused by the production stage, and the transportation stage was responsible for another 6% of the CO₂-emissions. The small contributions from the construction and operation phases could be neglected. Within the manufacturing process, the steel tower was identified as the source responsible for more than half of the emissions. The environmental impacts of the wind farm are small in terms of CO₂-emissions, which can be credited to a green electricity mix. This scenario presents an advantage for the country and for further production sites, particularly in the surroundings of the preferred wind farm sites in Brazil, which should be favored to reduce CO₂ emissions to an even greater extent.     

The economics of wind power with energy storage

We develop a nonlinear mathematical optimization program for investigating the economic and environmental implications of wind penetration in electrical grids and evaluating how hydropower storage could be used to offset wind power intermittence. When wind power is added to an electrical grid consisting of thermal and hydropower plants, it increases system variability and results in a need for additional peak-load, gas-fired generators. Our empirical application using load data for Alberta's electrical grid shows that costs of wind-generated electricity vary from $37 per MWh to $68/MWh, and depend primarily on the wind profiles of installed turbines. Costs of reducing CO₂ emissions are estimated to be $41–$56 per t CO₂. When pumped hydro storage is introduced in the system or the capacity of the water reservoirs is enhanced, the hydropower facility could provide most of the peak load requirements obviating the need to build large peak-load gas generators.     

Comparison of carbon dioxide and nuclear waste storage costs in Lithuania

Nuclear power and carbon capture and storage (CCS) are key greenhouse gas mitigation options under consideration across the world. Both technologies imply long-term waste management challenge. Geological storage of carbon dioxide (CO₂) and nuclear waste has much in common, and valuable lessons can be learnt from a comparison. Seeking to compare these technologies economic, social and environmental criteria need to be selected and expressed in terms of indicators. Very important issue is costs and economics of geological storage of carbon dioxide and nuclear waste. The costs of storage are one of the main indicators for assessment of technologies in terms of economic criteria.The paper defines the costs of the geological storage of CO₂ and nuclear waste in Lithuania, drawing also on insights from other parts of the world. The costs of carbon dioxide and nuclear waste storage are evaluated in UScnt/kWh and compared. The paper critically compares the characteristics and location of the both sources of and storage options for CO₂ and nuclear waste in Lithuania. It discusses the main costs categories for carbon dioxide and nuclear waste storage. The full range of potential geological storage options is considered and the most reliable options for carbon dioxide and nuclear waste are selected for the comparative costs assessment.     

A liquefied energy chain for transport and utilization of natural gas for power production with CO2 capture and storage – Part 1

A novel transport chain for stranded natural gas utilized for power production with CO₂ capture and storage is developed. It includes an offshore section, a combined gas carrier, and an onshore integrated receiving terminal. Due to utilization of the cold exergy both in the offshore and onshore processes, and combined use of the gas carrier, the transport chain is both energy and cost effective. In this paper, the liquefied energy chain (LEC) is explained, including novel processes for both the offshore field site and onshore market site. In the offshore section, natural gas (NG) is liquefied to LNG by liquid carbon dioxide (LCO₂) and liquid inert nitrogen (LIN), which are used as cold carriers. The LNG is transported in a combined gas carrier to the receiving terminal where it is used as a cooling agent to liquefy CO₂ and nitrogen. The LCO₂ and LIN are transported offshore using the same combined carrier. Pinch and Exergy Analyses are used to determine the optimal offshore and onshore processes and the best transport conditions. The exergy efficiency for a thermodynamically optimized process is 87% and 71% for the offshore and onshore processes, respectively, yielding a total efficiency of 52%. The offshore process is self-supported with power and can operate with few units of rotating equipment and without flammable refrigerants. The loss of natural gas due to power generation for the energy requirements in the LEC processes is roughly one third of the loss in a conventional transport chain for stranded natural gas with CO₂ sequestration. The LEC has several configurations and can be used for small scale (<0.25 MTPA LNG) to large-scale (>5 MTPA LNG) transport. In the example in this paper, the total costs for the simple LEC including transport of natural gas to a 400 MW_net power plant and return of 85% of the corresponding carbon as CO₂ for a total sailing distance of 24 h are 58.1 EUR/tonne LNG excluding or including the cost of power. The total power requirements are 319 kWh/tonne, hence the energy costs are 31.9 EUR/tonne LNG adding up to 90.0 EUR/tonne LNG. The exergy efficiency for this energy chain including power production and CO₂ capture is 46.4% with a total cost of 20.4 EUR/MWh for the produced electricity. The total emissions (in CO₂ equivalents) in the chain are 1–1.5% of the transported CO₂.     

Performance analysis of various hybrid renewable energy systems using battery,hydrogen, and pumped hydro‐based storage units

The aim of this research is to analyze the techno‐economic performance of hybrid renewable energy system (HRES) using batteries, pumped hydro‐based, and hydrogen‐based storage units at Sharurah, Saudi Arabia. The simulations and optimization process are carried out for nine HRES scenarios to determine the optimum sizes of components for each scenario. The optimal sizing of components for each HRES scenario is determined based on the net present cost (NPC) optimization criterion. All of the nine optimized HRES scenarios are then evaluated based on NPC, levelized cost of energy, payback period, CO₂ emissions, excess electricity, and renewable energy fraction. The simulation results show that the photovoltaic (PV)‐diesel‐battery scenario is economically the most viable system with the NPC of US$2.70 million and levelized cost of energy of US$0.178/kWh. Conversely, PV‐diesel‐fuel cell system is proved to be economically the least feasible system. Moreover, the wind‐diesel‐fuel cell is the most economical scenario in the hydrogen‐based storage category. PV‐wind‐diesel‐pumped hydro scenario has the highest renewable energy fraction of 89.8%. PV‐wind‐diesel‐pumped hydro scenario is the most environment‐friendly system, with an 89% reduction in CO₂ emissions compared with the base‐case diesel only scenario. Overall, the systems with battery and pumped hydro storage options have shown better techno‐economic performance compared with the systems with hydrogen‐based storage.     

Photovoltaic (PV) electricity: Comparative analyses of CO2 abatement at different fuel mix scales in the US

Photovoltaic electricity has the potential to mitigate CO₂ emissions from the grid. A methodology to more accurately evaluate CO₂ abatement by PV electricity is developed. We develop a capacity factor based dispatching model to evaluate marginal abatement in the load zones of ERCOT and CAISO, and compare it to the abatement using national, regional and state average resource profiles. The average cases over-estimated and under-estimated CO₂ abatement in ERCOT and CAISO, respectively. Marginal abatement was lower by 17% than the average cases in ERCOT, due to the predominant displacement of the low carbon natural gas plants at the margin. In CASIO, marginal abatement was higher (1.3–2.4 times) than that of the average cases due to the displacement of highly inefficient gas plants at the margin. We demonstrate that actual CO₂ abatement of PV electricity is dependent on both peak load resources and capacity of installations. Subsequently, we develop a CO₂ indicator that can be used as a guideline for selecting PV installation sites to derive maximum abatement. Installing photovoltaics in regional areas of MRO, SPP and RFC was determined to be most beneficial. The results of this study can guide energy planning and CO₂ mitigation policy-making using photovoltaics in the future.     

Low-carbon hydrogen production via electron beam plasma methane pyrolysis: Techno-economic analysis and carbon footprint assessment

Electron beam plasma methane pyrolysis is a hydrogen production pathway from natural gas without direct CO₂ emissions. In this work, two concepts for a technical implementation of the electron beam plasma pyrolysis in a large-scale hydrogen production plant are presented and evaluated in regards of efficiency, economics and carbon footprint. The potential of this technology is identified by an assessment of the results with the benchmark technologies steam methane reforming, steam methane reforming with carbon capture and storage as well as water electrolysis. The techno-economic analysis shows levelized costs of hydrogen for the plasma pyrolysis between 2.55 €/kg H₂ and 5.00 €/kg H₂ under the current economic framework. Projections for future price developments reveal a significant reduction potential for the hydrogen production costs, which support the profitability of plasma pyrolysis under certain scenarios. In particular, water electrolysis as direct competitor with renewable electricity as energy supply shows a considerably higher specific energy consumption leading to economic advantages of plasma pyrolysis for cost-intensive energy sources and a high degree of utilization. Finally, the carbon footprint assessment indicates the high potential for a reduction of life cycle emissions by electron beam plasma methane pyrolysis (1.9 kg CO₂ eq./kg H₂ – 6.4 kg CO₂ eq./kg H₂, depending on the electricity source) compared to state-of-the-art hydrogen production technology (10.8 kg CO₂ eq./kg H₂).