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Abstract Background The residential heating sector in many European countries requires a fundamental transformation if it is to become climate neutral. Besides the introduction of efficiency measures and updating heating systems, scholars and practitioners consider replacing fossil fuels in existing heating systems a viable approach. Drop-in renewable gases such as biomethane and synthetic natural gas (SNG) cause considerably fewer carbon dioxide (CO2) emissions than natural gas and can be used in natural gas boilers, the dominant heating system in many European countries. To move the ongoing debate around e-fuels forward, this study reports on a Discrete Choice Experiment with 512 respondents in Germany that analyzed consumer preferences and willingness to pay (WTP) for SNG. I build on these insights by comparing WTP to the production costs, making evidence-based decision-making possible. Results The results show that consumers prefer renewable gases over natural gas. Comparing the two types of renewable gases, SNG and biomethane, reveals that consumers clearly favor the latter despite the criticism it has come under in the last 10–15 years. Consumers show a surprisingly high WTP for increasing shares of SNG, with premia of 40 to almost 70% over a natural gas-based tariff. Comparing production costs to the WTP reveals that only tariffs with small shares of SNG (5% and 10%) can be offered at cost-covering prices. Conclusions Given the urgent need for a fundamental transition of the residential heating sector, marketers and policymakers should consider carefully whether it is worth channeling a rather unknown and expensive product like SNG into the voluntary market for heating gas, especially as biomethane is already established in the market and clearly a cheaper and more popular alternative.

Background: The residential heating sector in many European countries requires a fundamental transformation if it is to become climate neutral. Besides the introduction of efficiency measures and updating heating systems, scholars and practitioners consider replacing fossil fuels in existing heating systems a viable approach. Drop-in renewable gases such as biomethane and synthetic natural gas (SNG) cause considerably fewer carbon dioxide (CO2) emissions than natural gas and can be used in natural gas boilers, the dominant heating system in many European countries. To move the ongoing debate around e-fuels forward, this study reports on a Discrete Choice Experiment with 512 respondents in Germany that analyzed consumer preferences and willingness to pay (WTP) for SNG. I build on these insights by comparing WTP to the production costs, making evidence-based decision-making possible. Results: The results show that consumers prefer renewable gases over natural gas. Comparing the two types of renewable gases, SNG and biomethane, reveals that consumers clearly favor the latter despite the criticism it has come under in the last 10–15 years. Consumers show a surprisingly high WTP for increasing shares of SNG, with premia of 40 to almost 70% over a natural gas-based tariff. Comparing production costs to the WTP reveals that only tariffs with small shares of SNG (5% and 10%) can be offered at cost-covering prices. Conclusions: Given the urgent need for a fundamental transition of the residential heating sector, marketers and policymakers should consider carefully whether it is worth channeling a rather unknown and expensive product like SNG into the voluntary market for heating gas, especially as biomethane is already established in the market and clearly a cheaper and more popular alternative. [ABSTRACT FROM AUTHOR]

The current climatic and geopolitical situation leads to strong decarbonisation policies in several industries worldwide. Moreover, the European Union is pushing intensive industries to achieve a 55% reduction in CO2 emissions towards 2030. Among them, the steel manufacturing sector is at the lead of alternative projects that can help achieve this ambitious target. Co-production of syngas and biochar is one potential solution for this sector. Herein, a techno-economic analysis is provided to evaluate the economic feasibility and the effect of the most influential parameters for a successful deployment. A bibliographic review has been carried out to establish a clear baseline for such an analysis in terms of investment costs at several scales for gasification projects. Additionally, the cost evolution for coke, natural gas, and CO2 emission credits on the profitability of these projects are given. The case scenario processing 20,000 tbiomass/y is the most feasible solution, with a payback of around three years and a net present value (NPV) of around 15 million EUR, showing that biomass gasification can be an up-and-coming alternative in the mid-term. [ABSTRACT FROM AUTHOR]

The gas turbine industry strongly committed to develop gas turbines operating with 100% hydrogen till 2030, such fully supporting the transformation of the European natural gas grid into a renewable-based energy system by overcoming technical challenges and ensuring that this transformation takes place swiftly. By extending the fuel capabilities of gas turbines to hydrogen, their role can become predominant in the energy transition period but also in longterm energy strategies. In combined cycle configuration (CCGT), gas turbines are already the cleanest form of thermal power generation. For the same amount of electricity generated, gas turbines running on natural gas emit 50% less CO2 emissions than coal-fired power plants. Mixing renewable gas (e.g., green hydrogen, biogas) with natural gas enables further reduction in net CO2 emissions. In this paper pure hydrogen and blends of hydrogen methane will be studied as fuel in order to predict the behavior of afterburner system with a new designed geometry. [ABSTRACT FROM AUTHOR]

Renewable hydrogen is an energy vector that appears as a keysustainable solution for the decarbonisation of the economy. In this sense, theregulatory framework must recognize its potential, assuming the challengesand opportunities that this energy vector has. Thus, the purpose of this study isto make regulatory proposals that we understand are adequate to achieve the promotion of the renewable hydrogen value chains. In particular, we examinelegal aspects regarding the actions of infrastructure owners and the applicationof the principles of unbundling and third-party access to the networks. We alsohighlight the necessary cross-border cooperation framework that must existbetween owners of the facilities. Likewise, we address the most relevant aspectsof the remuneration regime that must be configured for the owners of thefacilities. And, finally, we examine the current framework for promoting renewablehydrogen in Spain. This promotion framework is built on the basis of competitivecalls that select the pioneering and most innovative projects.

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The current climatic and geopolitical situation leads to strong decarbonisation policies in several industries worldwide. Moreover, the European Union is pushing intensive industries to achieve a 55% reduction in CO2 emissions towards 2030. Among them, the steel manufacturing sector is at the lead of alternative projects that can help achieve this ambitious target. Co-production of syngas and biochar is one potential solution for this sector. Herein, a techno-economic analysis is provided to evaluate the economic feasibility and the effect of the most influential parameters for a successful deployment. A bibliographic review has been carried out to establish a clear baseline for such an analysis in terms of investment costs at several scales for gasification projects. Additionally, the cost evolution for coke, natural gas, and CO2 emission credits on the profitability of these projects are given. The case scenario processing 20,000 tbiomass/y is the most feasible solution, with a payback of around three years and a net present value (NPV) of around 15 million EUR, showing that biomass gasification can be an up-and-coming alternative in the mid-term.

Northern countries face a unique challenge in decarbonizing heating demands. This study compares two pathways to reduce carbon emissions from building heating by (1) replacing natural gas heaters with electric heat pumps or (2) replacing natural gas with renewable gas. Optimal annual system cost and capacity requirements for Metro Vancouver, Canada are assessed for each pathway, under nine scenarios. Results show that either pathway can be lower cost but the range of costs is more narrow for the renewable gas pathway. System cost is sensitive to heat demand, with colder temperatures favouring the renewable gas pathway and milder temperatures favouring the electrification pathway. These results highlight the need for a better understanding of heating profiles and associated energy system requirements.

The scaling up of renewable gases is now being presented as a critical and effective component of the EU's long-term decarbonization strategy. Yet, the support schemes implemented for biogas and biomethane are far less studied than the ones dedicated to renewable power generation (e.g., solar or wind). This work bridges this gap by reviewing the supporting policies implemented in the EU and conducting a retrospective comparative analysis of the mechanisms implemented in Germany, Denmark, and Italy. The analysis is based on primary data extracted from policy statements that have been harmonized. Results show that incentivizing the supply side lowers the risk associated with early investments and market development. Conversely, they highlight inhomogeneity among countries in accounting for demand and end-use in their policies. Finally, they point at the availability of feedstock and the geographic and economic structure of a country as factors influencing the development of a market for renewable gases. The analysis stresses the value of policy mix in promoting biogas and biomethane in the EU's energy mix, and it hinges on the importance of scrutinizing sectoral massification, novel business models, infrastructure integration, and enhanced financial accessibility to improve their competitiveness and market advancement within the energy landscape. [Display omitted] • Novel structure analyzes policy evolution with harmonized primary data from policy statements. • Retrospective comparative analysis explores "support scheme-deployment" link for renewable gas. • Supply-side policies decrease early investments and market design risks. • Market evolution of biogas and biomethane is country-specific. [ABSTRACT FROM AUTHOR]

The article describes the technology of the “hydraulic piston”, as well as the studies that confirm the viability of this technology, implemented in various devices, designed to compress natural gas (CNG) and biomethane (bio-CNG), to accumulate CNG and bio-CNG, to deliver bio-CNG from the production site to the point of its injection into the natural gas network or to the vehicle fuelling stations to fill the Natural Gas Vehicles (NGV). The article presents prototypes of personal fuelling devices and mobile fuelling systems developed by Hygen Ltd. (Hygen), thereby showing the potential of the technology to contribute in the deployment of alternative fuel infrastructure and into the global GHG emissions reduction, mainly in the transport sector.

Biogas is an instrument of synergy between responsible waste management and renewable energy production in the overall transition to sustainability. The aim of this research is to assess the integration of the power-to-gas concept into a food waste-based biogas plant with the goal to produce renewable methane. A robust optimisation was studied, using linear programming with the objective of minimising total costs, while considering the market price of electricity. The mathematical model was tested at an existing biogas power plant with the installed capacity of 1 MW el. It was determined that the integration of power-to-gas in this biogas plant requires the installation of ca. 18 MW el of wind and 9 MW el of photovoltaics, while importing an additional ca. 16 GWh el from the grid to produce 36 GWh of renewable methane. The economic analysis showed that the feedstock gate fee contributes significantly to the economic viability of renewable methane: a change in the feedstock gate fee by 100 €/tonne results in a decrease of production costs by ca. 20–60%. The robust nature of the model showed that uncertainties related to electricity production from wind and photovoltaics at the location increased the cost of gas production by ca. 10–30%. • Robust optimisation of power-to-gas integration in biogas plant was studied. • Hourly level operation was investigated with regard to electricity market prices. • Capacities of units for production and demand of electricity were assessed. • Gate fee significantly contributes to viability of renewable methane production. • Uncertainties in electricity production decrease system's economic benefits. [ABSTRACT FROM AUTHOR]

The decarbonisation of industry, heating and transportation is a major challenge for many countries' energy transition. Hydrogen is a direct low-carbon fuel alternative to natural gas offering a higher flexibility in the range of possible applications, yet currently most hydrogen is produced using carbon-intensive steam methane reforming due to cost considerations. Therefore, this study explores the economics of a prominent low-carbon method of hydrogen production, comparing the cost of hydrogen generation from offshore wind farms with and without grid electricity imports to conventional hydrogen production methods. A novel techno-economic model for offshore electrolysis production costs is presented, which makes hydrogen production fully dispatchable, leveraging geological salt-cavern storage. This model determines the lifetime costs aportioned across the system components, as well as the Levelised Cost of Hydrogen (LCOH). Using the United Kingdom as a case study, LCOH from offshore wind power is calculated to be €8.68/kg H2 using alkaline electrolysis (AEL), €10.49/kg H2 using proton exchange membrane electrolysis (PEMEL), and €10.88/kg H2 with grid electricity to backup the offshore wind power. A stochastic Monte-Carlo model is used to asses the uncertainty on costs and identify the cost of capital, electrolyser and wind farm capital costs, and cost of electricity as the most important drivers of LCOH across the different scenarios. Reducing the capital cost to comparative levels observed on today's wind farms alone, could see AEL LCOH fall to €5.32/kg H2 , near competitive with conventional generation methods. • Development of a techno-economic model for offshore electrolysis production cost. • Lifetime hydrogen production and Levelized cost of gas (LCOH) are determined. • LCOH is calculated using deterministic and stochastic Monte-Carlo models. • Alkaline electrolysis with offshore wind power cost is the UK's lowest cost option. [ABSTRACT FROM AUTHOR]

Abstract Background Mitigating climate change requires fundamentally redesigned energy systems in which renewable energy sources ultimately replace fossil fuels such as natural gas. In this context, the question how and to which extent the gas sector can contribute to an increasingly climate-neutral future EU energy system is heavily debated among scholars, energy industry experts, and policy makers. Methods We take a two-step approach: we begin with a review of studies from energy industry and academia to discuss potential gas sector contributions from a holistic energy system design point of view; this is followed by a comprehensive discussion of technical potentials, micro-economic conditions, and societal implications of renewable gas. We then enrich our findings with the results of an empirical focus group process. Results The gas sector can not only contribute to balancing volatile renewable energy production but also enable the supply of renewable energy to end-users in gaseous form; based on existing infrastructure. This could reduce costs for society, increase public acceptance, and ultimately speed up the energy system transformation. There is the theoretical technical potential to substitute major parts of natural gas with renewable gas of biogenic and synthetic nature. This, however, crucially requires a supportive policy framework like the one established for renewable electricity. Conclusion Given the societal benefits and the competitiveness of renewable gas as compared to renewable alternatives, energy policy makers should incorporate renewable gas and the existing gas infrastructure in the future energy system framework. The objective should be an optimized interplay of various energy vectors and their infrastructure along the entire energy supply chain. This requires a level playing field for different renewable technologies across different policy areas and a form of public support that strikes the balance between facilitating the gradual substitution of natural gas by renewable gas while maintaining public acceptance for this transformation despite higher costs for end-users.

Gas is considered an important part of the European Union’s (EU) energy mix. Making up a quarter of the energy consumed in the EU, it is widely used by both households and industry. Gas supports the penetration of intermittent renewable electricity and is considered the cleanest of the fossil fuels but its combustion emits a considerable amount of greenhouse gases. In the fight against climate change, the EU has committed itself to the near-complete decarbonisation of the energy sector well before 2050. This will have a significant impact on the gas sector, especially in the EU, which has significant gas transportation and storage assets. This commentary examines two potential pathways that could enable the gas sector to contribute to the EU’s decarbonisation efforts while continuing to play a substantial role in the EU’s energy supply. The pathways include gas and electricity sector coupling and the substantial increase of renewable gas production. Those options, which are not mutually exclusive, provide an opportunity for the gas sector to thrive in a decarbonised energy future. In some cases, it could require changes in the EU’s gas legislation announced by the European Commission to be proposed in 2020.

Copyright of Zeitschrift für Energiewirtschaft is the property of Springer Nature and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

• A thermodynamic model representative of the GoBiGas process has been built. • One 71 MW SNG bio-SNG plant is the most competitive configuration, LCOE = 86.3 €/MWh. • A two-plant system is the most profitable configuration, NPV = 165.8 M€. • For the optimal configuration, the cost of the bio-SNG varies from 59 to 98 €/MWh. • Incentives from 22 to 66 €/MWh are necessary to break-even the investment. This article presents a novel method for the optimal integration of large-scale bio-SNG (biomass-derived synthetic natural gas) production system into the existing natural gas network. A thermodynamic model representative of a commercial bio-SNG process fed by forestry residues has been built and validated with experimental data. The variation of the capital and operational expenditures as functions of the power output is calculated, identifying the economies of scale of the process. A spatially-explicit model, based on a modified location-allocation algorithm, has been built to find the site and size of the plant(s) that minimise the levelised cost of the energy produced (LCOE). The combined effects of the capital, operational and transport costs resulted in an optimal LCOE of 86.3 €/MWh for a single 71 MW SNG plant. On the other hand, the most profitable configuration has been found for a two-plant configuration, which has a net present value of 165.8 M€ and LCOE of 89.5 €/MWh. The resulting optimal configurations are shown in maps, including the resource harvesting sites and the selected bio-SNG and grid injection points. The mean distance from harvesting sites to the one-plant injection point is approximately 95 km, which means transportation costs, while small are not negligible. A scenario analysis shows the impact of the resource cost and incentives for bio-SNG injection, showing that a low cost of the resource (45 €/t DB) would reduce the one-plant LCOE to 59 €/MWh, which is currently above the cost of natural gas for household consumers, 52 €/MWh. [ABSTRACT FROM AUTHOR]

Gas is considered an important part of the European Union's (EU) energy mix. Making up a quarter of the energy consumed in the EU, it is widely used by both households and industry. Gas supports the penetration of intermittent renewable electricity and is considered the cleanest of the fossil fuels but its combustion emits a considerable amount of greenhouse gases. In the fight against climate change, the EU has committed itself to the near-complete decarbonisation of the energy sector well before 2050. This will have a significant impact on the gas sector, especially in the EU, which has significant gas transportation and storage assets. This commentary examines two potential pathways that could enable the gas sector to contribute to the EU's decarbonisation efforts while continuing to play a substantial role in the EU's energy supply. The pathways include gas and electricity sector coupling and the substantial increase of renewable gas production. Those options, which are not mutually exclusive, provide an opportunity for the gas sector to thrive in a decarbonised energy future. In some cases, it could require changes in the EU's gas legislation announced by the European Commission to be proposed in 2020. [ABSTRACT FROM AUTHOR]

Abstract Considering the recent happenings in the energy market of Latvia, future strategies for natural gas market and infrastructure remain unclear. For policy planners and gas market stakeholders it is crucial to deal with this uncertainty and aim for exploitation of existing natural gas infrastructure. In this case a model that allows to explore opportunities for renewable energy applications in natural gas infrastructure and at the same time provides information about security of energy supply can be highly desirable. Therefore, this paper presents a System Dynamics model made for natural gas infrastructure with storage facility in the Latvian context. The model incorporates the specific parts of the Latvia’s natural gas infrastructure (transmission system and storage facility) and their characterizing parameters: natural gas transmission system capacities, storage facility capacities, working regimes, processes performed by transmission system operator for transmission system balancing based on natural gas flows. Model has potential to be used as a tool in energy policy planning processes for evaluation of different RES strategies and natural and technogenic risks of gas supply disruption. For this purpose, model must be upgraded with aspects that show gas market dynamics. [ABSTRACT FROM AUTHOR]

The suitability of existing sources of CO 2 in a region (Ireland) for use in power to gas systems was determined using multi criteria decision analysis. The main sources of CO 2 were from the combustion of fossil fuels, cement production, alcohol production, and wastewater treatment plants. The criteria used to assess the suitability of CO 2 sources were: annual quantity of CO 2 emitted; concentration of CO 2 in the gas; CO 2 source; distance to the electricity network; and distance to the gas network. The most suitable sources of CO 2 were found to be distilleries, and wastewater treatment plants with anaerobic digesters. The most suitable source of CO 2 , a large distillery, could be used to convert 461 GWh/a of electricity into 258 GWh/a of methane. The total electricity requirement of this system is larger than the 348 GWh of renewable electricity dispatched down in Ireland in 2015. This could allow for the conversion of electricity that would be curtailed into a valuable energy vector. The resulting methane could fuel 729 compressed natural gas fuelled buses per annum. Synergies in integrating power to gas at a wastewater treatment plant include use of oxygen in the wastewater treatment process. [ABSTRACT FROM AUTHOR]

Six EU gas grids have a target of 100% substitution of natural gas with renewable gas by 2050. This industry will start with biogas upgraded to biomethane. The biomethane resource and location of waste substrates (such as agricultural slurries, slaughterhouse waste, milk processing waste, and source separated household organic waste) were determined using the most recent spatially explicit data for Ireland. The total biomethane resource was estimated equivalent to: 7.6% of natural gas usage, 7% of energy in transport; 52% of the fuel usage in heavy goods vehicles in 2013. In terms of natural gas usage it corresponded to 26.5% of industrial gas use, and 52% of residential natural gas use. The resource as a source of thermal energy is equivalent to wood chips from 16.5% of arable land under short rotation coppice willow. Thematic maps illustrating the location of each resource were developed to highlight regions of significant biomethane production potential. The regions with the greatest resource of cattle slurry are located in the south and east of the country; sheep manure resources are concentrated on the western seaboard, while the largest biomethane resource from household organic waste is found in urban and city areas (63% of household organic waste biomethane resource). [ABSTRACT FROM AUTHOR]

To address the cost-effective role of the different energy sources and carriers, energy optimization models should ideally consider the key energy supply, carrier, conversion, and storage options in an endogenous way, with high temporal resolution, and accounting for both positive and negative CO 2 emissions. To do this, we develop a model optimizing dispatch and investment, meeting all the above-mentioned conditions, and we apply it to the French energy system for 2050 for a wide range of social cost of carbon (SCC) values (0 to €500/tCO 2). Our findings show that (1) the optimal carbon-neutral energy system is highly electrified (∼80% of the primary energy supply), which implies highly electrified heating and transport sectors. (2) In the presence of renewable gas, a carbon-neutral energy sector can be achieved for a robust SCC of €300/tCO 2. (3) In such a system, renewables provide more than 90% of primary energy. (4) Therefore, renewables are crucial for achieving carbon-neutrality in a cost-effective way, and in the absence of renewable gas, carbon-neutrality cannot be achieved, even for an SCC of €500/tCO 2. Finally, (5) exclusion of nuclear energy from the energy system does not induce significant extra cost or emissions. [Display omitted] • We study the role of renewable gas in the future low-carbon French energy system. • Renewable gas provides at least 20% of the primary energy. • Renewables are the main enablers of carbon-neutrality (>90% of the primary energy). • A high degree of electrification is required in the heat and transport sectors. [ABSTRACT FROM AUTHOR]

Power-to-Gas (PtG) is a technology that has the potential to be a system solution to the fluctuating energy production that arises due to the increasing share of renewable energies. Despite the fact that the technology is mature, it has not penetrated the market, yet. Financial resources are, among others, often blamed for. To investigate the economics behind the first step of PtG, Power-to-Hydrogen (PtH 2 ), we derive a microeconomic partial equilibrium Market model for water ELectrolYsis, MELY, with a temporal horizon up to 2040. The model accounts for multiple electricity markets and various hydrogen usage paths. Each combination of these represents a subsector of the model. Utilising surpluses from renewable energies in order to produce hydrogen for the mobility sector appears to be the most profitable subsector, yielding positive unit profits in 2027. Subsectors consuming electricity from other markets and serving the mobility sector will follow this lead. A one-factor-at-a-time (OFAT) sensitivity analysis reveals that the hydrogen price and parameters influencing the effectiveness of the factor input capital are most sensitive. [ABSTRACT FROM AUTHOR]

Northern countries face a unique challenge in decarbonizing heating demands. This study compares two pathways to reduce carbon emissions from building heating by (1) replacing natural gas heaters with electric heat pumps or (2) replacing natural gas with renewable gas. Optimal annual system cost and capacity requirements for Metro Vancouver, Canada are assessed for each pathway, under nine scenarios. Results show that either pathway can be lower cost but the range of costs is more narrow for the renewable gas pathway. System cost is sensitive to heat demand, with colder temperatures favouring the renewable gas pathway and milder temperatures favouring the electrification pathway. These results highlight the need for a better understanding of heating profiles and associated energy system requirements. • Compares electrification and renewable gas decarbonization pathways for heating. • Hindcasts heat demand profile from electricity consumption and temperature records. • Optimizes energy production and storage across demand, supply, and cost scenarios. • Electrified heating requires 4 to 357 GWh of electric storage. • Renewable gas pathway has lower range of costs across scenarios. [ABSTRACT FROM AUTHOR]

Renewable gas has been proposed as a solution to decarbonise industrial processes, specifically heat demand. As part of this effort, the breast-milk substitutes industry is proposing to use renewable gas as a substitute for fossil natural gas. However, decarbonising the industrial processing of breast-milk substitutes can increase social license for these products, potentially undermining breastfeeding. World Health Organisation nutrition targets aim to increase exclusive breastfeeding to at least 50% globally by 2025 to improve maternal, infant, and young child health and nutrition. This target will have implications for the energy transition. A weakness of existing energy models is that demands for end-use products such as breast-milk substitutes are typically not considered explicitly. This paper develops an analytical framework for explicitly representing infant feeding methods in energy systems models. We compare the emissions saved in Ireland from decarbonising the industrial processing of breast-milk substitutes with renewable gas with the emissions saved by an increase in exclusive breastfeeding to 50% in both Ireland and a key export market, China. We demonstrate that the emissions saved from achieving the minimum global breastfeeding target are greater than when renewable gas is used to displace natural gas in the production of breast-milk substitutes in Ireland. We discuss the decarbonisation of breast-milk substitutes in relation to the principle of justice as non-maleficence, a principle based on the commitment to avoid harm, a novel application of a principle of justice. We conclude that breastfeeding support can be considered a demand-side measure for mitigating climate change by reducing the demand for energy services to produce breast-milk substitutes. A key recommendation is to position breastfeeding support as both a public health and a climate justice issue that is relevant for a just transition. The framework developed for this paper could be applied to support the inclusion of a wider range of mitigation options with social justice outcomes in energy system models. • Breastfeeding and breastfeeding support can contribute to mitigating climate change. • Achieving global nutrition targets will save more emissions than fuel-switching. • Breastfeeding support programmes support a just transition. • This work can support the expansion of mitigation options in energy system models. [ABSTRACT FROM AUTHOR]

Natural gas is an energy carrier of predominant significance for today's electricity and heating sectors. However, science heavily discusses the actual environmental burden of natural gas mainly due to the uncertainty in upstream methane losses during its extraction and transportation. In this context, numerous technologies pave the way for the production of renewable methane to replace natural gas: biomethane from anaerobic digestion of biomass, substitute natural gas (bio-SNG) from gasification and Power-to-Gas via water electrolysis and subsequent methanation. In recent years, numerous studies aimed at analysing the life cycle carbon intensity of those renewable gases. Given the high degree of freedom in the methodology of life cycle assessment (LCA) however, the studies are highly dependent on the respective boundary conditions and assumptions. To summarise and discuss the different findings, this review identifies and quantitatively analyses 30 life cycle assessment studies on the greenhouse gas emissions of renewable gases, comparing their results and deriving the main determinants on their environmental friendliness. A comparison between the results for renewable gases and existing literature reviews on the LCA of fossil natural gas shows the considerable emission reduction potential of renewable gases. This however requires the consideration and right implementation of the main influencing factors (inter alia the storage of digestate in closed tanks for biomethane, heat extraction of excess heat for bio-SNG, or the use of renewable electricity for Power-to-Gas) and is not a mere result of the technologies per se. [Display omitted] • 30 LCA studies on renewable gases are quantitatively reviewed. • Results are compared with literature reviews on LCAs of natural gas. • Main determinants of the CO 2 eq emissions of renewable gases are analysed. • Renewable gases offer considerable greenhouse gas mitigation potential. • CO 2 eq emissions of natural and renewable gas show high variance. [ABSTRACT FROM AUTHOR]

• Quantitative analysis of sector coupling scenarios. • Detailed modelling of integrated power and gas networks. • Quality tracking of distributed hydrogen blends in final users. • Dispatch and hydrogen injection strategies for higher integration of renewable energy. Electricity and gas infrastructure coupling has the twofold effect of solving production-consumption mismatches and decarbonizing the natural gas system through power-to-gas technologies producing hydrogen to be injected within the gas network. However, little is known on how this may impact the gas network operation, especially at a local level. This paper aims to fill this gap by presenting a methodology for modeling the interactions between electricity and gas distribution networks through the implementation of their physical models. A scenario of increasing penetration of distributed photovoltaic production is considered for a sample urban area. Whenever photovoltaic production exceeds the urban area consumption, hydrogen is produced and injected into the gas network. 24 injection scenarios were examined and compared to evaluate their impacts on fluid-dynamics and the quality of gas blends. Results show possible bottlenecks against hydrogen injection caused by the gas network. During summertime operations and in the cases of injection following directly the solar over-production, the hydrogen share peaks 20–30% already in the scenario of 40% solar penetration, generating unacceptable blends. These gas quality perturbations are considerably reduced when hydrogen is injected constantly throughout the day. The choice of the injection node also contributes to perturbation reduction. Sector coupling through hydrogen blending results in a complex interplay between renewable energy excess and local gas network availability which can be enhanced by buffer storage solutions and proper choice of injection node. In the framework of integrated and multi-gas systems, combined simulation tools are necessary to evaluate sector-coupling opportunities case-by-case. [ABSTRACT FROM AUTHOR]