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Natural gas has developed as a prominent energy source across the world over the last century. However, its use in the future will be constrained by evolving climate goals, and an optimal role for natural gas in a future 1.5 °C world is debated. We conduct a systematic review of the literature, and analysis of the Intergovernmental Panel on Climate Change SR1.5 scenarios to understand the role of natural gas in a 1.5 °C world. We also examine key factors that influence the use of gas such as Carbon Capture and Storage and Negative Emissions Technologies. We find that global gas use decreases more considerably under a 1.5 °C target than 2 °C with half of the 1.5 °C scenarios reducing gas use by at least ∼35% by 2050 and ∼70% by 2100 against 2019 consumption. We find there is no correlation between the level of Negative Emissions Technologies and the permitted gas use in Intergovernmental Panel on Climate Change scenarios, while there is a strong correlation between gas use and the deployment of Carbon Capture and Storage. Regionally, there are considerable ranges in gas use, with the Organisation for Economic Cooperation and Development & European Union seeing the greatest decrease in use and Asia increasing use until 2050. Notwithstanding this uncertainty, global natural gas use is likely to decrease in the coming decades in response to climate goals.

Achieving net-zero greenhouse gas emissions by 2050 requires a step-change in resource management, and the utilisation of organic waste is currently an untapped opportunity in Latin America. This study carries out a quantitative and qualitative assessment of organic waste-to-energy potentials for the Chilean context. First, it produces a comprehensive quantification of organic waste, including annual crop residues, horticulture residues, livestock manure and OFMSW by region; then it estimates the energy potential of these bioresources; and finally, it conducts a series of stakeholder interviews determining barriers to greater waste-to-energy utilisation. The results show that the total bioenergy potential from waste is estimated at 78 PJ/yr (3.3% of annual energy demand), being livestock manure (41%) and annual crop residues (28%) the main sources, arising mostly from three regions. The stakeholder elicitation concluded that financial, technical, and institutional barriers prevent waste utilisation, highlighting the needs to address elevated investment costs and high reliance on landfilling practices, which together with public policies could enable the full exploitation of these resources to ensure energy security and resource efficiency. This research was supported by the Sustainable Gas Institute at Imperial College London and by Universidad de Santiago de Chile through the DICYT (Dirección de Investigación Científica y Tecnológica) grant 021812GL. X. Schmidt Rivera is supported by the Institutional QR Global Challenges Research Fund. F. Jalil-Vega acknowledges the support of ANID through Complex Engineering Systems Institute PIA/BASAL AFB180003, and through ANID/FONDAP/15110019 SERC-Chile.

Replacing fossil fuels with energy sources and carriers that are sustainable, environmentally benign, and affordable is amongst the most pressing challenges for future socio-economic development. To that goal, hydrogen is presumed to be the most promising energy carrier. Electrocatalytic water splitting, if driven by green electricity, would provide hydrogen with minimal CO2 footprint. The viability of water electrolysis still hinges on the availability of durable earth-abundant electrocatalyst materials and the overall process efficiency. This review spans from the fundamentals of electrocatalytically initiated water splitting to the very latest scientific findings from university and institutional research, also covering specifications and special features of the current industrial processes and those processes currently being tested in large-scale applications. Recently developed strategies are described for the optimisation and discovery of active and durable materials for electrodes that ever-increasingly harness first-principles calculations and machine learning. In addition, a technoeconomic analysis of water electrolysis is included that allows an assessment of the extent to which a large-scale implementation of water splitting can help to combat climate change. This review article is intended to cross-pollinate and strengthen efforts from fundamental understanding to technical implementation and to improve the ‘junctions’ between the field's physical chemists, materials scientists and engineers, as well as stimulate much-needed exchange among these groups on challenges encountered in the different domains.

Published online 19 September 2022 Methane is potent greenhouse gas (GHG) accounting for 11% of all EU emissions, but in contrast to CO2 it has received relatively little attention. Although methane is regulated under the EU Effort Sharing framework, this policy lacks methane-specific regulations or targets, leaving the Member States considerable discretion over whether to prioritize methane reduction or not. The European Commission presented a proposal for EU methane regulation on 15 December 2021. However, our understanding of how to design measurement, reporting and verification (MRV) regulation for methane is limited. MRV involves many stakeholders at different steps in the process (policymakers, industry, civil society, MRV service providers, etc.), whose perspectives may differ, and our study aims to gain an insight into what constitutes an effective MRV by garnering the different stakeholders’ perspectives. The study reveals that: (1) the limits of voluntary MRV initiatives justify regulatory intervention, (2) the major barrier to the implementation of methane-specific MRV is not economic, but relates to an incomplete understanding of methane sources and available measurement technologies, (3) verification is likely to be the most challenging MRV element to implement, partly due to the limited number of accredited verifiers and overlapping tasks (4) MRV needs to be accompanied by methane mitigation policies incentivising continuous improvement of companies’ performance. The study recommends enhancing the proposed regulation by: introducing equal requirements for operated and non-operated assets; an obligation to report measurement uncertainties; a closer integration of MRV and LDAR; clear verification rules; and an introduction of minimum and optimum methane control standards.

Greenhouse gases (GHGs) produced by the extraction of natural gas are an important contributor to lifecycle emissions and account for a significant fraction of anthropogenic methane emissions in the USA. The timing as well as the magnitude of these emissions matters, as the short term climate warming impact of methane is up to 120 times that of CO2. This study uses estimates of CO2 and methane emissions associated with different upstream operations to build a deterministic model of GHG emissions from conventional and unconventional gas fields as a function of time. By combining these emissions with a dynamic, techno-economic model of gas supply we assess their potential impact on the value of different types of project and identify stranded resources in various carbon price scenarios. We focus in particular on the effects of different emission metrics for methane, using the global warming potential (GWP) and the global temperature potential (GTP), with both fixed 20-year and 100-year CO2-equivalent values and in a time-dependent way based on a target year for climate stabilisation. We report a strong time dependence of emissions over the lifecycle of a typical field, and find that bringing forward the stabilisation year dramatically increases the importance of the methane contribution to these emissions. Using a commercial database of the remaining reserves of individual projects, we use our model to quantify future emissions resulting from the extraction of current US non-associated reserves. A carbon price of at least 400 USD/tonne CO2 is effective in reducing cumulative GHGs by 30–60%, indicating that decarbonising the upstream component of the natural gas supply chain is achievable using carbon prices similar to those needed to decarbonise the energy system as a whole. Surprisingly, for large carbon prices, the choice of emission metric does not have a significant impact on cumulative emissions.

Different technologies produce hydrogen with varying cost and carbon footprints over the entire resource supply chain and manufacturing steps. This paper examines the relative costs of carbon mitigation from a life cycle perspective for 12 different hydrogen production techniques using fossil fuels, nuclear energy and renewable sources by technology substitution. Production costs and life cycle emissions are parameterized and re-estimated from currently available assessments to produce robust ranges to describe uncertainties for each technology. Hydrogen production routes are then compared using a combination of metrics, levelized cost of carbon mitigation and the proportional decarbonization benchmarked against steam methane reforming, to provide a clearer picture of the relative merits of various hydrogen production pathways, the limitations of technologies and the research challenges that need to be addressed for cost-effective decarbonization pathways. The results show that there is a trade-off between the cost of mitigation and the proportion of decarbonization achieved. The most cost-effective methods of decarbonization still utilize fossil feedstocks due to their low cost of extraction and processing, but only offer moderate decarbonisation levels due to previous underestimations of supply chain emissions contributions. Methane pyrolysis may be the most cost-effective short-term abatement solution, but its emissions reduction performance is heavily dependent on managing supply chain emissions whilst cost effectiveness is governed by the price of solid carbon. Renewable electrolytic routes offer significantly higher emissions reductions, but production routes are more complex than those that utilise naturally-occurring energy-dense fuels and hydrogen costs are high at modest renewable energy capacity factors. Nuclear routes are highly cost-effective mitigation options, but could suffer from regionally varied perceptions of safety and concerns regarding proliferation and the available data lacks depth and transparency. Better-performing fossil-based hydrogen production technologies with lower decarbonization fractions will be required to minimise the total cost of decarbonization but may not be commensurate with ambitious climate targets.

Summary Coal is at a crossroads, with divestment and phase-out in the West countered by the surging growth throughout Asia. Global energy scenarios suggest that coal consumption could halve over the next decade, but the business and geopolitical implications of this profound shift remain underexplored. We investigate coal markets to 2040 using a perfect competition techno-economic model. In a well-below-2°C scenario, Europe, North America, and Australia suffer from over-capacity, with one-third of today’s mines becoming stranded assets. New mines are needed to offset retirements, but a new commodity cycle in the 2030s can be avoided. Coal prices decline as only the most competitive mines survive, and trade volumes fall to give more insular national markets. Regions stand to gain or lose tens of billions of dollars per year from reducing import bills or export revenues. Understanding and preparing for these changes could ease the transition away from coal following 150 years of dominance.

Projections of decarbonisation pathways have typically involved reducing dependence on natural gas grids via greater electrification of heat using heat pumps or even electric heaters. However, many technical, economic and consumer barriers to electrification of heat persist. The gas network holds value in relation to flexibility of operation, requiring simpler control and enabling less expensive storage. There may be value in retaining and repurposing gas infrastructure where there are feasible routes to decarbonisation. This study quantifies and analyses the decarbonisation potential associated with the conversion of gas grids to deliver hydrogen, focusing on supply chains. Routes to produce hydrogen for gas grids are categorised as: reforming natural gas with (or without) carbon capture and storage (CCS); gasification of coal with (or without) CCS; gasification of biomass with (or without) CCS; electrolysis using low carbon electricity. The overall range of greenhouse gas emissions across routes is extremely large, from − 371 to 642 gCO 2 eq/kW h H2 . Therefore, when including supply chain emissions, hydrogen can have a range of carbon intensities and cannot be assumed to be low carbon. Emissions estimates for natural gas reforming with CCS lie in the range of 23–150 g/kW h H2 , with CCS typically reducing CO 2 emissions by 75%. Hydrogen from electrolysis ranges from 24 to 178 gCO 2 eq/kW h H2 for renewable electricity sources, where wind electricity results in the lowest CO 2 emissions. Solar PV electricity typically exhibits higher emissions and varies significantly by geographical region. The emissions from upstream supply chains is a major contributor to total emissions and varies considerably across different routes to hydrogen. Biomass gasification is characterised by very large negative emissions in the supply chain and very large positive emissions in the gasification process. Therefore, improvements in total emissions are large if even small improvements to gasification emissions can be made, either through process efficiency or CCS capture rate.

Methane emitted from natural gas supply chains are a major source of greenhouse gas emissions, but there is uncertainty on the magnitude of emissions, how they vary, and which key factors influence emissions. This study estimates the variation in emissions across the major natural gas supply chains, alongside an estimate of uncertainty which helps identify the areas at the greatest emissions ‘risk’. Based on the data, we estimate that 26.4 Mt CH4 (14.5–48.2 Mt CH4) was emitted by these supply chains in 2017. The risk assessment identified a significant proportion of countries to be at high risk of high emissions. However, there is a large dependency on Tier 1 emission factors, inferring a high degree of uncertainty and a risk of inaccurate emission accounting. When emissions are recalculated omitting Tier 1 data, emissions reduce by 47% to 3.8-fold, downstream and upstream respectively, across regions. More efforts in collecting robust and transparent primary data should be made, particularly in Non-Annex 1 countries, to improve our understanding of methane emissions.

International shipping faces strong challenges with new legally binding air quality regulations and a 50% decarbonisation target by 2050. Liquefied natural gas (LNG) is a widely used alternative to liquid fossil fuels, but methane emissions reduce its overall climate benefit. This study utilises new emissions measurements and supply-chain data to conduct a comprehensive environmental life cycle and cost assessment of LNG as a shipping fuel, compared to heavy fuel oil (HFO), marine diesel oil (MDO), methanol and prospective renewable fuels (hydrogen, ammonia, biogas and biomethanol). LNG gives improved air quality impacts, reduced fuel costs and moderate climate benefits compared to liquid fossil fuels, but with large variation across different LNG engine types. Methane slip from some engines is unacceptably high, whereas the best performing LNG engine offers up to 28% reduction in global warming potential when combined with the best-case LNG supply chain. Total methane emissions must be reduced to 0.8–1.6% to ensure climate benefit is realised across all timescales compared to current liquid fuels. However, it is no longer acceptable to merely match incumbent fuels; progress must be made towards decarbonisation targets. With methane emissions reduced to 0.5% of throughput, energy efficiency must increase 35% to meet a 50% decarbonisation target.

The displacement of diesel in the road freight sector by natural gas could cut the sector’s environmental impacts but methane emissions risk eliminating this benefit. A life cycle assessment has been performed to compare natural gas fuelled trucks to diesel, biodiesel, dimethyl ether and electric (UK grid mix), on impacts to climate change, air quality and resource depletion. LNG drivetrains exhibit climate change impacts lower than diesel (17-21%) and similar to electric drivetrains, but CH4 emissions will negate any benefits if they exceed 3.5% of throughput for typical fuel consumption. However, this is much higher than measured slip from current natural gas trucks. Biodiesel exhibits the lowest GHG emissions but for compressed natural gas, only at lowest fuel consumption and negligible methane emissions does this option reach climate parity with diesel. For the other indicators, natural gas exhibits lower impacts (11-66%) than diesel and is the best performer for all the indicators while electric and biodiesel are the worst.

Natural gas is typically considered to be the cleaner-burning fossil fuel that could play an important role within a restricted carbon budget. While natural gas emits less CO2 when burned than other fossil fuels, its main constituent is methane, which has a much stronger climate forcing impact than CO2 in the short term. Estimates of methane emissions in the natural gas supply chain have been the subject of much controversy, due to uncertainties associated with estimation methods, data quality, and assumptions used. This Perspective presents a comprehensive compilation of estimated CO2 and methane emissions across the global natural gas supply chain, with the aim of providing a balanced insight for academia, industry, and policy makers by summarizing the reported data, locating the areas of major uncertainty, and identifying where further work is needed to reduce or remove this uncertainty. Overall, the range of documented estimates of methane emissions across the supply chain is vast among an aggregation of different geological formations, technologies, plant age, gas composition, and regional regulation, not to mention differences in estimation methods. Estimates of combined methane and CO2 emissions ranged from 2 to 42 g CO2 eq/MJ HHV, while methane-only emissions ranged from 0.2% to 10% of produced methane. The methane emissions at the extraction stage are the most contentious issue, with limited data available but potentially large impacts associated with well completions for unconventional gas, liquids unloading, and also the transmission stage. From the range of literature estimates, a constrained range of emissions was estimated that reflects the most recent and reliable estimates: total supply chain GHG emissions were estimated to be between 3.6 and 42.4 g CO2 eq/MJ HHV, with a central estimate of 10.5. The presence of “super emitters”, a small number of facilities or equipment that cause extremely high emissions, is found across all supply chain stages creating a highly skewed emissions distribution. However, various new technologies, mitigation and maintenance approaches, and legislation are driving significant reductions in methane leakage across the natural gas supply chain.

Natural gas is a transport fuel which helps reduce greenhouse gas emissions in shipping and trucks. However, there is some disagreement regarding the potential for natural gas to provide significant improvements relative to current ships and trucks. In 2015, road freight represented ~7% of global energy related CO2 emissions, with shipping representing ~2.6% of emissions. Emissions are also expected to grow, with estimates suggesting road freight emission growing by a third, and shipping emissions growing by 50% to 250% from 2012 to 2050, making absolute emissions reductions challenging. Reducing emissions in ships and trucks has proved technically difficult given the relatively long distances that ships and trucks travel. This paper documents a systematic review of literature detailing well-to-wheel/wake greenhouse gas emissions and economic costs in moving from diesel and heavy fuel oil to natural gas as a fuel for trucks and ships. The review found a number of important issues for greenhouse gas reduction. First, moderate greenhouse gas reductions of 10% were found when switching to natural gas from heavy fuel oil in shipping when comparing the lowest estimates. Comparing lowest well-to-wheel greenhouse gas emissions estimates for trucks, the benefit of switching to natural gas fuel is approximately a 16% reduction in greenhouse gas emissions. However, these emissions are highly variable, driven particularly by methane emissions in exhaust gas. Given this, in the worst cases natural gas ships and trucks emit more greenhouse gasses than the diesel trucks and heavy fuel oil ships that they would replace. It appears relatively cost effective to switch to natural gas as a transport fuel in ships and trucks. However, the limited emissions reduction potential raises questions for the ongoing role of natural gas to reduce greenhouse gas emissions in line with the challenging greenhouse gas reduction targets emerging in the transport sector.

Using natural gas as a fuel in the road freight sector instead of diesel could cut greenhouse gas and air quality emissions but the switch alone is not enough to meet UK climate targets. A life cycle assessment (LCA) has been conducted comparing natural gas trucks to diesel, biodiesel, dimethyl ether and electric trucks on impacts to climate change, land use change, air quality, human health and resource depletion. This is the first LCA to consider a full suite of environmental impacts and is the first study to estimate what impact natural gas could have on reducing emissions form the UK freight sector. If LNG is used, climate change impacts could be up to 33% lower per km and up to 12% lower per kWh engine output. However, methane emissions will eliminate any benefits if they exceed 1.5–3.5% of throughput for typical fuel consumption. For non-climate impacts, natural gas exhibits lower emissions (11–66%) than diesel for all indicators. Thus, for natural gas climate benefits are modest. However, emissions of CO, methane and particulate matter are over air quality limits set for UK trucks. Of the other options, electric and biodiesel trucks perform best in climate change, but are the worst with respect to land use change (which could have significant impacts on overall climate change benefits), air quality, human toxicity and metals depletion indicators. Natural gas could help reduce the sector's emissions but deeper decarbonization options are required to meet 2030 climate targets, thus the window for beneficial utilisation is short.

International shipping provides 80–90% of global trade, but strict environmental regulations around NOX, SOX and greenhouse gas (GHG) emissions are set to cause major technological shifts. The pathway to achieving the international target of 50% GHG reduction by 2050 is unclear, but numerous promising options exist. This study provides a holistic assessment of these options and their combined potential to decarbonise international shipping, from a technology, environmental and policy perspective. Liquefied natural gas (LNG) is reaching mainstream and provides 20–30% CO2 reductions whilst minimising SOX and other emissions. Costs are favourable, but GHG benefits are reduced by methane slip, which varies across engine types. Biofuels, hydrogen, nuclear and carbon capture and storage (CCS) could all decarbonise much further, but each faces significant barriers around their economics, resource potentials and public acceptability. Regarding efficiency measures, considerable fuel and GHG savings could be attained by slow-steaming, ship design changes and utilising renewable resources. There is clearly no single route and a multifaceted response is required for deep decarbonisation. The scale of this challenge is explored by estimating the combined decarbonisation potential of multiple options. Achieving 50% decarbonisation with LNG or electric propulsion would likely require 4 or more complementary efficiency measures to be applied simultaneously. Broadly, larger GHG reductions require stronger policy and may differentiate between short- and long-term approaches. With LNG being economically feasible and offering moderate environmental benefits, this may have short-term promise with minor policy intervention. Longer term, deeper decarbonisation will require strong financial incentives. Lowest-cost policy options should be fuel- or technology-agnostic, internationally applied and will require action now to ensure targets are met by 2050.

Methane is a more potent greenhouse gas (GHG) than CO2, but it has a shorter atmospheric lifespan, thus its relative climate impact reduces significantly over time. Different GHGs are often conflated into a single metric to compare technologies and supply chains, such as the global warming potential (GWP). However, the use of GWP is criticised, regarding: (1) the need to select a timeframe; (2) its physical basis on radiative forcing; and (3) the fact that it measures the average forcing of a pulse over time rather than a sustained emission at a specific end-point in time. Many alternative metrics have been proposed which tackle different aspects of these limitations and this paper assesses them by their key attributes and limitations, with respect to methane emissions. A case study application of various metrics is produced and recommendations are made for the use of climate metrics for different categories of applications. Across metrics, CO2 equivalences for methane range from 4-199 gCO2eq./gCH4, although most estimates fall between 20 and 80 gCO2eq./gCH4. Therefore the selection of metric and time horizon for technology evaluations is likely to change the rank order of preference, as demonstrated herein with the use of natural gas as a shipping fuel versus alternatives. It is not advisable or conservative to use only a short time horizon, e.g. 20 years, which disregards the long-term impacts of CO2 emissions and is thus detrimental to achieving eventual climate stabilisation. Recommendations are made for the use of metrics in 3 categories of applications. Short-term emissions estimates of facilities or regions should be transparent and use a single metric and include the separated contribution from each GHG. Multi-year technology assessments should use both short and long term static metrics (e.g. GWP) to test robustness of results. Longer term energy assessments or decarbonisation pathways must use both short and long-term metrics and where this has a large impact on results, climate models should be incorporated. Dynamic metrics offer insight into the timing of emissions, but may be of only marginal benefit given uncertainties in methodological assumptions.

There is an ongoing debate over future decarbonisation of gas networks using biomethane, and increasingly hydrogen, in gas network infrastructure. Some emerging research presents gas network decarbonisation options as a tractable alternative to ‘all-electric’ scenarios that use electric appliances to deliver the traditional gas services such as heating and cooking. However, there is some uncertainty as to the technical feasibility, cost and carbon emissions of gas network decarbonisation options. In response to this debate the Sustainable Gas Institute at Imperial College London has conducted a rigorous systematic review of the evidence surrounding gas network decarbonisation options. The study focuses on the technologies used to generate biomethane and hydrogen, and examines the technical potentials, economic costs and emissions associated with the full supply chains involved. The following summarises the main findings of this research. The report concludes that there are a number of options that could significantly decarbonise the gas network, and doing so would provide energy system flexibility utilising existing assets. However, these options will be more expensive than the existing gas system, and the GHG intensity of these options may vary significantly. In addition, more research is required, particularly in relation to the capabilities of existing pipework to transport hydrogen safely.

Hydrogen technologies have experienced cycles of excessive expectations followed by disillusion. Nonetheless, a growing body of evidence suggests these technologies form an attractive option for the deep decarb onisation of global energy systems, and that recent improvements in their cost and performance point towards economic viability as well. This paper is a comprehensive review of the potential role that hydrogen could play in the provision of electricity, h eat, industry, transport and energy storage in a low - carbon energy system, and an assessment of the status of hydrogen in being able to fulfil that potential. The picture that emerges is one of qualified promise: hydrogen is well established in certain nic hes such as forklift trucks, while mainstream applications are now forthcoming. Hydrogen vehicles are available commercially in several countries, and 225,000 fuel cell home heating systems have been sold. This represents a step change from the situation of only five years ago. This review shows that challenges around cost and performance remain, and considerable improvements are still required for hydrogen to become truly competitive. But such competitiveness in the medium - term future no longer seems an unrealistic prospect, which fully justifies the growing interest and policy support for these technologies around the world.

A rapid increase in household solar PV uptake has caused concerns regarding intermittent exports of electricity to the grid and related balancing problems. A microgeneration system combining solar PV, combined heat and power plant (CHP) and battery storage could potentially mitigate these problems whilst improving household energy self-sufficiency. This research examines if this could also lead to lower environmental impacts compared to conventional supply of electricity and heat. Life cycle assessment has been carried out for these purposes simulating daily and seasonal energy demand of different household types. The results suggest that the impacts are reduced by 35–100% compared to electricity from the grid and heat from gas boilers. The exception is depletion of elements which is 42 times higher owing to the antimony used for battery manufacture. There is a large variation in impacts with household energy demand, with higher consumption resulting in a far greater reduction in impacts compared to the conventional supply. CHP inefficiency caused by user maloperation can decrease the environmental benefits of the system significantly; for example, the global warming potential increases by 17%. This highlights the need for consumer information and training to ensure maximum environmental benefits of microgeneration. Appropriate battery sizing is essential with the 10–20 kWh batteries providing greatest environmental benefits. However, any reduction in impacts from battery storage is heavily dependent on the assumptions for system credits for electricity export to the grid. Effective management of the battery operation is also required to maximise the battery lifetime: a reduction from 10 to five years increases depletion of elements by 45% and acidification by 32%. Increasing the recycling of metals from 0% to 100% reduces the impacts from 46% to 179%. If 90% of antimony is recycled, the depletion of elements is reduced by three times compared to the use of virgin antimony. However, this impact is still 12 times higher than for the conventional system owing to the use of other metals in the system.

Methane and CO2 emissions from the natural gas supply chain have been shown to vary widely but there is little understanding about the distribution of emissions across supply chain routes, processes, regions and operational practises. This study defines the distribution of total methane and CO2 emissions from the natural gas supply chain, identifying the contribution from each stage and quantifying the effect of key parameters on emissions. The study uses recent high-resolution emissions measurements with estimates of parameter distributions to build a probabilistic emissions model for a variety of technological supply chain scenarios. The distribution of emissions resembles a log-log-logistic distribution for most supply chain scenarios, indicating an extremely heavy tailed skew: median estimates which represent typical facilities are modest at 18–24 g CO2 eq./MJ HHV, but mean estimates which account for the heavy tail are 22–107 g CO2 eq./MJ HHV. To place these values into context, emissions associated with natural gas combustion (e.g. for heat) are approximately 55 g CO2/MJ HHV. Thus, some supply chain scenarios are major contributors to total greenhouse gas emissions from natural gas. For methane-only emissions, median estimates are 0.8–2.2% of total methane production, with mean emissions of 1.6–5.5%. The heavy tail distribution is the signature of the disproportionately large emitting equipment known as super-emitters, which appear at all stages of the supply chain. The study analyses the impact of different technological options and identifies a set of best technological option (BTO) scenarios. This suggests that emissions-minimising technology can reduce supply chain emissions significantly, with this study estimating median emissions of 0.9% of production. However, even with the emissions-minimising technologies, evidence suggests that the influence of the super-emitters remains. Therefore, emissions-minimising technology is only part of the solution: reducing the impact of super emitters requires more effective detection and rectification, as well as pre-emptive maintenance processes.

Microgeneration technologies such as solar photovoltaics, solar thermal, wind and heat pumps may be able to contribute to meeting UK climate change and energy security targets, but their contribution to UK domestic energy supply remains low. This research uses a best-worst scaling survey of microgeneration adopters, considerers and rejecters (n=291) to determine the relative importance of different motivations and barriers in microgeneration (non) adoption decisions. The most important motivations are earning money from installation, increasing household energy independence and protecting against future high energy costs. Results indicate that the introduction of Feed-in Tariffs has clearly encouraged a new, more financially-motivated, group to install. Financial factors are the most important barriers and of most importance to rejecters is the prospect of losing money if they moved home. The Green Deal was introduced to reduce this barrier, but may instead exacerbate the problem as potential homebuyers are put off purchasing a home with an attached Green Deal debt. The difficulty in finding trustworthy information on microgeneration is also a major obstacle to adoption, particularly for considerers, despite efforts by the government and microgeneration interest groups to reduce this barrier. Self-sufficiency in energy is a more important motivation for those considering or having rejected installation than for adopters. Provision of accessible information and greater emphasis on household self-sufficiency in energy could help improve the uptake.

Despite significant financial support from the UK government to stimulate adoption of microgeneration energy technologies, consumer uptake remains low. This paper analyses current understanding of motivations and barriers that affect microgeneration adoption with the aim of identifying opportunities for improving the uptake. The findings indicate that, although feed-in tariffs have increased the uptake, policies do not sufficiently address the most significant barrier – capital costs. ‘Environmental benefit’ appears to be a significant motivation to install, but there is doubt whether consumers are willing to pay extra for that. The issue is complicated by the fact that motivations and barriers differ between segments of the population, particularly with age. Younger age groups are more willing to consider installing but less frequently reach the point of installation, suggesting that other barriers such as costs prevent them from installing. Further investigation into these factors is required to understand how uptake may be increased.