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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.

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.