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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.

The power of incumbent actors to affect sustainability transitions is increasingly recognised as a central issue associated with systemic change. However, incumbent’s approaches and the outcome of their influence is rarely examined in academic literature. Using a novel approach which combines the lens of ‘discourse coalitions’ with an explicitly critical discursive stance, in which the coalition’s storyline is scrutinised, this interdisciplinary analysis investigates a pro-gas, incumbent led coalition present in the Great Britain (GB) energy system. In response to the threat of electrification, the coalition presents decarbonising the gas grid with replacement gases as the optimal route for heat decarbonisation. However, much analysis suggests a significant need for heat electrification and our review highlights major uncertainties with a decarbonised gas pathway. Incumbents are over-selling 'green-gas' to policy makers in order to protect their interests and detract from the importance and value of electrification. Policy and research recommendations are made.

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.

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.

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.

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.

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.

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.

Supported by policy, electric vehicles (EVs) powered by lithium batteries are being commercialised in an increasing number of models and their global stock surpassed two million units in 2016. However, there is uncertainty around the future price and availability of lithium, which has consequences on the feasibility of manufacturing lithium batteries at scale. Reaching the EV penetration levels foreseen by governments implies a substantial growth in lithium demand. In this chapter, we review the evidence around future lithium availability for the manufacturing of EV batteries. We examine the methods used to estimate both lithium demand from EVs and lithium supply from brines and ore. The main variables influencing demand are the future size of the EV market, the average battery capacity and the material intensity of the batteries. Supply projections depend on global reserve and resource estimates, forecast production and recyclability. We find that the assumptions made in the literature on the key variables are characterised by significant uncertainty. However based on the available evidence, it appears that lithium production may be on a lower trajectory than demand and would have to rapidly increase in order not to prove a bottleneck to the expansion of the EV market. More research is needed in order to reduce uncertainty on lithium intensity of future EVs and improve understanding of the potential for lithium production expansion and recycling.

It is increasingly claimed that the world is entering a ‘golden age of gas’, with the exploitation of unconventional resources expected to transform gas markets around the world. But the future development of these resources is subject to multiple uncertainties, particularly with regard to the size and recoverability of the physical resource. This paper assesses the currently available evidence on the size of unconventional gas resources at both the regional and global level. Focussing in particular on shale gas, it first explores the meaning and appropriate interpretation of the various terms and definitions used in resource estimation and then summarises and compares the different regional and global estimates that have been produced to date. It shows how these estimates have increased over time and highlights their variability, the wide range of uncertainty and the inadequate treatment of this uncertainty by most studies. The paper also addresses coal bed methane and tight gas and identifies those estimates that appear to be most robust for each region. The paper concludes that unconventional gas could represent 40% of the remaining technically recoverable resource of natural gas, but the level of uncertainty is extremely high and the economically recoverable resource could be substantially smaller.

The routine availability of key component materials has been highlighted as a potential constraint to both extensive deployment and reduction in production costs of thin-film photovoltaic (PV) technologies. This paper examines the effect of material availability on the maximum potential growth of thin-film PV by 2050 using the case of tellurium (Te) in cadmium telluride (CdTe) PV, currently the dominating thin-film technology with the lowest manufacturing cost. The use of system dynamics (SD) modelling allows for a dynamic treatment of key Te supply features and prospects for reductions in PV demand via material efficiency improvements, as well as greater transparency and a better understanding of future recycling potential. The model's projections for maximum Te-constrained CdTe PV growth by 2050 are shown to be higher than a number of previous studies using static assumptions—suggesting that a dynamic treatment of the resource constraints for CdTe inherently improves the outlook for future deployment of this technology. In addition, the sensitivity analysis highlights certain complex correlations between the maximum potential CdTe growth by 2050 and the rated lifetime of PV modules as well as the reported size of global Te resources. The highest observed sensitivities are to the recovery rate of Te from copper anode slimes, the active layer thickness, the module efficiency and the utilisation rate of Te during manufacturing, all of which are highlighted as topics for further research. Copyright © 2013 John Wiley & Sons, Ltd.

This review paper summarises and evaluates the evidence regarding four issues that are considered to be of critical importance for future global oil supply. These are: a) how regional and global oil resources are distributed between different sizes of field; b) why estimates of the recoverable resources from individual fields tend to grow over time and the current and likely future contribution of this to global reserve additions; c) how rapidly the production from different categories of field is declining and how this may be expected to change in the future; and d) how rapidly the remaining recoverable resources in a field or region can be produced. It is shown that, despite serious data limitations, the level of knowledge of each of these issues has improved considerably over the past decade. While the evidence on reserve growth appears relatively encouraging for future global oil supply, that on decline and depletion rates does not. Projections of future global oil supply that use assumptions inconsistent with this evidence base are likely to be in error.

Decarbonisation goals have triggered photovoltaic (PV) sector expansion and cost reductions in PV technologies. Thin film (TF) PV technologies are currently the cheapest to manufacture and offer the possibility of attaining lower costs. However, scarcity of key component materials has been highlighted as a potential barrier to both large scale deployment and reductions in technology cost. This paper explores this claim for cadmium telluride (CdTe) and copper indium gallium (di)selenide (CIGS) TF technologies and their potentially constraining materials, tellurium and indium. It reviews key literature, highlighting the high uncertainty in the estimates of the resource constrained TF PV potential as well as in data and methodologies used to assess future availability of the targeted materials. The reviewed evidence does not support the contention that the availability of tellurium and indium will necessarily constrain CdTe and CIGS technologies respectively in their ability to supply expected future PV market growth. However, future escalation in indium and tellurium price resulting from demand–supply imbalances could have a negative impact on CdTe and CIGS cost reduction ambitions. Factors influencing indium and tellurium price and their relative contribution to TF PV module production cost need further investigation.

Within the polarised and contentious debate over future oil supply a growing number of commentators are forecasting a near term peak and subsequent decline in production. But although liquid fuels form the foundation of modern industrial economies, the growing debate on `peak oil has relatively little influence on energy and climate policy. With this in mind, the UK Energy Research Centre (UKERC) has conducted an independent, thorough and systematic review of the evidence, with the aim of establishing the current state of knowledge, identifying key uncertainties and improving consensus. The study focuses upon the physical depletion of conventional oil in the period to 2030 and includes an in-depth literature review, analysis of industry databases and a detailed comparison of global supply forecasts. This Communication summarises the main findings of the UKERC study. A key conclusion is that a peak of conventional oil production before 2030 appears likely and there is a significant risk of a peak before 2020.

This paper compares and evaluates fourteen contemporary forecasts of global supply of conventional oil and provides some observations on their relative plausibility. Despite the wide range of modelling approaches used and multiplicity of assumptions made, it is shown that forecasts can be usefully compared along two dimensions, namely: shape of future production profile and assumed or implied ultimately recoverable resource of conventional oil. Other differences between forecasts are either secondary or are components of these two parameters. The paper shows how large differences in the assumed size of the resource make relatively little difference to the timing of a global peak in conventional oil production. It also examines the impact of rates of discovery, reserves growth and depletion on the forecast date of peak and shows how forecasts that delay this peak until beyond 2030 rest on assumptions that are at best optimistic and at worst implausible.

A growing number of commentators are forecasting a near-term peak and subsequent terminal decline in the global production of conventional oil as a result of the physical depletion of the resource. These forecasts frequently rely on the estimates of the ultimately recoverable resources (URR) of different regions, obtained through the use of curve-fitting to historical trends in discovery or production. Curve-fitting was originally pioneered by M. King Hubbert in the context of an earlier debate about the future of the US oil production. However, despite their widespread use, curve-fitting techniques remain the subject of considerable controversy. This article classifies and explains these techniques and identifies both their relative suitability in different circumstances and the level of confidence that may be placed in their results. This article discusses the interpretation and importance of the URR estimates, indicates the relationship between curve fitting and other methods of estimating the URR and classifies the techniques into three groups. It then investigates each group in turn, indicating their historical origins, contemporary application and major strengths and weaknesses. The article then uses illustrative data from a number of oil-producing regions to assess whether these techniques produce consistent results as well as highlight some of the statistical issues raised and suggesting how they may be addressed. The article concludes that the applicability of curve-fitting techniques is more limited than adherents claim and that the confidence bounds on the results are wider than usually assumed.

There is growing concern about the depletion of hydrocarbon resources and the risk of near-term peaks in production. These concerns hinge upon contested estimates of the recoverable resources of different regions and the associated forecasts of regional production. Beginning with Hubbert, an influential group of analysts have used growth curves both to estimate recoverable resources and to forecast future production. Despite widespread use, these ‘curve-fitting’ techniques remain a focus of misunderstanding and dispute. The aim of this paper is to classify and explain these techniques and to identify both their relative suitability in different circumstances and the expected level of confidence in their results. The paper develops a mathematical framework that maps curve-fitting techniques onto the available data for conventional oil and highlights the critical importance of the so-called ‘reserve growth’. It then summarizes the historical origins, contemporary application and strengths and weaknesses of each group of curve-fitting techniques and uses illustrative data from a number of oil-producing regions to explore the extent to which these techniques provide consistent estimates of recoverable resources. The paper argues that the applicability of curve-fitting techniques is more limited than adherents claim, the confidence bounds on the results are wider than commonly assumed and the techniques have a tendency to underestimate recoverable resources.

Interpreting reserves: moving from reserves to URR. Given the conservative nature of reserve estimates, the resulting reserve growth over time, and other associated issues, the ultimately recoverable resource (URR) is a more useful resource classification when assessing future petroleum resource availability. This abstract describes some of the findings of a systematic review of the evidence surrounding resource and reserve estimates for both conventional oil and unconventional gas. This review includes discussion of the methodological approaches that can be used, the difficulties associated with these methodologies and the particular issues associated with estimating unconventional resources. It finds that the most robust estimates are likely to arise from a combination of methodological approaches.

Energy policies are strongly influenced by resource availability and recoverability estimates. Yet these estimates are often highly uncertain, frequently incommensurable, and regularly contested. This paper explores how the uncertainties surrounding estimates of the availability of fossil fuels, biomass and critical metals are conceptualised and communicated. The contention is that a better understanding of the uncertainties surrounding resource estimates for both conventional and renewable energy resources can contribute to more effective policy decision making in the long term. Two complementary approaches for framing uncertainty are considered in detail: a descriptive typology of uncertainties and a framework that conceptualises uncertainty as alternative states of incomplete knowledge. Both have the potential to be useful analytical and communication tools. For the three resource types considered here we find that data limitations, inconsistent definitions and the use of incommensurable methodologies present a pervasive problem that impedes comparison. Many aspects of resource uncertainty are also not commonly captured in the conventional resource classification schemes. This highlights the need for considerable care when developing and comparing aggregate resource estimates and when using these to inform strategic energy policy decisions.

Estimates of technically recoverable shale gas resources remain highly uncertain, even in regions with a relatively long history of shale gas production. This paper examines the reasons for these uncertainties, focussing in particular on the methods used to derive resource estimates. Such estimates can be based upon the extrapolation of previous production experience in developed areas, or from the geological appraisal of undeveloped areas. The paper assesses the strengths and weaknesses of these methods, the level of uncertainty in the results and the implications of this for current policy debates. We conclude that there are substantial difficulties in assessing the recoverable volumes of shale gas and that current resource estimates should be treated with considerable caution. Most existing studies lack transparency or a rigorous approach to assessing uncertainty and provide estimates that are highly sensitive to key variables that are poorly defined - such as the assumed ratio of gas-in-place to recovered gas (the ‘recovery factor’) and the assumed ultimate recovery from individual wells. To illustrate the uncertainties both within and between different methodological approaches, we provide case studies of resource estimates for the Marcellus shale in the US and three basins in India. 2013 Published by Elsevier Ltd.