The future of biogas and biomethane cannot be considered separately from the broader context of the global energy system. There is a huge range of possible futures for global energy, depending on the pace of technological innovation, the ambition of energy policies, market dynamics, societal trends and many other factors. The analysis below refers to two scenarios included in the IEA WEO, the Stated Policies Scenario (STEPS) and the Sustainable Development Scenario (SDS).

The STEPS represents the IEA’s assessment of the implications of today’s energy and climate policies, including those policies that have been announced (for example, as part of the nationally determined contributions under the Paris Agreement). This gives a sense of the direction in which the global energy system is heading, based on the latest available market and technology data and a defined set of starting conditions and assumptions.

The SDS takes the opposite approach. It fixes the end point, in this case full achievement of various energy-related sustainable development goals, and then works out a feasible pathway to reach them. Most significantly, it charts a pathway for the global energy sector to be fully aligned with the Paris Agreement by holding the rise in global temperatures to “well below 2°C … and pursuing efforts to limit [it] to 1.5°C”. It also meets goals relating to universal access to modern energy, including access to both electricity and clean cooking fuels, as well as a dramatic reduction in emissions of the pollutants that cause poor air quality.

Achieving the SDS would require rapid and widespread changes across all parts of the energy system, but there is a large gap between this scenario and the direction outlined in STEPS. While the SDS requires an early peak and a rapid decline in energy-related CO₂ emissions, in the STEPS there is no such peak in sight before 2040. And while the SDS sees universal access to modern energy achieved by 2030, in the STEPS there are still more than 600 million people remaining without electricity in 2030, and well over 2 billion still reliant upon the traditional use of solid biomass as a cooking fuel.

This disparity between the direction in which the world appears to be heading, on the one hand, and what would be required to hit crucial energy-related sustainable development goals, on the other, is a crucial fault line in global energy. The production and use of biogas and biomethane grow in both of these scenarios, but the STEPS and SDS also provide divergent visions of the opportunities that might lie ahead.

A wide range of technologies and policies are required to bring down emissions and ensure universal access.

In the SDS, alongside widespread improvements in energy efficiency, there is also a step change in the pace at which renewable technologies are deployed. This is most visible in the power sector, where renewables provide two-thirds of electricity supply worldwide by 2040 (up from one-quarter today). Of this, solar PV and wind power together provide 40%, with a further 25% from dispatchable renewables including hydro and bioenergy.

The growth in low-carbon electricity is accompanied by the rising importance of electricity as an energy carrier. The share of electricity in global final consumption rises from 19% today to more than 30% by 2040. The increase in electricity demand in the SDS comes from a variety of sources; the largest is electric vehicles.

However, even with rapid growth in low-carbon electricity, more than two-thirds of final consumption in 2040 in the SDS comes from other sources, mainly from liquids and gases.

And even if electricity use were to grow even faster and the complete technical potential for electrification were deployed, there would still be sectors requiring other energy sources (given today’s technologies), with most of the world’s shipping, aviation and certain industrial processes not yet “electric-ready”.

These trends open up significant possibilities for biogas and biomethane. These gases can help to decarbonise parts of the energy system that low-carbon electricity cannot reach. By enhancing the flexible operation of power systems, they can facilitate the rise of wind and solar. By displacing the traditional use of biomass, they can provide clean cooking fuels as part of the drive for universal access to modern energy. As a local, sustainable source of power and heat, they offer communities and municipalities a way to meet clean energy commitments in tandem with renewable electricity.

Biogas and biomethane start from a low base, but are the fastest-growing forms of bioenergy in both the STEPS and the SDS. Their combined market share in total modern bioenergy demand grows from 5% today to 12% by 2040 in STEPS and to 20% in SDS.

Global direct consumption of biogas was around 35 Mtoe in 2018. Currently, over 60% of biogas production capacity lies in Europe and North America. As the leading biogas-producing region, Europe has around 20 000 biogas plants, with the majority situated in Germany. Most are built for on-site electricity generation and co‑generation, with around 500 plants dedicated to the upgrading of biogas (OIES, 2019).

In the STEPS, projected production of biogas for direct consumption more than doubles, reaching around 75 Mtoe in 2040. Most of this growth comes from centralised plants that are fed by agricultural and municipal solid waste sources in order to meet local power and heating demand. The share of biogas used for power and heat rises from around 70% today to 85% by 2040.

Providing a renewable and reliable source of power has typically been the easiest route to market for biogas, given incentives such as feed-in-tariffs, subsidy grants and tax relief schemes that can also support the development of rural areas. The economic case for biogas improves when biodigesters are favourably located – e.g. close to feedstock sources, electricity networks and local heat offtake – or where co‑benefits, such as the ability of biogas plants to treat wastewater with high levels of organic pollutants, are recognised and remunerated.

Such co‑benefits from biogas production can address a suite of sustainability priorities in developing economies, which are set to capture three-quarters of the growth in global biogas production. China, already producing almost a third of the global total, is seeking to expand rural biogas production to reduce air pollution from coal use while improving waste management practices, with plans to reach a level of nearly 17 Mtoe (20 bcm) by 2030 (from around 7 Mtoe today). India has offered to provide financial support to local biogas co-generation plants and has overseen the deployment of more than 5 million household biogas units for clean cooking. The prospects for biogas are further galvanised by wider bioenergy targets in countries such as Indonesia, Malaysia and Thailand. These countries are seeking to develop a biogas market by leveraging vast quantities of available residues produced from certain industry sectors, such as the palm oil industry.

In the SDS, robust policy support for biogas development translates into nearly double the production level of the STEPS by 2040, along with a wholesale shift towards the use of sustainable feedstocks. Over 80 Mtoe of biogas is produced in developing economies alone, which exploit their vast potential from agricultural residues and MSW. Growth is underpinned by the use of biogas as a relatively stable source of renewable electricity generation; this becomes more valuable as developing economies increase the share of variable wind and solar in their electricity generation mix.

Biogas also provides an important option to support clean energy commitments at community level, especially where access to national electricity grids is more challenging, or where there is a large requirement for heat that cannot be met by renewable electricity. There is also a considerable push to develop biogas for clean cooking. By 2030, around 200 million people move away from the traditional use of biomass through biogas, half of whom are in Africa.

The development of a biogas industry ultimately depends on the policy framework in different countries and regions, which is itself informed by broader renewable energy goals and targets. In Europe most biogas plants to date have been built to capture feed-in tariffs and other forms of support for renewable power generation. In developing economies, development funding has driven the deployment of biodigesters at household and community levels to help ensure rural energy access.

In the SDS, there is an acceleration in the production of biogas in several regions. The installation of household biogas digesters is part of a concerted policy drive to ensure access to clean cooking solutions in developing economies, particularly for geographically dispersed populations located in rural areas far from cities or not connected to gas or electricity grids. Scaling up the use of household biogas in the SDS requires annual additions of over 5 million biodigesters in developing economies over the period to 2040.

A range of medium- and large-scale centralised biodigesters are also deployed in this scenario to capture agricultural wastes across a larger number of sources. These centralised units form around clusters of agricultural feedstock sources (e.g. a dense set of industrial farming facilities) and produce in the range of 500 m³/hour to 1 000 m³/hour of biogas; economies of scale mean lower per-unit capital and operating costs compared with smaller-scale commercial units. Such facilities could provide heat to local, captive distribution systems as well as power to national grids.

With low marginal costs of installing capture equipment, closed landfill facilities make the largest contribution to the growth in total biogas production in the SDS, as emerging economies increasingly adopt more comprehensive and efficient waste management practices.

Biogas production in the SDS ultimately comes from thousands of local, small-scale facilities, compared with the traditional large-scale centralised infrastructure that meets most energy service demand today. While this has several co‑benefits for rural communities, it also creates challenges for scaling up output, as larger plants require more sophisticated co‑operative models and are also more exposed to the variability of different waste streams. It is also less certain that biogas digesters can undergo the type of factory-style modular fabrication that has driven down the manufacturing costs of other renewable technologies, such as solar PV.

Policy frameworks need to value the co‑benefits of biogas, including reduced air pollution, avoided emissions, and rural and agricultural development, and to consider its contribution in these areas relative to other bioenergy pathways (i.e. biofuels or solid biomass). Tailoring support schemes to local conditions could also ensure that a biogas industry develops as a partner, rather than competitor, to food production.

Below, this report considers the role of biogas as a way to provide clean cooking in Africa, to illustrate how well-designed policies can overcome some of the barriers to larger-scale deployment.

The world has made considerable progress towards achieving universal access to electricity in recent years, but increasing access to clean cooking facilities remains challenging. In sub-Saharan Africa, around 900 million people lack access to clean cooking facilities (or, five out of six people), accounting for a third of the global total. Almost 95% of them use solid biomass, in the form of fuelwood, charcoal or dung in open fires, while the remainder use kerosene (especially in Nigeria) or coal (mostly in Southern Africa).

At the global level, 80% of those without access to clean cooking are located in rural areas, and they make up 60% of the world’s rural population. Less than 15% of the urban population globally lacks access to clean cooking, thanks to wider access to cleaner options.

There are a range of modern fuels and technologies that can provide clean cooking, including natural gas, LPG, electricity, bioethanol and biogas, or improved biomass cook stoves which deliver significant improvements compared with basic biomass cook stoves or three-stone fires. The choice among these options is a consequence of the interactions among policy, geography, demographics and socio‑economic factors.

Rural areas face a unique array of challenges in transitioning towards clean cooking, with the lack of availability of modern fuels being one of the principal barriers to change:

• LPG is not always available due to long distances and poor transport links between distribution centres and households. Moreover, there can also be competition for supply from urban areas.
• A move to electric cooking is impeded by very low rates of electricity access in rural areas in Africa, the unreliability of electricity supply in many places where it does exist, the prioritisation of electricity for uses such as lighting and appliances, and a cultural preference in many countries for cooking over a flame.
• Other modern fuels such as ethanol and processed biomass pellets or briquettes often face similar barriers to access.

Household air pollution resulting from reliance on inefficient and polluting cook stoves is directly linked to nearly 500 000 premature deaths in sub-Saharan Africa in 2018, and 2.5 million globally. There are also around 3 million deaths attributable to outdoor air pollution, half of which are in China and India. Stubble burning, the practice of intentional burning of the stubble that remains after grains have been harvested, is a major contributor to air pollution. There have been attempts to restrict this practice, but it remains common in many developing economies (in India, stubble burning can account in certain peak days for up to 40% of air pollution in Delhi).

Turning organic waste such as animal manure or crop residues into biogas via a simple household biodigester offers a way to support rural development and to alleviate these health impacts. In China, for example, subsidy support was based on the diversion of household sewage towards biodigesters, with major positive health impacts.

Research in East Africa shows that families with access to biogas see benefits in terms of ease of cooking and a reduction in the time spent collecting fuelwood, as well as a lower incidence of health and respiratory problems. There are also potential co‑benefits in terms of agricultural productivity (as a result of using the digestate as fertiliser) and reducing deforestation (Clemens et al., 2018).

The main economic challenge is the relatively high upfront cost of the biodigester. In Africa, upfront costs for an average-size household biodigester with a technical lifetime of over 20 years can range between USD 500 and USD 800 (ter Heegde, 2019). Installation costs for other clean cooking technologies are much lower. However, on a total cost-of-ownership basis, biodigesters have a corresponding advantage by having low or non‑existent fuel costs, and basic digesters can prove their relative worth once they surpass two years of continuous use.

A part of the capital cost can be reduced by using traditional and locally available construction materials such as sand and gravel, and by relying on local labour. For the remainder, financing help is often needed. There are also significant non‑economic barriers. Biogas systems have been in use as early as the 1980s to provide clean cooking in rural parts of Africa and Asia. However, their wide-scale diffusion has been limited by a number of deployment challenges, such as difficulties with providing a continuous availability of feedstock and ensuring proper maintenance of biodigesters. These barriers can be even more pronounced for a biodigester at the community scale or larger. The same research in East Africa showed that more than a quarter of biodigesters installed between 2009 and 2013 were out of operation by 2016 because of a lack of readily available maintenance expertise (Clemens et al., 2018).

While there are no fuel costs for running household biodigesters, producing and gathering sufficient feedstock cannot be taken for granted. For example, in order to generate enough biogas to cook for two to three hours per day and prepare one family meal, 20 to 30 kg of fresh dung has to be available on a daily basis, along with an equivalent quantity of water. Feeding a household biodigester regularly with animal manure requires at least two mature cattle, so any deterioration in household circumstances quickly affects biogas production, while local communities need to develop and maintain a system to collect waste and residues for centralised biodigesters.

Well-designed development assistance programmes could help overcome these barriers and thereby encourage the wider diffusion of household biodigesters. Training a local workforce and involving local communities in the construction of biogas production plants can create durable employment opportunities while ensuring the optimal use of biodigesters over their full technical lifetimes.

Local entrepreneurs and government partnerships with the private sector also have a crucial role to play in overcoming these barriers, with governments promoting investment through a range of subsidy programmes, community grants and favourable financing facilities. This is crucial for attracting private-sector participation, particularly independent energy companies, private equity and infrastructure funds, which can help scale up the supply chain while benefiting from lower-cost financing afforded by government-backed investment programmes.

The agricultural sector employs around half of the labour force in Africa, meaning biogas is a strong contender for large-scale diffusion across the population. However, a clear picture of today’s consumption of biogas in Africa is not available due to lack of data. This report estimates that current biogas use is around 5 000 toe (6 million m³ of natural gas equivalent), and its use is concentrated in countries with specific support programmes for this fuel.

Some governments, such as Benin, Burkina Faso and Ethiopia, provide subsidies that can cover anywhere from half to the full cost of investment, while numerous projects promoted by non‑governmental organisations provide practical know-how and subsidies to lower the net investment cost. In addition to these subsidies, credit facilities have made progress in a few countries. A limited number of companies in Kenya have recently developed a new lease-to-own (LtO) arrangement, and around 45% of the households in Kenya that installed a digester in 2018 financed their unit through an LtO arrangement (ter Heegde, 2019).

Based on this new bottom-up assessment, this report estimates that Africa has the potential to provide nearly 50 Mtoe of locally produced low-carbon biogas, largely via household-scale biodigesters; this potential doubles to almost 100 Mtoe by 2040, at an average cost of around USD 15/MBtu. The case for developing biogas in Africa is strongest for rural areas with large agricultural sectors. Crop residues, especially cereals, account for almost 60% of the total potential, animal manure for close to 25%, and MSW for most of the remainder. At the end of the outlook period, the picture changes slightly as further urbanisation increases the availability of MSW and as anticipated changes in diet underpin an increase in livestock and therefore of animal manure.

Projected consumption of biogas rises to more than 3 Mtoe in Africa by 2040 in STEPS. However, this is only a fraction of the potential. Africa’s rural electrification needs and the achievement of universal access to clean cooking could push biogas demand three times higher, at 9 Mtoe by 2040 (over half of this would be used as a clean cooking fuel, the remainder for power generation). In such a scenario, more than 100 million people in Africa use biogas to move away from reliance on traditional use of solid biomass.

Whichever way the energy system evolves over the coming decades, biomethane is on a growth trajectory. But the extent of that growth varies substantially between STEPS and SDS, responding to the different market and policy environment that each scenario describes.

Since biomethane is indistinguishable from natural gas, it can reach any grid-connected residential or commercial building, industrial facility, or power plant and can provide energy services to a broad spectrum of sectors and end users. To be injected, biomethane has to comply with the gas grid specifications originally planned for natural gas.

Viewed through the lens of decarbonisation, the optimal uses of biomethane are in end-use sectors where there are fewer low-carbon alternatives, such as high-temperature heating, petrochemical feedstocks, heavy-duty transport and maritime shipping. But there are other motivations that can play into the uses of biomethane, including rural development, energy security (where biomethane is used instead of natural gas transported over long distances or imported, or where it is used flexibly to complement electricity from variable wind and solar PV), and urban air quality.

This range of motivations is visible in IEA scenarios, notably in developing economies in Asia (including China, India, Southeast Asia and other developing economies in Asia Pacific) that account for the bulk of the growth. China produces over 30 Mtoe of biomethane by 2040 in the STEPS, which is injected into its expanding natural gas grid, while India’s consumption grows to 15 Mtoe, in part to support the expansion of gas use in the transport sector.

In the case of China, biomethane largely substitutes for domestic coal and imported natural gas (biomethane provides a much greater reduction in CO₂ emissions than switching from coal to natural gas). In India, it substitutes for the traditional use of solid biomass and for oil products, where import dependence stands at around 80% of total demand.

Projected consumption growth in STEPS is more limited in countries with mature gas markets. Consumption in North America increases to just under 10 Mtoe. European biomethane use reaches 12 Mtoe in 2040, accounting for 2.5% of the gas used in natural gas grids.

At the moment, 70% of the biomethane used in Europe comes from energy crops. The share of waste and residue feedstocks is set to rise, though, as policies seek to encourage bioenergy that avoids competition with food or feed production, and industry initiatives (such as the Biogas Done Right concept developed by the Italian Biogas Association) gain traction.

In the SDS, the production and use of biomethane accelerates in all regions, a consequence of strengthened efforts to lower the carbon footprint of gas and ensure energy access across the developing world. The Asia Pacific region sees by far the largest growth, driven in large part by China and India, but gains are also visible elsewhere: by 2040, there is a 10% blend of biomethane in gas grids in Europe and a 5% blend in North America. This represents a step change in the role of biomethane in global energy.

Reducing emissions from the transport sector is a central challenge of energy transitions. Efficiency, electrification and alternative fuels are the key vectors for reducing reliance on oil, with biofuels currently displacing around 2 million barrels per day of oil demand. Natural gas is also playing a role in some sectors and countries; there are some 28 million natural gas-fuelled vehicles on the road today, representing around 1% of the global road fleet. This also opens up opportunities for biomethane.

The case for using compressed natural gas (CNG) or LNG for transport is strongest in transport segments where electrification is a more challenging prospect, such as long-haul road freight and shipping. Although the provision of gas fuelling infrastructure adds expense and complexity, there are possibilities to build infrastructure along established routes (for example those used by captive fleets such as municipal buses, refuse collection vehicles, or ferries and cruise ships) or along key transport corridors sustaining a significant portion of tonne- or passenger-kilometre activity.

The environmental case for natural gas in these applications rests on much lower air pollutant emissions, allied to an appreciable reduction in CO₂ compared with combustion of oil. The counterargument points to the risk of fugitive methane emissions along the natural gas supply chain as well as at the vehicle tailpipe.

The use of biomethane as a transport fuel bolsters the environmental case for gas-based vehicles. It also has a distinctive advantage over bioethanol and biodiesel, which can often be subject to blend share limitations (since they are not identical to gasoline and diesel); biomethane, by contrast, can fully replace natural gas as a source of fuel without any changes required to the engine.

Around one-fifth of existing biomethane plants produce either CNG (bio‑CNG) or more energy-dense liquefied gas (bio‑LNG) for the transport sector, but their use in transport is currently very small. How far and fast this niche role expands depends to a large degree on policy design and the buildout of infrastructure.

The United States is the current leader in this area, due to incentives from the federal Renewable Fuel Standard and California’s Low Carbon Fuel Standard. Several countries in Europe are also developing gas-based transport infrastructure; most of Sweden’s biomethane production is used in vehicles, giving it the highest share of biomethane use in transport demand. Italy has a well-established natural gas vehicle fleet and an expanding fuelling network, and has recently introduced biomethane blending obligations. India also has ambitious plans to expand the use of biomethane in transport, targeting the buildout of 5 000 bio-CNG stations by 2025. Most of the small quantities of biomethane produced in China today are used in gas-fired vehicles – primarily buses and heavy-duty trucks.

The use of biomethane in transport reaches more than 25 Mtoe in STEPS by 2040, or around 30% of total biomethane consumption; a lack of policy commitments elsewhere limits overall growth. In the SDS, biomethane consumption in the transport sector is nearly twice as high, with India accounting for the largest share of vehicles running on biomethane by 2040.

In many respects, the prospects for biomethane and other low-carbon gases are tied up with wider questions about the future role of gas infrastructure in energy transitions. Long-term strategies need to consider the potential for existing and new infrastructure to deliver different types of gases in a low-emissions future, as well as their role in ensuring energy security. There is a concurrent need to consider interactions and possible synergies between the delivery systems for liquids, gases and electricity.

WEO analysis has consistently highlighted the enormous potential for electricity to play a bigger direct role in the energy system in the future (IEA, 2018). Indeed, all deep decarbonisation pathways envisage a low-carbon energy system in which an expansion of low-carbon electricity generation is accompanied by widespread electrification of industrial processes, electric heating takes over market share from natural gas in buildings, and electric transport is ubiquitous.

Since 2000, global electricity demand has grown two-thirds faster than total final consumption. Worldwide investment in electricity generation, networks and storage in 2018 exceeded USD 750 billion, more than combined investment in oil and gas supply.

However, there are limits to how quickly and extensively electrification can occur, as electricity is not well suited to deliver all types of energy services. Even if the complete technical potential for electrification were deployed, there would still be sectors requiring other energy sources (given today’s technologies).

For example, most of the world’s shipping, aviation, heavy-freight trucks and certain industrial processes are not yet “electric-ready”. While in the future these sectors could use fuels that have been generated using electricity (such as hydrogen or synthetic fuels), some of these fuels would need a separate delivery infrastructure.

The energy security value of overlapping infrastructure can also be an important consideration for policy makers. Maintaining a parallel gas infrastructure system adds a layer of resilience compared with an approach that relies exclusively on electricity. This was visible, for example, in Japan when gas-fired generation stepped in to provide power following the shutdown of its nuclear reactors from 2011. It also provides a useful hedge against the risks that electrification and the development of new electricity networks do not increase at the pace needed to displace existing fuels while meeting energy service demands.

However, if gas infrastructure is to secure its role in a low-emissions system, it will ultimately need to deliver truly low-carbon energy sources.

In the SDS, the share of electricity in final consumption rises from 19% today to 30% by 2040, and there is a simultaneous decarbonisation of supply through a significant expansion of renewables, particularly wind and solar PV but also bioenergy, hydropower and nuclear. Still, half of final energy consumption in 2040 remains served by liquids and gases; the share of low-carbon sources in liquids supply also rises to 14%, and in gas supply to 18%.

Replicating the services that gas grids provide via low-carbon electricity may be possible in some parts of the world, in particular areas that have ample resources to generate renewable electricity, relatively limited winter heating requirements, and an economic base (services and certain industrial subsectors) that is amenable to electrification. However, elsewhere, substituting electricity for gas as a way to provide services to end consumers is likely to be much more challenging and expensive.

There are practical issues with deploying electric heating at scale in both industry and residential sectors. The scale of infrastructure investments required to balance peak loads with variable supply present a significant barrier to full electrification. Batteries are becoming cheaper and are well suited to manage short-term variations in electricity supply and demand, but they are unlikely to provide a cost-effective way to cope with large seasonal swings.

If there is, instead, an option to use some existing infrastructure to deliver decarbonised gases, then these networks could be used through energy transitions and beyond. As things stand, gas networks are the primary delivery mechanism for energy to consumers in many countries; in Europe and the United States, for example, they provide far more energy to end users than electricity networks. Allied to gas storage facilities, they also provide a valuable source of flexibility, scaling up deliveries as necessary to meet peaks in demand.

The two main options to decarbonise gas supply are biomethane and low-carbon hydrogen.

There has been a surge of interest in low-carbon hydrogen in recent years, although for the moment it is relatively expensive to produce. Blending low-carbon hydrogen into gas grids would not only mean lower CO₂ emissions, but also help scale up production of hydrogen and so reduce its costs (IEA, 2019b). Further, since there is no widespread infrastructure today for dedicated hydrogen transport, the existing natural gas grid in many countries could be used to transport hydrogen at much lower unit costs than would be the case if new dedicated hydrogen pipelines had to be built.

With minor modifications, transmission networks could probably cope with hydrogen blends of up to 15-20%, depending on the local context. However, regulations on hydrogen blending today are generally based on natural gas supply specifications or the tolerance of the most sensitive piece of equipment on the grid. As a result, only very low levels of blending are allowed: in many countries, no more than 2% hydrogen blending is currently permitted (IEA, 2019b).

Unlike hydrogen, biomethane, a near-pure source of methane, is indistinguishable from natural gas and so can be used without the need for any changes in transmission and distribution infrastructure or end-user equipment.

The trajectory of gas demand in the SDS means a reduced requirement for spending on gas infrastructure, especially after 2030. There is an increasing divergence in trends between advanced economies, where investment levels fall more sharply, and developing economies. In all cases, an increasing share of total spending is for the maintenance of existing networks: investment in new assets continues in some places to meet rising gas demand in the near term, but this also has to take adequate account of longer-term trends.

The growth in biomethane, along with low-carbon hydrogen, provides a way to future-proof continued investment in gas infrastructure in the SDS. However, there are uncertainties about the optimal configuration of the gas grid, including the costs involved in maintaining its role as a flexible delivery mechanism for large quantities of energy.

The chosen pathway to deliver low-carbon gases has major implications for investment in storage and delivery capacity, processing and separation requirements, blending tolerances, and choices about end-user equipment. The uptake of technologies that create interdependences between gas and electricity networks (for example, electrolysers or hybrid heat pumps) will also determine the scale of investments required for gas grids

The location and size of biomethane and hydrogen production facilities are also crucial variables for the scale and types of infrastructure investments. There are many uncertainties over the way this might play out in practice, but in general biomethane production is likely to be more dispersed than hydrogen, requiring (if it is not consumed locally) thousands of new grid connections. By contrast, hydrogen is likely to be done at scale and, in most cases, as close as possible to concentrations of end users (such as industrial clusters).

On the regulatory side, gas quality specifications are an essential step in scaling up production from a variety of different feedstocks and technologies. Blending levels and injected volumes also need to be properly tracked in order to support certification schemes (such as guarantees of origin or the development of national registries), which are required for policies that remunerate consumption of low-carbon gases. There may also be a need to incentivise low-carbon gas production through the socialisation of grid connection charges. 

Another important consideration, particularly in the context of ambitions to reach net-zero emissions, is whether low-carbon gases, on their own, can eventually provide for a fully carbon-neutral gas system. The volumes of low-carbon gases delivered to consumers are on a sharp upward trajectory in the SDS by 2040, but whether they can be scaled up to provide 100% decarbonised gases depends on numerous factors, including relative technology costs, supply availability and the trajectory for gas demand (including seasonality).

In the case of the European Union, maximising the full sustainable technical potential of biomethane would allow it to reach a 40% share of total gas demand in 2040. Options to tackle emissions from the remaining share would include accelerated investments in low-carbon hydrogen, CCUS or carbon offsetting mechanisms, alongside efficiency measures and fuel switching to reduce further gas consumption.