The landscape for biogases is very different now compared to our last Outlook in 2020, with total demand 32% higher in 2040 in the STEPS than in the New Policies Scenario at the time. Whereas natural gas prices in 2020 were at record lows, the Russian invasion of Ukraine in 2022 triggered interest in developing biomethane to substitute imported natural gas. The revised figure is driven in part by strengthened policy incentives, notably in Europe and China.  

There is a strong continued use case for biogases in the Outlook scenarios. Electricity's share in total final consumption increases from 20% in 2023 to over 30% by 2050 in the STEPs and around 40% in the APS. Nevertheless, liquid and gaseous fuels still meet 50% of total final energy consumption in the STEPS and 40% in the APS, creating opportunities for the use of low-emissions fuels in sectors unable to electrify. The share of biogases in total gaseous fuel demand grows from 1% in 2023 to around 5% by 2050 in the STEPS and 10% in the APS. 

In the power sector, capacity of biogas plants increases from 11 GW in 2023 to 20 GW in 2035. Use of biomethane in the power sector triples by 2035 due to its ability to replace natural gas in combined- or open cycle gas turbines; this provides more power system flexibility compared to combined heat and power units with local biogas. Growth also occurs within the industry and buildings sectors, where usage reaches 65 bcme and 60 bcme respectively by 2050 in the STEPS. Transport remains a small fraction of overall biogases usage, in the form of compressed or liquefied biomethane, but nevertheless plays a role in fuel switching. In emerging market and developing economies (EMDEs), fuel switching from oil accounts for roughly 40% of biomethane demand growth to 2035, followed by coal displacement in the power sector (33%) and natural gas displacement in buildings (9%).  

Geographies of demand change significantly in both the STEPS and APS. While Europe and North America currently make up just under 60% of demand for biogases, EMDEs constitute the new majority by 2035 in the STEPs. This is driven by China, which accounts for 40% of the global production increase in that period. Demand roughly triples in Brazil and India as well. 

Demand growth is accompanied by fuller utilisation of feedstock potential, of which only 4% is used today. Municipal waste, as the cheapest feedstock, sees the most development of its potential. However, manure-based biogas is promoted for emissions reduction purposes in the APS and sees its utilisation rise in that scenario despite higher costs. Overall, the average cost for sustainable biomethane falls by 20% to 2050 from USD 20 per gigajoule today, driven by increased crop yields, technological learning effects and economies of scale. 

In order to achieve this potential growth, further investment is needed. Over the past decade, an average of USD 3 billion was invested annually in increasing in the production of low emissions gases. This is less than 2% of equivalent spending on unabated natural gas. In the STEPS, annual investment in biogases increases to USD 15 billion per year by 2050; in the APS, USD 45 billion is reached. These increases will hinge on overcoming investment barriers such as the long payback period for biogases, as well as concerns regarding feedstock availability over the project lifetime.  

Despite these barriers to investment, the energy security dimension of biogases is a key motivator for their continued development. As resources consumed in the country where they are produced, they can help to reduce reliance on foreign producers and create import cost savings. In the European Union, biomethane production avoids the need to import 15 kb/d of oil and 2 bcme of natural gas each year.  

Biogases have their own security of supply considerations, such as fluctuations in production across the year. Yields of biogas from agricultural residues are impacted by harvest and storage times; production from manure can depend on farming practices such as putting cows to pasture in spring and summer. Moreover, the ability of biomethane to provide seasonal gas flexibility is contingent on storage potential. Due to volume constraints at production sites, availability of gas storage within the main grid could be a limiting factor. Especially as further electrification is achieved and some operators begin to consider decommissioning gas infrastructure, planning will be important to ensure that remaining infrastructure is sufficiently dense to be useful while avoiding an overly large network whose costs fall on a shrinking customer base.