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Investment

Average annual investment in gas in the Sustainable Development Scenario, 2016-2040

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Average annual investment in gas in the Stated Policies Scenario, 2016-2040

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Average annual investment in low-carbon gas in the Sustainable Development Scenario, 2010-2040

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Average annual investment in low-carbon gas in the Stated Policies Scenario, 2010-2040

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Currently, biogas and biomethane projects represent only a small fraction of total global spending on gas. Investments have averaged less than USD 4 billion per year over the last decade, the same amount the natural gas industry typically spends every week.

In the STEPS, annual spending on biogas and biomethane rises more than threefold to reach around USD 14 billion by 2040. Rising spending on biomethane eclipses the amount invested in the direct use of biogas by the late 2020s. However, the share of biomethane and biogas in total investment spending on gas remains well below 5%.

The SDS sees a significant upside to this trend. As investment in natural gas declines, total capital spending on low-carbon gases rises to capture over a quarter of total investment in global gas supply, as biogas and biomethane are scaled up and hydrogen and CCUS are added to the mix of low-carbon gases. Biomethane and biogas projects remain the largest destination for low-carbon gas investment, capturing 40% of the total; by 2040, around USD 30 billion is spent on biomethane injected into gas grids every year, around the same level of investment being made in shale gas development in the United States today. These investments are made primarily in developing economies in Asia, particularly China and India, which together make up nearly 40% of total global spending.

The investments made in the SDS assume that several financing barriers are overcome. At the moment, biogas and biomethane projects encounter some of the same financing challenges as other small-scale, distributed renewable projects (especially in developing economies). Local banks often serve as a first port of call for raising the capital necessary for a biogas project; however, the loan requirements are often too small to attract project finance, and also potentially too large for individual investors (e.g. farmers) to raise the required equity. The latter is usually around 20-25% of the initial capital costs (which, for a medium-sized biogas plant producing around 2 million cubic metres per year [1.7 kilotonnes of oil equivalent], would be in the range of USD 1.5 million to USD 2 million).

From a banking perspective, there is often a lack of technical expertise in this area and relatively few benchmarks to assess adequately the risk/return profile for individual projects. There are also some risks that can be difficult to assess, e.g. the ability to secure reliable feedstock of consistent quality or, in the case of biomethane, to meet the rigorous gas quality specifications for injection into national distribution networks. These issues can increase risk perceptions and raise the cost of debt or reduce the loan tenure available to potential investors.

Various models are being tested to overcome these hurdles; for example, project sponsors such as energy companies or larger-scale agricultural firms can offer an integrated business model to farming communities, in order to take advantage of fixed feed-in tariffs or other forms of subsidy, which typically yield a lower risk for securing finance. Farming co‑operatives or other models that aggregate feedstock sources are also viable routes to scale up production.

Both biogas and biomethane projects might also benefit from the growing accessibility of financial instruments focused on renewable projects, such as green bonds or targeted institutional investor funds.

Energy security

Import bill savings from biomethane production in the Sustainable Development Scenario, 2040

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Natural gas imports and biomethane production in the Sustainable Development Scenario, 2040

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For import-dependent countries, investment in biomethane supply can displace the need for fuel imports. Natural gas imports in India, for example, increase from 30 bcm in 2018 to 220 bcm in 2040 in the SDS, while in China natural gas imports double from today’s levels to reach 260 bcm in 2040.

There is widespread biomethane potential in both of these countries, a significant proportion of which is available at relatively low cost. In India, biomethane consumption in 2040 in this scenario is around 35 bcm, and in China, 90 bcm. If this energy demand were to be met instead by natural gas, imports would be around 15% higher in India and 35% in China. Moreover, every additional billion cubic metres of biomethane produced in China or India could save over USD 300 million on fuel import costs; by 2040, both countries would see tens of billions in import bill savings in the SDS, which could help offset the costs of developing a domestic biomethane industry.

The security-of-supply implications of biomethane production on gas networks require careful evaluation. Scaling up biomethane production means gas supply becomes more decentralised. This reduces excessive reliance on the operation of a limited number of large-scale production, storage and import nodes. However, as with electricity distribution, gas grids would need to accommodate the growth of supply at the distribution level; impacts might be felt in grid balancing, while changes to tariff structures and capacity charges might be needed to incentivise injection at the distribution level while avoiding penalising other grid-connected customers.

Most biomethane projects today require a high and relatively constant level of plant utilisation to recoup their initial investment costs, meaning that (in the absence of storage) the seasonal “swing” capabilities of biomethane plants – the ability to ramp up and down – could be limited in some cases. This could have implications for countries with high winter heating loads, where the ratio of average-to-peak demand for biomethane may be an order of magnitude higher than the ratio of average-to-peak supply. For those countries that have it, gas storage capacity would be able to manage this issue. The spare capacity within gas transmission pipelines could also be leveraged to meet short-term peak periods of demand, whether for electricity or heat. Countries looking to replace seasonal LNG or pipeline imports with biomethane would need to assess feedstock types and their productive cycles to understand the energy security implications of this switch.

In the power sector, plants running on biogas and biomethane can provide an important complement to the rising shares of variable renewables such as wind and solar. By leveraging the energy storage potential from gas infrastructure, these renewable gases could also be used to flexibly meet peak electricity demand.

Biogas and biomethane also have co‑benefits in terms of food security, as the by‑product from production – digestate – can be used as a fertiliser and so obviate the need for imports (for example, the European Union must import 30% of its nitrogen consumption, 60% of its phosphorus and 75% of its potassium (European Commission, 2019).

Reductions in CO2 and methane

Average value of feedstock sources for biomethane production according to different carbon prices, 2018

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The potential to realise CO2 emissions reduction from using biogas or biomethane depends on how these gases are produced and where they are used in the value chain. From a policy perspective, it is essential that the production of biogases (and all other forms of bioenergy) actually deliver net life-cycle CO2 emissions reduction.

For example, a 10% volume blend of biomethane in a natural gas pipeline would in theory reduce CO2 emissions in the gas consumed by 10%. However, there are emissions from the collection, processing and transport of the biogas feedstock that need to be weighed against the CO2 emissions that arise during the production, processing and transport of natural gas (GRDF, 2018) (Giuntoli et al., 2015). These indirect emissions can vary considerably between sources of biomethane and natural gas and, unless minimised, they could reduce the CO2 emissions savings from the use of biomethane.

The same is true of low-carbon hydrogen: a 10% volume blend in a natural gas pipeline would reduce CO2 emissions by 3-4% (for a given level of energy). However, the different potential energy inputs and conversion technologies to produce hydrogen mean a careful life-cycle emissions approach is needed to ensure that it is truly low-carbon (McDonagh et al., 2019). 

There is an additional opportunity for CO2 emissions reductions from biomethane production. Biogas upgrading generates a highly concentrated by‑product stream of CO2 that could be captured for as little as USD 20 per tonne of CO2 (tCO2) (Koornneef J. et al., 2013).

Carbon prices enhance the economic case for biomethane consumption, supporting the development of plants in areas of feedstock availability and in many cases providing additional sources of income to rural communities. The value of each feedstock type ultimately depends on the production yield of each tonne of collected waste, and also on the costs of collecting and processing the waste. At carbon prices of USD 50/tCO2, for example, a tonne of MSW used for biomethane production would be worth nearly USD 10, as it could be used to deliver carbon-neutral electricity and heat. However, carbon prices would need to more than triple to unlock the same value from a tonne of crop residue.

Globally, low-carbon hydrogen and biomethane blended into the gas grid in the SDS avoid around 500 Mt of annual CO2 emissions that would have occurred in 2040 if natural gas were used instead.

Global marginal abatement costs for biomethane to replace natural gas, with and without credit for avoided methane emissions, 2018

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… but finding a way to account for methane-related savings is not simple


There is around 30 Mtoe of biomethane potential today that can be developed cost-effectively at a cost lower than the regional gas price. As discussed, if CO2 prices are applied to the combustion of natural gas, then a much larger quantity of biomethane becomes an attractive proposition. If policy also recognises the value of avoided methane emissions that would otherwise take place from the decomposition of feedstocks, then an even larger quantity would be cost-competitive. Methane is such a potent GHG that attaching a value to these avoided emissions makes a dramatic difference to its overall supply cost profile.

Some of the feedstocks that are used to produce biomethane would decompose and produce methane emissions if not carefully managed. This applies in particular to animal manure and the organic fraction of MSW at landfill sites. In both cases, anaerobic digestion can happen spontaneously, generating methane emissions. All other potential biomethane feedstock types, such as crop residues, generally degrade in the presence of oxygen (not under anaerobic conditions) and so do not commonly result in methane emissions.

Biomethane production can avoid methane emissions from certain organic waste by capturing and processing them instead. Even if these emissions occur outside the energy sector, they should be credited to biomethane. This is already the case within California’s Low Carbon Fuel Standard, which considers the full life-cycle GHG emissions for biomethane and gives credit to avoided methane.

Yet estimating the size of this credit is not straightforward, as it depends on a reasonable “counterfactual” case for what level of methane emissions would have occurred if the feedstock had not been converted into biomethane, which can vary according to region and over time. For example, there is wide regional variation in how methane produced within landfill sites is currently handled. In Europe, most sites have capture facilities, with the captured methane (known as “landfill gas”) either flared or used for power generation. In the United States, around 55% of the methane that is generated in landfill sites across the country is captured. Around 20% of the remainder breaks down before reaching the atmosphere, meaning that close to 35% of the methane generated in landfills is emitted to the atmosphere. There is a lack of reliable data on landfills in most developing economies, but the percentage of methane that is captured is likely to be considerably lower than in advanced economies.

There are a number of policy frameworks for how “avoided” methane emissions should be handled or credited (e.g. the Clean Development Mechanism (UNFCCC , 2018), but there is currently no globally agreed or universally accepted framework. Different ways of handling these emissions can have a major impact on the apparent cost-effectiveness of using biomethane to reduce global GHG emissions.

For example, if no credit were to be awarded for avoiding methane emissions, but a credit were to be given for the CO2 that is avoided from displacing natural gas, then around 60 Mtoe of biomethane potential would be economic at a USD 50/tonne GHG price. If avoided methane emissions were to be additionally included, then more than 120 Mtoe would be economic at a USD 50/tonne GHG price.

Considerations for policy makers

Biogas and biomethane both have enormous potential to contribute to clean energy transitions and help achieve a number of energy-related Sustainable Development Goals. There have been previous waves of enthusiasm for these gases but today they meet only a fraction of total energy demand. This is because they are generally more expensive than natural gas and they have not enjoyed the same level of policy support as renewable sources of electricity such as wind and solar PV.

If biogas and biomethane are to play a more prominent role in the future energy mix, it will be critical to recognise both the benefits that they provide over natural gases and the enduring importance of gaseous energy carriers.

This report outlines some possible approaches for consideration by governments and other stakeholders seeking to facilitate biogas and biomethane market development. Two key features of any policy framework are to:

  • Support the competitiveness of biogas and biomethane against oil, natural gas and coal via CO2 or GHG pricing mechanisms. This should include recognising the significant GHG emissions abatement potential of biogas/biomethane from avoiding direct methane emissions from feedstock decomposition to the environment. There are many examples of existing and planned policies that do this globally, including the Low Carbon Fuel Standard in California and the forthcoming Netherlands SDE++ policy.
  • Ensure co‑ordinated policy-making across agriculture, waste management, energy and transport to deliver an integrated approach to developing the biogas and biomethane sector. There are several co‑benefits of developing a biogas industry, including employment and income for rural communities, improved gender equality, health benefits from avoided air pollution and proper waste management, reduced risk of deforestation, and greater resource efficiency. These benefits cut across the competencies and jurisdictions of different government departments, and ultimately a holistic approach is required that adequately values these benefits, and hence incentivises public and private investment in their development.

This report concludes with possible policy considerations and approaches in three areas:

  • Availability of sustainable biogas and biomethane feedstocks.
  • Support for biogas and biomethane consumption.
  • Support for biogas and biomethane supply.

Specific ways to support the availability of sustainable feedstocks for biogas and biomethane production could include:

  • Introduce comprehensive waste management policies and regulations to enhance the collection, sorting and pre‑treatment of MSW, creating suitable biomass feedstock for biogas production in urban areas.
  • Enhance the collection of unavoidable food waste by banning landfill disposal and introducing segregated collection.
  • Promote sequential cropping trials and programmes to maximise feedstock resources from a given area of agricultural land, without affecting food production. 
  • Apply appropriate and harmonised sustainability criteria to ensure only sustainable feedstocks are used for biogas and biomethane production.
  • Introduce GHG monitoring and reporting requirements for large-scale biogas and biomethane production units.
  • Undertake comprehensive national and regional assessments of feedstock availability and cost, including a screening of optimal locations for biogas and biomethane plants, and assessing the potential at municipal level.
  • Conduct feasibility assessments at existing landfill and water treatment plants to assess potential for landfill/sewage gas production.

Policy measures or approaches that could lead to greater consumption of biogas and biomethane include:

  • Consider the wider positive externalities when developing biogas/biomethane policy support, as the benefits from biogas and biomethane extend beyond the provision of renewable heat, electricity and transport fuels.
  • Encourage the creation of biogas and biomethane industry jobs in rural locations, through promotional campaigns and training programmes.
  • Support the adoption of biogas installations in rural areas of developing countries for clean cooking through subsidy programmes covering a certain percentage of the capital cost or microcredit schemes that would allow households to pay off the capital costs over time using the economic savings produced by the biogas plant.
  • Design renewable electricity auction frameworks for power purchase agreements that recognise and reward the flexible generation potential of biogas systems. 
  • Develop registries to track and balance the volumes of biomethane injected to the gas network and subsequently consumed. These are an essential component in the application of policy support and are already in place in 14 European countries.
  • Introduce quotas for renewable energy in transport that include sub‑targets for advanced bioenergy production from waste and residues, for example the European Union (EU) Renewable Energy Directive sub‑target of 3.5% of transport energy demand from such fuels by 2030.
  • Roll out natural gas/biomethane fuelling infrastructure along key road freight corridors to enable biomethane consumption, a relevant example being the EU Alternative Fuels Infrastructure Directive.
  • Promote public procurement of biomethane-fuelled vehicles that operate as captive fleets, e.g. municipal refuse collection vehicles and city buses.
  • Utilise pricing units that allow comparison with other transport fuels, e.g. units of gasoline or diesel equivalents.
  • Develop a framework for the use of digestate as a soil improver/fertiliser, e.g. through appropriate regulations, standards and certifications.
  • Consider setting binding targets for renewable gases, based on quotas linked to total gas consumption.
  • Develop more targeted incentives for renewable sources of power generation which can provide baseload and load-following services.

Policy measures or approaches that could lead to greater supply of biogas and biomethane include

  • Introduce low-carbon and renewable gas standards and incentives for their use, considering the appropriateness of feed-in tariffs, feed-in premiums or auction-based support schemes for renewable gases.
  • Establish targets for biogas electricity capacity, biomethane production or injection into natural gas networks based on realistic assessments of feedstock availability and the status of the industry.
  • Introduce fiscal benefits, for example accelerated depreciation for the purchase of equipment/accessories for biogas production, and exemptions from excise duty for imported equipment and biomethane fuels.
  • Develop relevant technical specifications, for example the European EN 16723-1 (2016) standard for the injection of biomethane in the gas grid and EN 16723-2 (2017) standard for biomethane use in transport.
  • Stimulate innovation in solid biomass gasification to accelerate its commercialisation.
  • Develop frameworks for co‑operative infrastructure deployment for biomethane upgrading and gas network injection, reducing the investment and operational costs for multiple biogas producers in the same geographical location, e.g. multiple farm digester units. 
  • Establish a shared understanding about the path to minimise the risk of conflicts between the strategies of market participants with differing commercial interests.
  • Utilise nationally appropriate mitigation actions in developing countries to facilitate technology transfer, financing and capacity building from developed countries
  • Harness overseas development assistance to co‑fund the market-based provision of household and community-scale biogas systems in developing countries.
  • Raise awareness of biogas’s potential in key industry subsectors such as food and drink, and chemicals. 
  • Clarify and harmonise Guarantee of Origin schemes and regulations in collaboration with other governments to encourage virtual cross-border trade of low-carbon gas.
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