Pillar 3:
Biogas Utilisation

Pillar 3: Biogas Utilisation sets out the suite of policies that will support and stimulate the rapid development of primary output of the biogas industry – biogas (other outputs, digestate and carbon capture for utilisation and storage, are addressed in Pillars 4: Digestate Policy and Pillar 5: Gas Quality Regulations respectively) and the variety of its end uses such as electricity generation, heating, cooking and transportation.

Countries across the world will benefit tremendously from creating a supporting environment for the industry and assessing the end of this renewable energy. Aligned to international and national policies on biogas, supporting biogas utilisation is essential for its environmental benefits (creating a circular economy, emissions reduction, sustainable organic waste management and nutrient recycling), contributing to energy security (potentially creating a source for locally produced baseload power that can be used for diverse energy uses) and creating social and economic growth (jobs and market opportunities as well as improved energy access and health benefits).

This pillar details avenues for support, including taxation and trading mechanisms to create an even playing field and incentivising biogas generation, that governing bodies can pick directly and apply suitably to their jurisdictions.

Conclusion

Pillar 3 provides a detailed toolset for countries to rapidly stimulate their biogas generation and ensure their ongoing viability over the long term. In enacting these recommendations at an early stage, governments will realise the environmental, social and economic benefits of this crucial renewable source of energy.

PILLAR 3: Biogas Utilisation

Introduction

Biogas is currently the primary output of anaerobic digestion (AD) along with digestate and bio-CO₂, but biogas is the one that has been widely used and monetised. It is also the primary focus of most current policy incentives where the industry is mature. Pillar 3 considers policies in relation to the use of biogas. The focus is on biogas only and not on other outputs, which are dealt with elsewhere, although the potential for carbon capture and storage, with and without use of the stored carbon dioxide (CO₂), is included.

Supporting biogas utilisation is essential for multiple environmental, economic, and social reasons including environmental benefits (creating a circular economy, emissions reduction, sustainable organic waste management and nutrient recycling), contributing to energy security (potentially creating a source for locally produced baseload power that can be used for diverse energy uses) and creating social and economic growth (jobs and market opportunities as well as improved energy access and health benefits).

3.1. Overarching Considerations

The Pillar 3 policies should be aligned with a country’s approach to the formulation and implementation of international and national policies on climate change (see Pillar 1), as well as policies that may be considered (or already in place) to support the use of solid and liquid outputs (see Pillar 4). The combined objectives of the policies should be to offer an efficient means of supporting biogas without undermining the case for other intents – for example, the prevention of food waste – where this is clearly possible. Policies need to ensure that there are no leaks to the atmosphere in the implementation of the technology.

Policymakers should also consider the balance to be struck between supporting the viability of biogas and ensuring that the price of energy, or the cost of managing waste, does not have contradictory consequences. ¹ In this context, it is worth noting that some countries that offer financial support to biogas generation may also have existing policies that place a price on pollutants such as CO₂, or they may have implemented taxes and/or restrictions on landfilling and incineration.

EXAMPLES

The United Kingdom has used various schemes to support biogas over the years ², but it also has a landfill tax of over £100 per tonne. ³It plans to bring incineration within the scope of its ETS. ⁴

By the end of 2025, Scotland will implement a ban on biodegradable municipal waste in landfills, with England expected to follow by 2028.⁵

Hamilton City Council (New Zealand) aims to reduce the amount of waste each person sends to landfills by 10% by 2024. ⁶

All countries should look to introduce a set of coherent, stable policies, or be on a trajectory that has a clear direction. This is not always straightforward, as biogas can be derived from a range of different sources, and its energy and/or gaseous content can be used in different ways (see Table 1).

Table 1: Potential feedstocks and possible uses of biogas

Sources of feedstocks

Manures, slurries and livestock wastes

Crop residues

Energy crops (crops grown specifically for biogas generation)

Organic fraction of waste degradable in landfills

Segregated organic waste (households/business)

Food processing wastes

Sewage sludge

Biogas uses

Generation of electricity and heat through use of combined heat and power (CHP) engines

Gas for cooking

Upgraded gas: injection into gas network

Upgraded gas: use as transport fuel

Reacting methane with steam to produce biohydrogen

Sustainable aviation fuel

Decentralised/off-grid energy source

Use of CO₂ in greenhouses/manufacturing/ food processing

Use of CO₂ as a basis for chemical synthesis

Storage of CO₂ (CO₂ removal)

Countries may not always have a clear view as to how biogas might best be used in a given context and over the long term, so looking forward to the most beneficial output that biogas can be used for is a sensible first step.

3.1.1. Biogas industry as a solution to problems

The different sources from which biogas is derived is also relevant, as they might be more or less prevalent or problematic in different countries. A starting point may be to consider the potential sources of biogas, and the problems that biogas generation might seek to address. For example:

Using biogas facilities to manage manures and slurries might be considered as part of an approach to reduce the pollution associated with storing manures and slurries (methane, air pollutants and odours), or nutrient run-off from livestock operations. ⁷
Using biogas facilities to manage crop residues may be a response to concerns about burning stubble in fields and its effect on air quality. ⁸
Using energy crops may be part of a strategy to put biogas to specific uses.
Capturing biogas from landfills may be motivated by a desire to reduce fugitive methane emissions, a potent short-lived climate pollutant, from landfills. ⁹
Segregating wastes by businesses and households may be motivated by a desire to further reduce methane emissions from landfills and to return organic matter to soils.¹⁰
Food processors and beverage companies might be motivated to use AD by a desire to extract value (in the form of energy) from wastes that cannot otherwise be eliminated (e.g. spent grain from distilleries) and to meet net-zero targets.¹¹
Generating biogas from sewerage or wastewater treatment might be considered as both a means of generating additional energy and part of a way of treating discharges. ¹²

More generally, some countries are still reliant on coal for much of their power generation – for example, China – and see energy from biogas as one way of combatting the air pollution from fossil fuel combustion. In some contexts, biogas can be part of the solution to energy security and the stability of electricity grids.

3.1.2. Making the best use of biogas

In the case of all but numbers three and six above, a country might not have a specific use of biogas in mind, so how it is captured, or generated at all, will tend to follow the pathway that offers the greatest revenue potential, taking into account the costs of accessing that revenue stream to the operator of the biogas-generating facility. Countries should, therefore, consider the relative prices that might be received from different utilisation pathways, and whether these align with their own priorities. Where they do not, or where those prices are considered insufficient to bring forward what might be considered a desired level of biogas generation in the first place, they should consider the case for policy intervention.

3.1.3. Taking into account potential critics

It is also worth considering that different sources of biogas might attract different levels of critical comment, and this might affect the extent to which it is seen as politically acceptable to offer support for biogas derived from different sources. For example, the use of land to grow crops specifically for biogas facilities has attracted criticism, as has the use of wood chips for biomass energy facilities. ¹³ Partly as a result, jurisdictions such as Denmark and Germany have been revising policy to reduce the extent to which support schemes favour energy crops. ¹⁴ There has also been criticism of biogas from intensive livestock systems. ¹⁵ It follows that there may be a sectoral dimension to any support mechanisms that are considered appropriate in a given country, with the potential for the level of support to be tailored to reflect the costs of developing biogas facilities, relative to the alternatives. Appropriate application of digestate is also necessary to avoid eutrophication caused by excess load of nutrients into water streams and bodies.

3.1.4. Key supporting infrastructure

Assuming all things are equal (for example, revenue opportunities for the off take of digestate), the key infrastructure required for generating specific revenue streams is shown in Table 2. These have their own costs, which will vary with the scale of biogas generation. Policies that are in place about support for the different uses of biogas will influence the choices that operators make about its use. Since these choices imply decisions related to associated capital equipment, and because the capital equipment concerned will not always be used across all the options, it is sensible for policymakers to consider where, in the medium- to-long term, they feel that biogas might best be used within their own energy systems.

Table 2: Key infrastructure associated with different biogas use pathways

Uses	Key Infrastructure
Generation of electricity and heat	For landfills, gas-collection infrastructure (wells, pipework, etc.) CHP engine(s) Opportunity to connection to electricity grid (or suitable ‘private wire’ connection) Heat exchangers
Gas for cooking	Usually for small-scale systems Basic clean-up system Piping into cooking stove
Upgraded gas: injection into gas network	Gas clean-up equipment (removal of CO₂, moisture and other impurities) Opportunity for injection into gas network
Upgraded gas: use as transport fuel	Gas clean-up equipment (removal of CO₂, moisture and other impurities) Compression/storage of cleaned gas Suitable fuelling stations Adapted vehicles/fleet (as necessary)
Reacting methane with steam to produce biohydrogen	Gas clean-up equipment (removal of CO₂, moisture and other impurities) Facility for steam reforming of biomethane Compression/storage of cleaned gas Suitable fuelling stations Adapted vehicles/fleet (as necessary)
Sustainable aviation fuel
Use of CO₂ in greenhouses/manufacturing	Capture of CO₂ from combustion (CHP) or separation of CO₂ (including through gas clean-up) Pipework for CO₂ transport Storage facilities Suitable greenhouses or industrial offtake
Use of CO₂ as a basis for chemical synthesis	Capture of CO₂ from combustion (CHP) or separation of CO₂ (including through gas clean-up) Multiple possible pathways, generally involving catalytic conversion of CO₂ directly or indirectly (conversion of CO₂ to CO) and reacting with one or more of hydrogen, water, electricity, sugars derived from biomass, etc.
Storage of CO₂ (CO₂ removal)	Capture of CO₂ from combustion (CHP) or separation of CO₂ (including through gas clean-up) Transport of CO₂ Compression of CO₂ Onward transport to site for permanent storage

3.1.5. Preferred use

In Europe, much of the support for biogas use in the past was focused on support for electricity generation, and some still is. This was considered appropriate where the aim was to increase the amount of electricity generated from renewable sources, with biogas being treated as one such source. Even then, some countries, such as Sweden, had a stronger focus on the use of biogas as a source of heat, and then around the turn of the century as fuel to power transport, notably buses for public transport. The benefits of using biogas for electricity generation were limited in Sweden, where most of the electricity was already derived from clean low-carbon sources, while the use of biogas in transport could displace diesel and reduce emissions of both greenhouse gases (GHGs) and harmful air pollutants. ¹⁶

Over time, many European countries have progressively decarbonised power, and some countries, such as the UK, have shifted their focus for biogas use away from power generation and towards sectors that have tended to decarbonise more slowly, such as transport and heat. ¹⁷ Equally, many countries now see the principal route to decarbonisation of transport and domestic heating (but typically not industrial heating) as being through electrification via decarbonised power generation.¹⁸ Biogas for CHP (combined heat and power) or boilers is often still the first step before moving to biomethane process, as is now seen in developing countries. While this has been the traditional pathway since the early days of the industry, countries establishing biogas policy today could fast-track support for biomethane production, to meet specific national need.

3.1.6. Length and stability of support

Government policies and priorities might shift over time: if they do, ideally the policy shift should not penalise those who have made investment decisions in good faith and based on policies enacted previously. Of course, governments should not have to write ‘blank cheques’, but their policy design should acknowledge the nature and longevity of the capital investments being made.

3.1.7. Avenues for support

It is worth considering some of the policies that have been, and may be, used to support biogas use, recognising that different countries may have different priorities about the products of biogas.

Note that there are a range of different approaches that can be used to stimulate biogas generation. In principle, biogas facilities imply:

an upfront capital investment, which may require a source of financing if it cannot be financed off the balance sheet of the investing body
a cost of operation, which may include labour, inputs, utilities, maintenance and the management of (solid and liquid) wastes
revenue streams, which not only must cover the finance costs that are used for investment and the operating costs, but which must also offer the opportunity to make a surplus or profit.

It is relatively rare to see instances of policies that support operational costs. Consequently, to stimulate the development of biogas, two approaches are generally observed:

support for the revenues linked to outputs
support for the necessary capital investments, whether in the form of grants, which are typically restricted to the early stages of development of biogas in a given sector, or finance made available on concessional terms.

The main focus of this report is the first of these, but we give some consideration to the second. We also discuss the case for support for some outcomes, given discussions around, for example, ‘avoided emissions’. Note that where public policy is the source of support, as is usual, it might be a condition of access to support for capital investments that a given facility should not also be a beneficiary of support for revenues linked to outputs, although this depends on the circumstances and the implied level of support.

3.2. Energy/GHG-Related Taxes and Levies

Before considering a means of supporting the use of biogas directly, it is worth considering the role of taxes on GHG emissions and other market-based mechanisms, such as emissions trading schemes. Although these might not be directly related to the use of biogas, they can have implications for the prices that are available in any given market for biogas-derived energy products.

3.2.1. Carbon tax on fossil fuels

For example, if heating fuels are taxed according to their fossil-carbon content, the anticipated effect would be an increase in the price that consumers are expected to pay for heat, which can, in turn, increase the value of biogas if heating from biogas is exempted from the same taxes by virtue of being free of fossil carbon.

The same is true of transport fuels: if conventional fuels are taxed according to fossil-carbon content, so the prices paid for transport fuels derived from biogas can increase if the taxes are not applied to biogas used as transport fuel. Power-generating facilities can also be subject to taxes, e.g. on the fossil-carbon content of fuel inputs.

EXAMPLES

This approach can be found in Nordic countries.¹⁹

Furthermore, in the EU the so-called Energy Tax Directive was passed in 2003, ²⁰ laying down minimum tax rates for a range of energy products, including motor fuels; motor fuels used for specified commercial and industrial purposes (a lower rate is applicable than for use as transport fuel); heating fuels; and electricity (with differentiation according to whether it is used by businesses or others).

Under the EU Emissions Trading Scheme (ETS), biomethane is assigned as zero emission factor under the monitoring and reporting rules (MRR). ²¹

3.2.2. Emissions trading schemes

Some facilities may also be included in emissions trading schemes (ETSs): typically, power, sometimes heat, and occasionally landfills (the scope varies by jurisdiction) and/or agricultural emissions. The waste sector is often excluded from trading schemes, and it is more common to see the application of taxes, or restrictions, on what can be landfilled (methane emissions from landfills are not especially easy to measure directly, let alone to link to a specific tonne of waste). Landfills in New Zealand have been required to surrender New Zealand Units under its ETS, using either a default factor for emissions, or a unique emissions factor, which requires data submission in line with regulations. Waste is also included in South Korea’s ETS.

Where waste incinerators generate energy they are classified as stationary combustion installations for the purposes of reporting GHG emissions to the United Nations Framework Convention on Climate Change (UNFCCC). However, incineration has often been exempted from measures applied to other such installations, even though incinerators also emit fossil-derived CO₂. ²² This might be considered an implicit subsidy that should be removed. Note that the UK and the EU are both now considering the inclusion of incineration under their respective ETSs.²³

ETSs are discussed in further detail in Pillar 1: International and National Policy

3.2.3. Effect of taxes and ETSs on prices received for biogas outputs

The extent to which the above policies lead to an uplift in the sale price for heat, transport fuel or electricity from biogas depends on how product prices are set in markets. ²⁴ Furthermore, any ‘value uplift’ associated with such taxes are not necessarily stable over the long term, and this is especially true of ETSs.

Although it is important to tax fossil-derived sources of energy or include them within ETSs, it might not always offer a sufficiently stable or certain source of revenue over the lifetime of an investment to make biogas facilities attractive to investors. Some of these matters can be partially addressed through, for example, mechanisms seeking to give certainty around carbon pricing in ETSs.

The use of price floors and price ceilings can help to provide some greater certainty to the market, ensuring that allowance fluctuations will be maintained within a range rather than being allowed to fluctuate without constraints. Even then, values will fluctuate between any bounds that are set. Where ETSs are concerned, the extent to which allowances are auctioned, or issued free to some market participants, may further act to weaken any price uplift for biogas outputs.

3.2.4. Removal of fossil fuel subsidies

Implementing market-based measures to internalise (some of) the costs of fossil fuel pollution may support the prices paid for biogas outputs, albeit imperfectly. However, the opposite will be true of subsidies that are made available to produce fossil fuels, including in the exploration phase.

There is a debate around how the term ‘subsidy’ should be defined: some, including staff at the International Monetary Fund (IMF), interpret this as including ‘uninternalised externalities’. Others take a more restrictive view, so that subsidies cover those that are explicit – such as price support schemes – and implicit, such as taxes that a business might have been expected to pay, but from which they are offered exemption. This can include exemptions from capital gains tax, or favourable tax treatment of investments made in the exploration or exploitation of reserves.

While full internalisation of externalities would be a welcome goal (through applying taxes or implementing ETSs with a suitably constrained cap), a far more straightforward first step should be the removal of the explicit and implicit subsidies that benefit the fossil fuel industries in various countries. The European Commission reported that these subsidies amounted to €50bn in the EU in 2020, and while the amount had fallen in most countries between 2015 and 2020, in some countries the amount had actually increased. ²⁵ The IMF, in an update of an earlier study, estimated that fully reforming fossil fuel prices by removing explicit and implicit fossil fuel subsidies, and introducing taxes to address externalities, could reduce GHG emissions by 34% below 2019 levels, keeping the world in line with the Paris Agreement of well within 2°C global warming and towards 1.5°C. This would also generate a net welfare benefit of about 3.6% of global GDP and avert 1.6m premature deaths per year caused by air pollution. ²⁶

3.3. Policies to Support Renewable Energy and Fuels

Whether biogas is used for the generation of electricity, cleaned for injection into the grid or cleaned up for use as a transport fuel, the resulting supply of electricity, heat or motive power has generally been considered to be both renewable and zero carbon. As countries seek to meet decarbonisation objectives and to address other forms of pollution associated with fossil fuels – or, indeed, as they seek to address other forms of pollution – many have sought to support the generation of energy and fuels from biogas. The rationale for support is typically linked to the association of biogas generation with avoiding pollution (if biogas is not created and used the organic waste would emit methane to the atmosphere and increase GHG emissions) and the strategic nature of biogas as a source of heating fuel that helps decarbonise existing sources of gas. In some countries without major investment in storage infrastructure, gas remains an important dispatchable supply source for electricity, and it can allow the decarbonisation of heating with relatively limited adaptation of the existing heating infrastructure.

There are a range of policies that have been used to support biogas and these are often part of a wider suite of policies aimed at supporting the generation of renewable or low-carbon energy. The main mechanisms that have been used in this regard fall into one of the following categories:

feed-in premiums
feed-in tariff / price support
contracts-for-difference
mandated minimum shares or content of renewables, including blending mandates
tradable green certificates.

Note that the different forms of support can be varied based on the features of a given facility, whether that be the size (measured, for example, in terms of the output energy content of biogas, or the tonnage of waste of a given type being received), or the nature of the feedstock used (which may be considered to be more or less sustainable), or the nature of the output (e.g., whether upgraded to biomethane, or used for electricity generation). Some also differentiate according to the nature of the technology used.

3.3.1. Feed-in premiums (fixed)

A fixed feed-in premium provides a producer with a guaranteed premium that is usually a fixed payment in addition to wholesale electricity and heat market prices. ²⁷ The preferential and (often) technology-specific premiums are determined by the government, and the producer can benefit from a secure uplift. However, in this case, the price received for generation by renewable producers of electricity and heat still fluctuates according to the changes in the wholesale market price for electricity and heat.

The fact that the revenue received for generation is still exposed to fluctuating market prices can be problematic, as although the scheme can enable producers to ‘win’ at times of high prices, they are not guaranteed. Particularly where new capital investment is required, financial backers place great weight on the certainty of revenue streams to (partially) justify their investment. That certainty needs to be evident over the lifetime of the asset to attract more interest from financial backers, so enabling project developers. Another way of considering this is that to give the required level of comfort to investors, the guaranteed premiums would have to be higher than is necessary (or over a longer period) to generate the same result as might be achieved using a support mechanism that offers certainty.

This approach, which might be considered as a fixed subsidy on top of a fluctuating market price, is likely to have limited attraction, other than where the ‘fluctuating market price’ is always low and the premium is relatively large (so the premium effectively determines the price received).

Denmark uses feed-in premiums among a range of measures, ²⁸ and Sweden also uses premiums to support biomethane production, with additional premiums being available for the liquefaction of biogas. ²⁹

3.3.2. Feed-in tariffs

Feed-in tariffs overcome the ‘revenue instability’ feature of feed-in premiums; instead of providing a specified level of top-up they guarantee a fixed price for the supply of electricity, heat or biomethane to a network or specific destination. As with feed-in premiums, tariffs can be technology-specific. The tariffs offer enhanced prices relative to what prevails in the market.

This approach has been quite widely used, and while it can clearly overcome the problem of revenue instability, it might not always be the most efficient; if the prices on offer are the same for lower- and higher-cost providers, then the level of price support available might enable some providers to generate excessive profits. Perhaps in response, some schemes have varied tariffs related to the scale of the facility (lower tariffs for facilities of greater scale), but doing so on readily justifiable grounds is not straightforward.

Note that this approach has been widely used to support electricity prices, somewhat less widely to support biomethane used for heat, and not widely for transport fuels. Biomethane for transport tends to be supported more through encouraging minimum bio-content (of fuels) or so-called blending mandates (discussed below).

Experience has shown that in order to make investment attractive, as with feed-in-premiums, tariffs must be guaranteed over a suitable period after the operation starts. Feed-in tariffs are typically backed by contracts that might lock in revenues over an extended period, perhaps 10–20 years. Such contracts can protect investors from the risks linked to policy change, but they may also protect policymakers from changes in circumstances.

Feed-in tariffs thereby reduce both the price and the market risk, and they create certainty for the investor about the rate of return. On the other hand, from a policymaker’s perspective the risk may be that the fixed tariffs end up overpaying for the output generated. Fixed feed-in tariffs, therefore, are more likely to be tailored relative to capacity, or to other features that might affect the level of support required for commercial viability.

Note also that with the possible evolution in a country’s priorities such that a means of support is linked to specific installations, those installations might not be as negatively affected by changes in policy within a given investment cycle: this may give policymakers some flexibility to switch priorities, although some additional capital support might be considered for existing facilities to adapt to a changed policy regime. ³⁰

Examples of feed-in tariffs for electricity are found across the world. In Luxembourg, tariffs are varied by capacity and over time (see Table 3).³¹ An additional heat premium of up to €50/MWh of marketed heat, as well as a manure premium of up to €60/MWh can be granted, in accordance with the conditions defined by the regulations.

Table 3. Feed-in tariffs for electricity, Luxembourg

Power class	Tariff
≤ 100kW	265 (1-(n-2023) × 0.25/100) €/MWh
> 100kW to ≤ 200kW	208 (1-(n-2023) × 0.25/100) €/MWh
> 200kW to ≤ 500kW	188 (1-(n-2023) × 0.25/100) €/MWh
> 500kW to ≤ 2500kW	162 (1-(n-2023) × 0.25/100) €/MWh

Where: n = calendar year of start of electricity feed-in

As part of a wider scheme in Malaysia, ³² biogas from landfills and agricultural wastes are supported as shown in Table 4. ³³ Tariffs vary by the size of the facility, with top-ups available where defined technology specifications are met.

Table 4. Feed-in tariffs, Malaysia

Description of Qualifying Renewable Energy Installation	FiT Rates (RM per kWh)
(a) Basic FiT rates having installed capacity of :
Biogas
(i) up to and including 4MW	0.3184
(ii) above 4MW and up to and including 10MW	0.2985
(iii) above 10MW and up to and including 30MW	0.2786
Biogas (Landfill and Agri Waste)
(iv) up to and including 30MW	0.3015
(b) Bonus FiT rates having the following criteria (one or more) :
Biogas
(i) use of gas-engine technology with electrical efficiency of above 40%	+0.0199
(ii) use of locally manufactured or assembled gas-engine technology	+0.0500
(iii) use of landfill, sewage gas or agricultural waste, including animal waste, as fuel source	+0.0000
Biogas (Landfill and Agri Waste)
(i) use of gas engine technology with electrical efficiency of above 40%	+0.0199
(ii) use of locally manufactured or assembled gas engine technology	+0.0500
(iii) use of landfill, sewage gas or agricultural waste, including animal waste as fuel source	+0.0786

Note: Biogas data from 1 January 2025. Biogas (Landfill and Agri waste) data from 30 September 2025.

For biomethane, the UK Green Gas Support Scheme provides tariff support for biomethane produced via AD that is injected into the gas grid. There are three tiers of support: tariffs from 1 October 2024 are shown in Table 5: ³⁴

Table 5. Feed-in tariffs, the UK

Tier	Tarriff Rate (p/kWh)
Tier 1: up to 60,000 MWh	6.69
Tier 2: above 60,000 MWh up to 100,000 MWh	4.16
Tier 3: above 100,000 MWh up to 250,000 MWh	3.88

Tariffs are calculated to compensate plants for the building of new infrastructure to produce biomethane, and ongoing operational costs.

In Estonia, biomethane support is offered at a rate that depends on the use of the biomethane. If it is consumed as a transport fuel, the amount of support offered is €100/MWh less the average market price of natural gas for the current month. If biomethane is consumed for other purposes via the gas system, the amount of aid is €93/MWh less the average market price of natural gas for the current month. ³⁵

3.3.3. Contracts-for-Difference

Feed-in premiums offer price support, but the level of support is constant, whether the market price for outputs is high or low. Feed-in tariffs offer a fixed overall price for the supply of renewable electricity, heat or fuel. This addresses the problem of revenue uncertainty for investors, but it might not be the most efficient way to offer price support. If the price is set too low, then only very low-cost sources of biogas or large facilities for biogas will be encouraged to invest. If the price is set too high, there might be reduced incentive for producers to come forward with lower-cost facilities.

From the perspective of value for money per unit of revenue, one way to achieve a more efficient use of support revenue, while also addressing the investor’s problem of revenue instability, is the contracts-for-difference (CfD) approach. Under this approach, potential project suppliers bid to supply new capacity for electricity, biomethane or heat, with their bid being the minimum price that they would be prepared to accept and the capacity they propose in their project(s).

This approach is sometimes termed a reverse auction, since the bidder (the biogas generator) is bidding for a price they need to be paid to supply something, not a price they will pay to purchase something. The bids are made under specific rules and then reviewed by a market operator, and as long as they are below an acceptable price (which can be made clear in advance), and subject to other constraints being met (there may be a maximum capacity to be supported), the successful bidders are awarded supply contracts. A so-called ‘strike price’ is then established through a specified rule, which could simply be the price of the bid placed by the last successful (the ‘marginal’) bidder. Contracts require the successful bidder to start the supply, as bid, within a given time frame.

In this model, the level of support rises and falls as the price of electricity, biomethane or heat falls or rises, respectively. If the market price falls below the strike price, the successful bidder receives a payment for the difference. Equally, if the market price rises above the strike price, the successful bidder then pays revenue to the scheme administrator. In this way, the revenue paid to suppliers is a ‘smoothed’ amount equal to the strike price (which may be indexed to a measure of price inflation) over the period of the contract. From the policymaker’s perspective, the revenue paid is no more than what the market indicated was the necessary price to call forward that level of capacity. In this respect, it is an efficient approach that can be used to stimulate a market where none currently exists. More and more countries appear to be adopting this approach, which is sometimes referred to as a feed-in-premium, although it can be differentiated from the fixed premiums discussed above.

Note that this approach might lend itself to some forms of biogas more than others: for waste facilities in particular, the risk as seen by investors is not only related to revenue from the sale of energy products, though evidently this can help compensate for the presence of other risks. Other issues related to the certainty of feedstock supply will affect the ability of any would-be bidder to become a supplier of energy products, so this approach might be more suited to agricultural sources or to those dealing with their own process wastes on-site.

CfD approaches to bringing forward new capacity for power generation are gaining popularity. It is not difficult to understand why: whether the revenues that support prices come from the public purse, or from electricity suppliers and heat providers, the policymaker has a wider interest in minimising the inefficient use of the funding resource. All things being equal, failure to do so requires more tax revenue or higher prices to consumers.³⁶ CfD contracts have not been widely deployed for biogas, but this is changing. In many cases, they have been used initially for electricity-generating projects, such as offshore wind. Where auctions for CfD contracts have been agnostic about technology, biogas generators have not always been competitive with offshore wind, for example. In principle, however, they seem likely to become more widely used to increase the supply of biomethane for heating or transport fuel, although the way the supply of biogas interfaces with the nature of gas transport and upgrading infrastructure may complicate matters to a degree. Indeed, a number of countries are developing approaches which include, or are tailored specifically to, biomethane generation.

A good examples of this approach is found in Italy, where the New Biomethane Decree of 2022 sets reference tariffs for small agricultural plants, larger agricultural plants and plants whose feedstock is waste. The decree provides for two approaches to tariff setting, but larger plants and those who have no third-party connection obligation are subject to the tariffa premio, which amounts close to a CfD mechanism.³⁷ Note that Italy also offers support for the capital costs of new facilities (see ‘Support for Gas Upgrading’).

In Denmark, the current support scheme for biomethane is a combination of fixed and variable premiums that the beneficiary receives on top of the sale price of the gas, so the overall support covers the cost difference between fossil gas and biomethane. ³⁸

Currently there is no real CfD mechanism for biogas although some are in consideration for bioenergy with carbon capture and storage (BECCS).

3.3.4. Mandated minimum shares or content of renewables, including blending mandates

Another way of increasing the demand for renewable energy, including biogas, is to require suppliers to achieve a specified minimum share of generation or supply that comes from renewable sources. Denmark, for instance is aiming to phase out all fossil fuels from its grid and to achieve 100% biomethane in heating by 2030.³⁹The extent to which this affects the supply of and demand for biogas depends on a number of factors.

The way in which the shares or content are set, and the scope of their coverage, clearly has implications for biogas. For example, if biogas is a relatively expensive source of electricity generation in a given country, then requiring a minimum share of electricity generation to come from a general ‘pot’ of renewables might not have a significant impact on calling forward new capacity for biogas, as the cheapest technologies would be expected to be used first.

This issue can be partially overcome by configuring schemes so that they give different levels of support to different technologies by setting the targets in terms of the share covered by ‘green certificates’, and allocating different numbers of green certificates to different technologies. This could reflect, for example, other benefits associated with the deployment of a given technology. For example, the UK adapted its system of renewable obligations certificates (ROCs) so that different technologies were entitled to a different number of certificates per kWh of electricity generated: AD was entitled to 2 ROCs per kWh, while the default figure was 1 ROC per kWh.

In principle, the same is true for transport fuel if multiple sources are to be included in scope. Indeed, approaches could be developed based on the extent to which different sources are deemed to offer GHG savings relative to a comparator, based on a specified methodology. Alternatively, biogas may be identified specifically as a source to which the minimum mandate applies. Hence, India has mandated 5% biogas in compressed and piped natural gas by 2028. ⁴⁰

If gas is a major source of heating fuel, and if minimum shares are set for biogas in the share of gas delivered to customers, then there may be a more direct stimulus to the development of new capacity for biogas.

3.3.5. Tradable Green Certificates

The previous section noted that implementing minimum shares or blending mandates can apply to each individual supplier or, alternatively, the mandates could be applied at the level of the totality of supply. In the former context, each individual supplier may have to develop a source of the required supply of their own, even though they might not be best equipped to do that. On the other hand, it might be unfair to expect a target for the totality of supply to be met by only some suppliers and not others; there would, in any case, be limited incentive for that to happen.

As a result, and to give greater certainty of meeting the target in an efficient manner, an overall supply target may be made tradable. In this case, the renewable forms of energy – electricity, heat, or transport fuel – might be recognised as such by being certified, with the certificates of origin being made tradable. Instead of each supplier having to arrange for the supply of the source of renewable electricity, heat or fuel, the supplier can purchase certificates in a market. In effect, the overall obligation becomes tradable, so that a supplier that exceeds its minimum requirement or mandate can sell their excess certificates to those who need to purchase evidence of their obligation being met by other actors in the market. The suppliers of the certificates can, as a result, generate revenue from their activity.

Because these certificates are made tradable, they have a value that reflects the interplay of the certified supply of the required electricity, heat or transport fuel, and the demand for the certificates. This is liable to fluctuate and, therefore, as with other tradable schemes, this might not provide a sufficiently certain revenue stream for investors, unless a price floor is in place.

Note that this tends to work on the demand side for renewable electricity, heat or transport fuel, whereas other policy instruments supporting the price of energy outputs may affect supply. In principle, in an efficient market the greater the stimulus on the supply side, the lower the value of tradable certificates should fall on the demand side. The merit of a tradable obligation or mandate is that it can be designed to give certainty that a minimum level of supply will be in place, but it might not be so efficient in stimulating the investment needed to call forward additional supply (the problem of fluctuating year-to-year prices for certificates). It also helps indicate a regulator’s intent to deliver a minimum level of a form of renewable energy.

The UK used tradable certificates for electricity generation for many years. Its scheme placed an annual obligation on all electricity suppliers to present to Ofgem, the market regulator, a specified number of ROCs per MWh of electricity supplied to their customers during each obligation period of one calendar year. Suppliers could meet their annual obligation by presenting ROCs, making a payment into a buy-out fund, or a combination of the two. The buy-out fund reflected the fact that a buy-out price was set for ROCs so that they could not rise to unreasonable levels. ROCs were issued to operators of accredited renewable generating stations for the eligible renewable electricity they generated. Operators were entitled to trade ROCs with other parties or sell them directly to an electricity supplier; the supplier could also be the operator, effectively generating its own ROCs. AD was one of the technologies entitled to issue 2 ROCs for each unit of electricity generated, and this approach was used to stimulate some less common technologies (at the time) that faced greater challenges to generate electricity at a competitive price.

The Netherlands’ Energy for Transport compliance system is similar and ensures companies adhere to their annual obligations, including reducing GHG emissions. The objective of the Energy for Transport legislation and regulations is to increase the share of renewable energy (such as biofuels) in the transport sector and reduce GHG emissions from transport fuels. ⁴¹ The annual obligation is a mandatory share of renewable energy in a company’s fuel deliveries, which increases annually. The mandatory share will increase incrementally from 18.9% in 2023 to 28.0% in 2030. Companies have to hold sufficient HBEs (hernieuwbare brandstofeenheden), which are renewable energy units (1 GJ equivalent), to discharge their obligation. The obligation also sets out minimum and maximum proportions that must be met from different sources to support, for example, the use of feedstocks that are deemed more environmentally beneficial.

Ireland has been discussing a similar mechanism for heat – a Renewable Heat Obligation. ⁴² Under the obligation, an initial introductory rate of 2% is being considered, where all suppliers of more than 1,000 GWh of fossil fuel used for heat would be obliged to demonstrate that 2% of the energy they have supplied is from a renewable source. It is proposed that the annual rate under the obligation increases up to a final target level of 10% by 2030.

Renewable gas certificates are sold in the market by gas suppliers to show proof of compliance with obligations such as renewable energy or emission reduction targets and are purchased by organisations to demonstrate thier efforts to reduce carbon emissions voluntarily and make the appropriate claims in their regular reporting. Under the EU Renewable Energy Directive framework, a compliance market, there are two types of renewable gas certificates that regulate biomethane: Proof of Sustainability and Guarantee of Origin. ⁴³ These certificates promote capacity growth and use of sustainable supply chain practices such as low carbon feedstock.

3.3.6. General Considerations for Support Mechanisms

As noted above, for many types of biogas facilities, the certainty of the revenue stream used to ‘pay down’ capital investment is likely to be important. Therefore, the support mechanisms should consider how they can give certainty over a period of time that is adequate for funders to consider new capacity sufficiently attractive for investment.

In implementing a support mechanism, consideration has to be given to the source of the revenue that is the source of the support. Especially in countries where fiscal resources are more limited, generating revenues from existing suppliers is likely to be attractive. It may be relevant to consider means through which to protect lower-income consumers from any potential price increases if these are not already in existence (much depends on the expected change).

The different feedstocks to biogas-generating installations are generally associated with other potential revenue sources (not only from biogas). The more income that can be derived from these sources, the less need for support for biogas outputs, and vice versa. Some revenue streams and considerations about them are noted in Table 6. As other revenue streams increase, so the level of support required for biogas outputs might be reduced.

Table 6: Non-energy revenue sources on AD facilities

Feedstock	Other revenue sources and considerations	Challenges affecting other revenue sources
Manures, slurries or livestock wastes	Avoided costs of waste management Cost reduction due to compliance with environmental regulations For small scale AD plants: avoided energy use costs and pollution reduction from alternative energy sources.	Lack of awareness of full benefits There is no challenge as revenue will remain similar. Poor understanding of post-AD management opportunities.
Crop residues	Avoided costs of management	Light regulatory pressure may reduce incentives to process crop residues. Focused more on cost avoidance due to regulations compliance (i.e. emissions compliance) than on revenue generation.
Energy crops (grown for biogas generation)	High opportunity cost due to land use competition with conventional crops	Financial viability is tied to the market value of other potential crops.
Organic fraction of waste landfilled	Gate fees for waste disposal	Gate fee variability (depends on surplus or scarcity of organic material): energy sectors drive the costs of organic materials, and as a side effect, gate fees are charged where surplus organic fraction is available, and rebate fees are charged where low quantities of organic fractions are available. Where available gate fees are relatively high, and the income required from the sale of biogas does not need to be so high.
Segregated household or municipal solid waste	Gate fees for waste disposal	As mentioned previously, the energy sector can impact the feedstock cost. High gate fees may depend on strict waste laws (e.g., mandatory organic waste segregation). AD facilities compete with aerobic composting, which is usually cheaper if there is no biogas (products) support mechanism.
Homogeneous stream of industrial or food processing waste	Avoided costs of waste management Gate fee for waste disposal Avoided costs of energy use	Waste stream consistency and quality may affect revenues.
Sewage and sewage sludge	User fees (bills for wastewater treatment) Gate fees for waste disposal	It may be regulated by law: efforts to keep fees and bills low may necessitate more support for biogas. Wastewater treatment policies in some countries may favour less sustainable alternatives. Low organic matter content in sewage may increase disposal costs and discourage investments in AD.

Note: Issues related to CO₂capture are discussed below. In principle, all facilities of a reasonable scale could benefit from sales of captured CO₂ or certificates derived from CO₂ reduction.

For most forms of support for biogas outputs, with the likely exception of cases where microscale digesters are the target of support, eligibility may be linked to certification or accreditation of those outputs. Eligibility for support might be linked to the nature of the feedstock, for example. Under the EU’s Renewable Energy Directive, rules regarding what qualifies as renewable energy have been established, and these criteria are cross-referenced in the EU’s ETS. Sources of biomass and biogas that meet qualifying criteria are not required to surrender allowances for the purposes of emissions trading.

Certification of sources is especially important for tradable certificates, but also to ensure that forms of support are not fraudulently claimed. In the case of tradable certificates, typically, some form of certificate of origin is issued against certified sources of generation, giving confidence to a market for trading certificates; the holding of sufficient certificates is generally required to demonstrate compliance with an obligation.

There is interest in harmonising the systems of accreditation so that certificates may be recognised across borders: after all, gas is also transported across borders, so there may be increasing interest in demonstrating the renewable or carbon component of gas transferred across borders. This would require reaching an agreement about appropriate criteria, and while some criteria exist, that does not necessarily imply they are readily transferable. For example, setting standards for GHG savings against a fossil fuel counterfactual might begin to look less relevant in countries where fossil fuels play a diminishing role in the mix of power generation, now or in the future.

Finally, for those sources of biogas considered suitable for support, it may be worth policymakers considering whether there is additionality over and above what regulation requires, or might require in the future. For example, it might be argued that landfills should be operated either with suitable gas-collection systems, or with requirements to treat waste prior to landfilling, minimising the potential for methane generation once in the landfill. In such cases and, more generally, where regulation requires the installation of means to capture biogas (wastewater might be another example), then the argument for support for biogas outputs is likely to be somewhat weaker. This can be addressed by ‘weighting’ of support depending on the source of biogas.

3.4. Valuing the Climate Change Benefits of Biogas

Biogas can provide a clean energy source for high energy consumption areas such as high population density areas and industrial clusters as biogas plants can provide energy and heat at lower prices and offset the energy bills.

We noted above that most ETSs have not included methane emissions, although there are cases where landfill is included. Where the use of biogas enables a reduction in GHG emissions, then whether or not there is direct financial support for any emissions reduction should be considered in light of how competing activities are treated by existing policy.

In the case of power generation, for example, if fossil-fuel power generation is covered by ETSs, and if no allowances are issued free of charge to power generators, then it could be argued that GHG emissions are already ‘paid for’ by the power sector. For power generation, the incentive concerning emissions reduction arises from the avoided costs of purchasing allowances.

On the other hand, if landfill emissions are not internalised by ETSs, or if the wastewater treatment sector is not included within such a scheme, there is likely to be a case for incentivising emissions reduction that can arise from use of biogas.

Some schemes do allow for linked ‘offsets’ to be claimed by activities including biogas capture and use, including the California Cap and Trade scheme (methane emissions from livestock farms, rice cultivation and mining projects) ⁴⁴, and the Alberta Technology Innovation and Emission Reduction Offset system, which allows for the inclusion of emissions reduction from AD of wastewater and organic waste. It accounts for methane and nitrous oxide emissions. ⁴⁵ Evidently, in some circumstances policymakers might regulate for the capture and use of biogas, in which case the argument for including methane capture as a benefit might be weakened.

The argument for incentivising methane abatement in particular looks more pressing by the day. Various studies have considered the potential role of methane pricing as a means to deliver abatement. ⁴⁶ In the waste sector, reported emissions are generally based on modelling, and the calibration of existing models is difficult because emissions from a landfill today are linked to wastes deposited in the landfill over many years. Nonetheless, mechanisms to quantify emissions do exist. Under the Clean Development Mechanism (CDM), credits (certified emissions reductions, or CERs) have, for many years, been claimed for projects that avoid landfill methane emissions.

In addition, Article 6 of the Paris Agreement provides for parties to help achieve their nationally determined contributions (NDCs) through internationally transferred mitigation outcomes (ITMOs). These can take several forms, but they imply one party discharging its commitment to reduce emissions by paying for or facilitating reductions in net emissions by another party.

Various possibilities exist for valorising methane abatement, and the implications for the trajectory of emissions abatement and, therefore, global temperature rise should be a consideration. ⁴⁷ In principle, this focuses attention on how to express equivalence between CO₂ and methane, especially if an ETS includes both gases (or links their abatement). The use of GWP100 – the measure most often used to convert emissions of different GHGs into a ‘CO₂ equivalent’ – might not be the best choice in ETSs; it might be more relevant to consider the social costs of different emissions, including methane.

The relative social costs of methane and CO₂ do not generally reflect GWP100 (or GWP20) values. On the other hand, the social costs of methane are high, with figures ranging from $1,000 to $4,000 per tonne of methane. ⁴⁸

In the context of valuing methane abatement, the issue of gas capture from landfill sites is significant. Some measures to support biogas generation may include the capture of gas from landfills. However, even where gas is captured relatively well, fugitive emissions from landfills will likely remain non-trivial. The balance of support for gas capture, and ensuring polluters pay for continued emissions, are important considerations for policymakers in their approach to landfills. In jurisdictions where permits should require the capture of gas as far as is practicable, such as the EU, the additionality that gas capture systems provide seems questionable. The short-term impact of the remaining fugitive methane emissions is likely to come into stronger focus in the coming years. Standards must be used to mitigate leaks, which can have a detrimental effect on climate efforts, especially when taking GWP20 into account.

The growth of remote observations has emerged as a complementary information source for modelling and allowing to spot biased estimations and malfunctioning

3.5. Support for Conversion to Biogas

With waste management, it is often the case that garden or yard wastes are collected separately at sites where households ‘deliver in’ large quantities, which often leads to the development of aerobic composting infrastructure, often in the form of open-air windrows. If door-to-door separate collection systems are then offered for combined garden and food wastes, this can result in an evolution in the aerobic composting infrastructure so that enclosed aerobic systems are developed.

If the biowaste treatment infrastructure evolves in this way, and if, for example, collection systems become more focused on food waste, there may be an argument for capital support or soft loans for the conversion of facilities from aerobic composting to AD, not least where there is a clear opportunity to integrate an aerobic processing step post-digestion to support marketing the end-products (of digestion) beyond agriculture.

Support for the switching suggested above might be available without being specified as such (it might be less targeted); for example, there could be a more general form of capital support for this purpose, subject to eligibility rules. The countries using capital grants to support biomethane are identified in the next section.

3.6. Support for Gas Upgrading

In some instances, it might be considered that the basic configuration of a biogas-generating facility might not be worth supporting, but there may be specific reasons why policymakers seek to ensure greater use of biogas: not for electricity generation but for injection into the gas network or for biomethane to be used in transport. Here it might be appropriate to target support specifically at the gas upgrading infrastructure. In principle, this support could come in different forms, either by offering facility operators capital grants for implementing gas upgrading systems, or offering network operators support to implement gas upgrading systems at so-called hubs, in which case a suitable form of support to developers might be incentives to deliver biogas to the hubs.

EXAMPLE

Italy has a €1.7bn CAPEX investment support scheme covering 40% of investment costs to upgrade existing biogas plants to biomethane plants, and for building new plants. ⁴⁹

Portugal offers a CAPEX subsidy to biomethane developers funded by the EU Recovery and Resilience Facility (RRF) and the domestic Environment Fund (FA, or Fundo Ambiental). ⁵⁰

Spain has a €150m investment support scheme for biogas production, including upgrading to biomethane, based on tendering CAPEX support. A second round of CAPEX support is being developed. ⁵¹

3.7. Support for Micro- and Small- scale digesters

Some countries have sought to stimulate the generation of biogas at a highly decentralised level. The arguments for doing so may be particularly strong in areas where population densities are low, and where grid infrastructure – whether for natural gas or electricity – would be expensive to provide. Furthermore, in some situations, the alternative fuels used might have health and/or environmental consequences. It may also be the case that small-scale biogas facilities can, when appropriately configured, help address pollution issues related to manure.

A challenge for support schemes for decentralised biogas generation is that part of the rationale – the absence of grids – implies that a means of measuring the injected power, or biomethane, might not be readily available. That may mean, in turn, that the potential for using support mechanisms linked to biogas output is more limited. A challenge for policymakers is to ensure that the nature of support is sufficient to motivate action, but not wasteful; for example, facilities are built but not used effectively.

India has a National Biogas and Manure Management Programme (NBMMP) in place for setting up family-type biogas plants, and this has existed in some form since 1981–82.⁵² The goal of the NBMMP is to provide clean cooking fuel for kitchens, lighting and to meet other thermal and small-power needs of farmers, dairy farmers and other users, including individual households, and to improve organic manure management based on enabling the use of livestock waste as a fertiliser. The NBMMP also offers additional support for connecting sanitary toilets to biogas plants. A gender-related benefit is also acknowledged – the objectives include ‘to mitigate drudgery of women and time saving for them for other livelihood activities and reduce pressure on forests and accentuate social benefits’.

Although a national programme, implementation at state and sub-state level is important, and there are state targets for the number of biogas plants to be developed. The programme promotes the use of small, family-type biogas plants that use manure as feedstock, and it provides financial assistance including subsidies for construction costs, system repair and training. The upfront support for construction varies by the scale of the facility (1 cubic metre per day, 2–6 cubic metres per day, 8–10 cubic metres per day, 15 cubic metres per day; and 20–25 cubic metres per day), but also by the category of the state.

Government agencies use a monitoring system to report the results of field inspections and independent agency study evaluations of biogas plant functionality. There are also dedicated Biogas Development and Training Centres (BDTCs) for training purposes.

3.8. Green Investment

There has been a growing interest in greening the financial system, and various criteria have been developed for determining whether or not an investment might be considered ‘green’, or not; supporting this evolution is the interest in greater transparency in financial reporting. This reflects the growing demand in the investor community, including citizens, for reassurance that their investments are helping solve, rather than contributing to, environmental problems.

Examples of criteria that are shaping discussions about which investments are green are those established by the Climate Bonds Initiative. This indicates activities that are eligible for certification for Green Bonds and the criteria that apply to them.

In Europe, the EU taxonomy for sustainable activities is a classification system established to clarify which economic activities are environmentally sustainable, in the context of the European Green Deal. The Taxonomy Regulation establishes a framework for assessing the contribution of activities to sustainability, ⁵³ and additional acts determine the conditions under which specific activities may be considered to contribute to aspects of sustainability. For example, a delegated regulation includes consideration of when AD of waste might ‘contribute substantially’ to the transition to a circular economy. ⁵⁴

These criteria can be important in signalling to investors those activities that are better aligned with a more sustainable future. To the extent that investors may be willing to accept lower rates of return in exchange for the knowledge that their investments are green, this could support, for example, improved terms for debt financing of accredited projects, including biogas. There have been green bond issuances that include biogas; for example, from Hera in Italy⁵⁵, and from the Swedish municipality of Gothenburg. ⁵⁶

3.9. Innovation funding

In principle, there are a range of activities that could be supported by governments and by private industry in the spirit of innovation support. Innovation funds are not always targeted at specific activities, and so the case for support for innovation in relation to biogas may need to be made either in the context of a more general programme of support, or through appeal to the commercial potential. The ways and means to support such innovation through research and development are many and varied, and not specific to biogas. For example, specific sectoral interest may lie, however, in one or more of:

speeding up the digestion process (at a given temperature)
increasing the conversion of substrate to biogas
reducing energy requirements in the process
reducing the costs of (and increasing efficiency of) phosphorous recovery from outputs
minimising GHG emissions post-digestion
optimising the costs of capture and storage of CO₂ from gas upgrading.

3.10. Support for Carbon Capture, Use and Storage at AD plants

When biogas is upgraded, an essential part of the process is the separation of CO₂ from the biogas mix. In principle, CO₂has value in industrial applications, and in future, it may become a building block for chemical synthesis, including bio-derived plastics. Other possibility include bioenergy with carbon capture and storage (BECCS).

Although there are approaches that have developed in voluntary markets, the focus of some policymakers – for example, in the EU – is more strongly focused on permanent removals of CO₂ (carbon dioxide removal, or CDR).⁵⁷The substitution of CO₂ in industrial applications is less strongly supported, principally because the removal of CO₂ is not considered permanent. This reflects, in part, recent concerns about the permanence of the CO₂ storage to which voluntary credits have been attached. It might follow that unless the captured CO₂ is being transported for permanent storage, such benefits might not be available. The value to businesses of using CO₂ from biogas is likely to relate partly to its lower-carbon source (lower than, for example, when the source is the fertiliser industry, one of whose principal feedstocks is natural gas).

At larger biogas installations, and especially where biogas combustion occurs on-site (in which case, the energy carrying methane is converted to CO₂), the flow of CO₂ might be high enough (or costs may fall over time) to justify the installation of carbon capture infrastructure at a given site. The case for this is likely to depend on the value attributed to CO₂ removals, and this will depend on how quickly, and on what terms, markets emerge for CDR, potentially linked to the various ETSs in place around the world.

3.11. Policy Towards Incineration

Note that a specific feature of some facilities that generate energy from mixed residual waste – notably, incineration and other thermal treatments (including co-incineration) – is that they themselves have often been considered to be a source of renewable energy, even though much of the energy generated is from fossil-derived materials, such as plastics. Another way of looking at this is that each unit of energy derived from a renewable (non-fossil) source is accompanied by one which is non-renewable and has a high carbon intensity.

Where such facilities benefit from price support for the renewable energy delivered, the cost of managing residual waste is kept artificially low. The same effect is observed where, for example, domestic heating fuels are taxed, but heat from waste incineration is untaxed (a good example of this is in Sweden), which undermines the case for segregating wastes suitable for biogas generation, such as food waste. This is especially unfortunate as some evidence suggests that, especially in commercial settings (such as kitchens, canteens, restaurants), introducing the segregation of food waste has a sensitising effect that can bring greater focus to food waste prevention, for which climate-related benefits are particularly significant.

Several countries have introduced systems that apply taxes to incineration: Denmark’s tax is linked to fossil-derived CO₂ emissions, and both the EU and the UK have indicated they are likely to include incineration within their ETS in the near future (some facilities are already included in the EU scheme). The effect of this should be to rebalance the situation that existed before when incinerators were, in many countries, beneficiaries of an implicit subsidy, i.e. they were exempted from the application of a policy that should have applied to them.

Note also that in some developing countries, new incinerators are being ‘banked’ based on guarantees from governments that these facilities will benefit from inflated prices; for example, for electricity. This effectively creates, or exacerbates, an existing market failure rather than resolving it.

FOOTNOTES

In particular, preventing waste is important, so making the treatment of waste ‘too cheap’, or ‘too profitable’ can reduce the case for preventing it in the first place.
“Green Gas Support Scheme (GGSS): open to applications”, UK Government. https://www.gov.uk/government/publications/green-gas-support-scheme-ggss
“Landfill Tax: increase in rates”, UK Government. https://www.gov.uk/government/publications/landfill-tax-rates-for-2025-to-2026/landfill-tax-increase-in-rates
“Proposals to expand the UK Emissions Trading Scheme”, UK Government. https://www.gov.uk/government/news/proposals-to-expand-the-uk-emissions-trading-scheme
“Biodegradable municipal waste landfill ban”, Scottish Environment Protection Agency (SEPA). https://www.sepa.org.uk/regulations/waste/landfill/biodegradable-municipal-waste-landfill-ban
“Emissions reduction plan: Chapter 15-Waste”, New Zeeland. https://environment.govt.nz/publications/aotearoa-new-zealands-first-emissions-reduction-plan/waste
https://www.ieabioenergy.com/wp-content/uploads/2021/07/Potential-utilization_WEB_END_NEW.pdf; https://www.ieabioenergy.com/wp-content/uploads/2018/08/anaerobic-digestion_web_END.pdf; https://www.ieabioenergy.com/wp-content/uploads/2018/08/anaerobic-digestion_web_END.pdf
https://www.globalmethane.org/expo-docs/china07/postexpo/ag_li.pdf
https://www.unep.org/resources/report/global-methane-assessment-benefits-and-costs-mitigating-methane-emissions; Duren, R., et al. ‘California’s methane super-emitters’, Nature, 2019, 575, 7781, doi: 10.1038/s41586-019-1720-3; See also Carrington, D., Clarke, S. ‘Revealed: The 1,200 Big Methane Leaks from Waste Dumps Trashing the Planet’, The Guardian, 12 February 2024. https://www.theguardian.com/environment/2024/feb/12/revealed-the-1200-big-methane-leaks-from-waste-dumps-trashing-the-planet
https://www.epa.gov/system/files/documents/2023-10/food-waste-landfill-methane-10-8-23-final_508-compliant.pdf; Wilson, D.C., Filho, C.S., Ramola, A. ‘The Significant Potential of Better Waste and Resource Management for Climate Mitigation’, Waste Management World, 27 November 2023; https://www.worldbiogasassociation.org/wp-content/uploads/2019/09/WBA-globalreport-56ppa4_digital-Sept-2019.pdf; https://www.unep.org/resources/global-waste-management-outlook-2024.
Pendrous, P. ‘Balmenach distillery installs £3M anaerobic digestion plant’, Food Manufacture, 10 January 2018. https://www.foodmanufacture.co.uk/Article/2018/01/03/Distillery-installs-3M-anaerobic-digestion-plant
https://task37.ieabioenergy.com/wp-content/uploads/sites/32/2022/02/Wastewater_biogas_grey_web-1.pdf
Klawitter, N. ‘Biogas Subsidies in Germany Lead to Modern-Day Land Grab’, Der Spiegel, 30 August 2012. http://www.spiegel.de/international/germany/biogas-subsidies-in-germany-lead-to-modern-day-land-grab-a-852575.html; Searchinger T., Heimlich R., Houghton R.A., Dong F., Elobeid A., Fabiosa J., Tokgoz S., Hayes D., Yu T.-H. Use of U.S. Croplands for Biofuels Increases Greenhouse Gases Through Emissions from Land-Use Change. Science, 2008, 319: 1238–1240. https://doi.org/10.1126/science.1151861.
In Denmark, there is a cap on the use of energy crops for biogas production. Hence: ‘Already in 2022, the energy crop cap will be lowered from 12% to 8%. By 2024, it will be lowered even further to an expected 4%. The use of maize as an energy crop will also be phased out by 2025.’ https://ens.dk/sites/ens.dk/files/Naturgas/groen_gasstrategi_en.pdf
https://foe.org/wp-content/uploads/2024/03/Factory-Farm-Gas-Brief_final.pdf
See Gustafsson, M., Anderberg, S. ‘Great Expectations – Future Scenarios for Production and Use of Biogas and Digestate in Sweden’, Biofuels, 14(1), 2023, 93–107 https://doi.org/10.1080/17597269.2022.2121543; Klackenberg, L. “Biomethane in Sweden – market overview and policies”, Energiegas Sverige, 27 March 2024. https://www.energigas.se/Media/1ernoznh/biomethane-in-sweden-240327.pdf.
In the UK, for example, the early focus of price support was for electricity production. Twenty years ago, landfill gas was one of the main sources of renewable power in the UK. Over time, as other sources have contributed to power generation (notably wind and solar), the nature of price support has shifted towards heat.
This can make decisions about how best to use biogas somewhat more complicated. For example, if methane in biogas can be converted at around 40% efficiency to power, then if an air-source heat pump is used to convert electricity to heat with a seasonal coefficient of performance above 2.5, the electricity source might deliver the same amount of heat, or more, as using the cleaned gas directly. Other issues, such as ease of storage, and ease of conversion of existing heating systems, may play a role in decision-making.
Useful insights into the development of these can be found in Speck, S., Skou Andersen, M., Nielsen, H.O., Ryelund, A., and Smith, C., “The Use of Economic Instruments in Nordic and Baltic Environmental Policy 2001–2005”, TemaNord, 2006, 525, Nordic Council of Ministers, Denmark. https://doi.org/10.6027/TN2006-525; and Speck, S. “The Design of Carbon and Broad-Based Energy Taxes”, Vermont Journal of Environmental Law, 2008, 10, 2008, 31–59. https://www.jstor.org/stable/vermjenvilaw.10.1.31; “The Use of Economic Instruments in Nordic Environmental Policy 2010–2013”, Nordic Council of Ministers, 2014. http://www.copenhageneconomics.com/dyn/resources/Publication/publicationPDF/2/262/0/The%20Use%20of%20Economics%20Instruments%20in%20Nordic%20Environmental%20Policy%202010-2013.pdf.
Council Directive 2003/96/EC of 27 October 2003 Restructuring the Community Framework for the Taxation of Energy Products and Electricity, European Union. http://data.europa.eu/eli/dir/2003/96/oj.
“Monitoring and reporting regulation”. European Union. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A02018R2066-20240701
“Problems in the Reporting of GHG Emissions from ‘Waste’: Indicators and Inventories”, Equanimator. https://static1.squarespace.com/static/5fac6c36040eba5dc1b46766/t/6231d1ed6897d337f4c4637e/1647432173757/Problems+in+Reporting+GHGs+from+Waste_final.pdf
Directive 2003/87/EC of the European Parliament and of the Council of 13 October 2003 establishing a system for greenhouse gas emission allowance trading within the Union. https://eur-lex.europa.eu/eli/dir/2003/87/oj; UK Government, the Scottish Government, the Welsh Government and the Department of Agriculture, Environment and Rural Affairs for Northern Ireland (2024) UK Emissions Trading Scheme Scope Expansion: Waste, May 2024, https://www.gov.uk/government/consultations/uk-emissions-trading-scheme-scope-expansion-waste.
Note that ownership and price regulation of utilities varies considerably across the world.
In the study, the definition of ‘subsidy’ followed the World Trade Organization (WTO) Agreement on Subsidies and Countervailing Measures, including four categories: (i) government measures involving the direct transfer of funds; (ii) government revenue that is otherwise foregone (not collected); (iii) governments providing goods and services or purchasing goods; and (iv) price and income supports (see “2022 Report on Energy Subsidies in the EU”, European Commission. https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52022DC0642).
Black, S., Liu, A., Parry, I., Vernon-Lin, N. “IMF Fossil Fuel Subsidies Data: 2023 Update”, Working paper, IMF, 24 August 2023. https://www.imf.org/en/Publications/WP/Issues/2023/08/22/IMF-Fossil-Fuel-Subsidies-Data-2023-Update-537281.
This can be contrasted with a variable premium that might be adjusted to close the gap between a reference price and the fluctuating market price. This is covered under ‘contracts-for-difference’.
Memo on the Danish Support Scheme for Electricity Generation Based on Renewables and Other Environmentally Benign Electricity Production, Danish Energy Agency. https://ens.dk/sites/ens.dk/files/contents/service/file/memo_on_the_danish_support_scheme_for_electricity_generation_based_on_re.pdf
Biomethane in Sweden: Market Overview and Policies”, Energigas Sverige. https://www.energigas.se/Media/1ernoznh/biomethane-in-sweden-240327.pdf
For example, a switch in emphasis from electricity to biogas for heating might lead to some support being considered for investment in gas upgrading, unless that upgrading happens at dedicated hubs (in which case, there may be a case for relevant support to the transport of biogas).
Renewable Energies: Feed-in Tariffs, Klima Agence. https://klima-agence.lu/en/renewable-energies-feed-in-tariffs
Feed-in Tariff, Sustainable Energy Development Authority, Malaysia. https://www.seda.gov.my/reportal/fit/.
FiT Rates, Sustainable Energy Development Authority, Malaysia. http://www3.seda.gov.my/iframe/.
Green Gas Support Scheme, UK Department for Energy Security & Net Zero. https://www.ofgem.gov.uk/publications/green-gas-support-scheme-tariff-table
Biomethane Subsidy, Estonia. https://elering.ee/en/biomethane-subsidy#:%7E:text=The%20eligibility%20period%20for%20the,is%2038%20489%20000%20%E2%82%AC. Note that the scheme was due to come to an end at end of 2023 if the available funds had been fully used.
“Contracts for Difference: the Instrument of Choice for the Energy Transition”, Oxford Institute for Energy Studies. https://www.oxfordenergy.org/wpcms/wp-content/uploads/2024/04/ET34-Contracts-for-Difference.pdf
“New Incentives for the Biomethane Sector”, Dentons. https://www.dentons.com/en/insights/guides-reports-and-whitepapers/2022/november/14/new-incentives-for-the-biomethane-sector
“Biomethane Incentives and Their Effectiveness”, Biomethane Industrial Partnership. https://bip-europe.eu/wp-content/uploads/2024/04/BIP-TF1_Biomethane-incentives-and-their-effectiveness-Final.pdf
https://www.iea.org/reports/denmark-2023/executive-summary
“Government Announces Mandatory Blending of Compressed Bio-Gas”, Ministry of Petroleum & Natural Gas, India. https://pib.gov.in/PressReleaseIframePage.aspx?PRID=1979705
Obligations: Renewable Energy for Transport 2022–2030, Dutch Emissions Authority. https://www.emissionsauthority.nl/topics/obligations—renewable-energy-for-transport
Design of the Renewable Heat Obligation: Public Consultation, Department of the Environment, Climate and Communications, Ireland. https://consult.decc.gov.ie/en/content/design-renewable-heat-obligation-public-consultation
Renewable Energy Directive . European Union https://eur-lex.europa.eu/eli/dir/2018/2001/oj
Compliance Offset Protocols, California Air Resources Board. https://ww2.arb.ca.gov/our-work/programs/compliance-offset-program/compliance-offset-protocols.
“Quantification Protocol for Biogas Production and Combustion”, Government of Alberta. https://open.alberta.ca/dataset/e4dadabf-2c60-4cba-8182-2d1f5e360e86/resource/32eba277-cb6d-4615-90c1-86c7f264c63c/download/aep-quantification-protocol-for-biogas-production-and-combustion.pdf
“Global Methane Assessment”, UNEP and CCA, 2021. https://www.ccacoalition.org/sites/default/files/resources/2021_Global-Methane_Assessment_full_0.pdf; Parry, I., Black, S., Minnett, D., Mylonas, V., Vernon-Lin, V. “How to Cut Methane Emissions. Staff Climate Note”, IMF, 31 October 2022. https://www.imf.org/en/Publications/staff-climate-notes/Issues/2022/10/28/How-to-Cut-Methane-Emissions-525188#:~:text=Putting%20a%20price%20on%20methane,polluters%20to%20subsidize%20cleaner%20producers.
See Allen, M., Tanaka, K., Macey, A., Cain, M., Jenkins, S., Lynch, L., Smith, M. “Ensuring that Offsets and Other Internationally Transferred Mitigation Outcomes Contribute Effectively to Limiting Global Warming”, Environ. Res. Lett. 2021, 16, 074009. https://doi.org/10.1088/1748-9326/abfcf9
See, for example, Azar, C., García Martín, J., Johansson, D. JA., Sterner, T. “The Social Cost of Methane”, Climatic Change, 2023, 176, 71. https://doi.org/10.1007/s10584-023-03540-1; Errickson, F. C., Keller, K., Collins, W. D., Srikrishnan, V., Anthoff, D. “Equity is More Important for the Social Cost of Methane than Climate Uncertainty”, Nature, 2021, 592: 564–570. https://doi.org/10.1038/s41586-021-03386-6; “Global Methane Assessment”, UNEP and CCA, 2021. https://www.ccacoalition.org/sites/default/files/resources/2021_Global-Methane_Assessment_full_0.pdf; “Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances”, US EPA. https://www.epa.gov/environmental-economics/scghg; Wang, T., Teng, F. “Damage Function Uncertainty Increases the Social Cost of Methane and Nitrous Oxide”, Nature Climate Change, 2023, 13, 11, 1258–1265. https://doi.org/10.1038/s41558-023-01803-4.
Press Release – 8 August 2022. European Commission. https://ec.europa.eu/commission/presscorner/detail/en/ip_22_4803?utm_source=chatgpt.com
“Portugal’s recovery and resilience plan”. European Commission. https://commission.europa.eu/business-economy-euro/economic-recovery/recovery-and-resilience-facility/country-pages/portugals-recovery-and-resilience-plan_en?utm_source=chatgpt.com
Boletin Oficial del Estado – 26 July 2022. Gobierno de España. https://www.boe.es/boe/dias/2022/07/26/pdfs/BOE-A-2022-12470.pdf
See National Biogas and Manure Management Programme, Government of India. https://ukrdd.uk.gov.in/wp-content/uploads/2020/07/Bio-gas-Guidline.pdf, and Ministry of New and Renewable Energy FAQs, Government of India https://mnre.gov.in/faq/.
Regulation (EU) 2020/852 of the European Parliament and of the Council of 18 June 2020 on the establishment of a framework to facilitate sustainable investment, and amending Regulation (EU) 2019/2088. https://eur-lex.europa.eu/eli/reg/2020/852/oj
Commission Delegated Regulation (EU) 2023/2486, supplementing Regulation (EU) 2020/852 of the European Parliament and of the Council. https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=OJ:L_202302486
“Italian Utility Hera issues EUR 500m, BBB, 10 yr green bond to kickstart the Italian market”, Climate Bonds Initiative https://www.climatebonds.net/2014/07/italian-utility-hera-issues-eur-500m-bbb-10-yr-green-bond-kickstart-italian-market-%E2%80%93-and-i-0
“Gothenburg Green Bonds” UNCC. https://unfccc.int/climate-action/momentum-for-change/financing-for-climate-friendly/gothenburg-green-bonds
In Europe, the European Parliament and the Council of the EU reached a provisional agreement in February 2024 on the Carbon Removals Certification Framework, an EU-wide voluntary framework for certifying carbon removals. Note that this is not a ‘law’, but a framework for what are currently voluntary trades. However, this might be a precursor to inclusion of CDRs in the European Union’s ETS.

COOKIE POLICY |. PRIVACY POLICY

Pillar 3: Biogas Utilisation

CONTENTS

Pillar 3: Biogas Utilisation

Executive Summary

PILLAR 3: Biogas Utilisation

Introduction

3.1. Overarching Considerations

EXAMPLES

The United Kingdom has used various schemes to support biogas over the years 2, but it also has a landfill tax of over £100 per tonne. 3 It plans to bring incineration within the scope of its ETS. 4

By the end of 2025, Scotland will implement a ban on biodegradable municipal waste in landfills, with England expected to follow by 2028. 5

Hamilton City Council (New Zealand) aims to reduce the amount of waste each person sends to landfills by 10% by 2024. 6

3.2. Energy/GHG-Related Taxes and Levies

EXAMPLES

This approach can be found in Nordic countries. 19

Under the EU Emissions Trading Scheme (ETS), biomethane is assigned as zero emission factor under the monitoring and reporting rules (MRR). 21

3.3. Policies to Support Renewable Energy and Fuels

3.4. Valuing the Climate Change Benefits of Biogas

3.5. Support for Conversion to Biogas

3.6. Support for Gas Upgrading

EXAMPLE

Italy has a €1.7bn CAPEX investment support scheme covering 40% of investment costs to upgrade existing biogas plants to biomethane plants, and for building new plants. 49

Portugal offers a CAPEX subsidy to biomethane developers funded by the EU Recovery and Resilience Facility (RRF) and the domestic Environment Fund (FA, or Fundo Ambiental). 50

Spain has a €150m investment support scheme for biogas production, including upgrading to biomethane, based on tendering CAPEX support. A second round of CAPEX support is being developed. 51

3.7. Support for Micro- and Small- scale digesters

3.8. Green Investment

3.9. Innovation funding

3.10. Support for Carbon Capture, Use and Storage at AD plants

3.11. Policy Towards Incineration

FOOTNOTES

Pillar 3:
Biogas Utilisation

The United Kingdom has used various schemes to support biogas over the years ², but it also has a landfill tax of over £100 per tonne. ³It plans to bring incineration within the scope of its ETS. ⁴

By the end of 2025, Scotland will implement a ban on biodegradable municipal waste in landfills, with England expected to follow by 2028.⁵

Hamilton City Council (New Zealand) aims to reduce the amount of waste each person sends to landfills by 10% by 2024. ⁶

This approach can be found in Nordic countries.¹⁹

Under the EU Emissions Trading Scheme (ETS), biomethane is assigned as zero emission factor under the monitoring and reporting rules (MRR). ²¹

Italy has a €1.7bn CAPEX investment support scheme covering 40% of investment costs to upgrade existing biogas plants to biomethane plants, and for building new plants. ⁴⁹

Portugal offers a CAPEX subsidy to biomethane developers funded by the EU Recovery and Resilience Facility (RRF) and the domestic Environment Fund (FA, or Fundo Ambiental). ⁵⁰

Spain has a €150m investment support scheme for biogas production, including upgrading to biomethane, based on tendering CAPEX support. A second round of CAPEX support is being developed. ⁵¹