1. Background to the RFNBO “GHG savings” requirements
In our previous article, When is H2 = RFNBO, we examined the criteria to be met for e-fuels (in particular, green hydrogen and its derivatives) to be classified as a renewable fuel of non-biological origin (RFNBO) under the European Union’s (EU) directive on renewable energy (RED II1) and the Delegated Acts2. The importance of the RFNBO designation is that the fuel would then count towards the minimum targets for renewable fuels in the EU in order to meet the EU’s mandatory carbon reduction targets.
The targets for RFNBOs in the transport sector were increased through the Revised Renewable Energy Directive (RED III, also known as the “Fit for 55” package)3 which also created targets for usage of RFNBOs in other sectors (including the iron, steel, aluminium, chemicals, fertiliser, cement and construction industries). Part of the criteria for RFNBOs under RED II requires “the greenhouse gas emissions savings from the use of [RFNBOs to be] at least 70%“4 compared to the fuels being replaced.
The Second Delegated Act established the methodology to be used by e-fuel producers to calculate the greenhouse gas (GHG) emissions used in the entire production process, in order to ascertain if the abovementioned GHG savings are achieved.
2. The impact of incorporated CO2 on the GHG savings of an RFNBO
E-fuels such as e-methanol, e-methane and e-kerosene (for use in the production of SAF) are synthetic fossil fuels which blend clean hydrogen with captured CO2 emissions. These e-fuels will be important in decarbonising the transportation sector. Although combustion of e-fuels in their end-user applications will emit carbon at much the same rate as conventional fossil fuels, those emissions can be seen as not adding anything further to the CO2 that would have been emitted into, or existed in, the atmosphere if it had not been captured to make the e-fuel. For example, to the extent that the “same” CO2 is captured from an industrial process and then incorporated into an e-fuel, the capturing process can be regarded as one in which emissions have been “avoided”, thereby reducing the overall amount of GHG emissions arising from that industrial process plus the end-use to which the e-fuel (that would otherwise have used fossil fuel) is put.
The Second Delegated Act imposes limitations on the permitted sources of CO2 to be incorporated into an e-fuel to attain such a CO2-neutral classification (such permitted deducted emissions being the Avoided CO2 Emissions).
For e-fuel producers seeking to obtain RFNBO status, it is therefore of critical importance that the CO2 being used in the production of the e-fuel can qualify as an Avoided CO2 Emission in order to obtain the required 70% GHG emission saving.
3. What are Avoided CO2 Emissions?
As set out above, the basic principle is simple enough, but in turning it into regulation – which, if complied with, will enable producers to attract subsidies or charge a green premium – legislators have to tread carefully to try to avoid creating perverse incentives for what might be environmentally unhelpful behaviour.
Accordingly, the Second Delegated Act begins straightforwardly enough by defining the following as being sources of Avoided CO2 Emissions5: Emissions from “existing use or fate” that are avoided when the input is used for fuel production. However, after that, it gets more complicated.
These emissions would have been released as CO2 into the atmosphere in any event prior to their capture and incorporation into the e-fuel6, and are eligible provided that the CO2 is sourced from one of the following pathways:
a. CO2 which has been:
(i) captured from specified industrial activities listed under Annex I to the EU ETS7 (e.g. oil refining, steel, cement, certain combustion installations) (Specified Industrial Source);
(ii) accounted for under an effective carbon pricing system (e.g. by paying a carbon tax or surrendering an emissions allowance); and
(iii) incorporated in the e-fuel prior to 1 January 2041 (or 1 January 2036 for CO2 from fuel combustion for electricity generation);
b. CO2 which has been captured from the air (e.g. through direct air capture technology);
c. CO2 which has been captured from the production or the combustion of biofuels, bioliquids or biomass fuels:
(i) complying with the sustainability and GHG saving criteria under RED II; and
(ii) where the CO2 captured did not receive credits for emissions savings from CO2 capture and replacement under RED II;
d. CO2 which has been captured from the combustion of RFNBOs or e-fuels complying with their own GHG savings criteria (i.e. recycling the same RFNBO-eligible CO2); or
e. CO2 which has been captured from a geological source of CO2 where the CO2 was previously released naturally (e.g. volcanic emissions or geothermal fields).
In addition:
a. the CO2 must not be derived from combustion of a fuel deliberately for production of CO2; and
b. the captured CO2 must not have received any emissions credit under “other provisions of the law” (to avoid double-counting).
4. Considerations
a. CO2 captured from industrial sources
Any CO2 that is captured from a Specified Industrial Source must have been taken into account through an effective carbon pricing system, which would either be under the EU ETS (for EU domiciled industries), CBAM (for non-EU industries) or other state or national carbon pricing systems considered “effective”.
(i) EU ETS: The European Union Emissions Trading System (ETS) generally requires certain affected industries located in the EU to purchase and/or trade emissions allowances in order to cover their CO2 emissions in the applicable year.
Whilst the EU ETS does not require emissions allowances to be surrendered for CO2 that is captured for permanent storage, or for utilisation in such a way that it becomes permanently chemically bound (or mineralised), this exemption would not apply to CO2 being sold for e-fuel production given that the incorporated CO2 will be released on combustion of the e-fuel as noted above. An industrial producer would therefore still have to surrender emissions allowances or purchase allowances in respect of captured CO2 that is intended for onward sales.
Therefore, the cost of the CO2 being supplied will likely pass through the cost of the ETS allowances that will need to be surrendered/purchased in order to cover the captured CO2.
CO2 from Specified Industrial Sources may therefore be more expensive than CO2 captured from other permitted sources. The time limitations on CO2 from Specified Industrial Sources being an eligible Avoided CO2 Emission8 will also impact its long-term viability as a source of CO2 for e-fuel production.
(ii) CBAM: The European Union Carbon Border Adjustment Mechanism (CBAM), commencing in 2026, requires importers into the EU of certain carbon intensive goods (e.g. cement, aluminium, steel) produced outside the EU to pay for the carbon emissions associated with the production of such goods (to the extent not already paid for). The price to be paid is generally determined as the price of the emissions allowances that would have been required under the EU ETS had such goods been produced in the EU.
In theory, CO2 from Specified Industrial Sources could be imported into the EU for the production of e-fuels. However, CBAM does not currently apply to pure CO2, meaning that any imported CO2 from industry could not satisfy the requirement for such CO2 to have been accounted for unless (a) the jurisdiction of production has equivalent carbon pricing rules pursuant to which the imported CO2 would have been accounted for in its country of origin or (b) the output of the industrial process which emitted the CO2 (e.g. the aluminium or steel) was itself accounted for under CBAM on importation to the EU.
b. CO2 captured from biogenic sources
CO2 captured from the production or combustion of biofuels, bioliquids or biomass fuels (Biogenic Products) will qualify as an Avoided CO2 Emission if the Biogenic Product produced or combusted:
(i) complies with the relevant sustainability and GHG emission savings criteria for such renewable fuels under RED II; and
(ii) did not receive any previous emissions credits.
The use of CO2 from biogenic sources is proving to be the most popular pathway, which may be driven by the fact that the majority of biogenic sources of CO2 are not subject to the temporal restrictions and carbon pricing considerations applicable to Specified Industrial Source CO2.
There are, however, many biogenic production pathways for CO2 and each pathway would need to be carefully considered on a case-by-case basis to ascertain if the resulting CO2 could qualify as an Avoided CO2 Emission, which would include analysis on the source of the biogenic material being used as a feedstock, how it is processed and for what the end product is to be used.
A few example biogenic pathways, and the regulatory considerations that would apply, are set out in the Annex to this article.
c. CO2 from direct air capture
Capturing CO2 from the atmosphere using direct air capture (DAC) technology certainly appears to be the most straightforward pathway to Avoided CO2 Emissions from a regulatory perspective. However, due to the current costs of this technology coupled with the lack of policy incentives to use it, developers may be less likely to pursue this pathway. DAC technology is also more power-intensive for each unit of CO2 captured, which may need to be considered in the overall GHG savings calculation and may limit such technology to locations with availability of hydro or geothermal power.
5. Final remarks
It is critical for e-fuel producers to ensure that CO2 incorporated into the e-fuel is an Avoided CO2 Emission.
As indicated above, there are many production pathways, but each one may have financial, technical, environmental or other constraints which will need to be analysed to ascertain which pathway will be optimal for each individual project.
This will involve careful consideration of the technical, commercial and legal landscape applicable to the relevant CO2 supply chain and the robustness of the GHG emissions modelling of the full production and transportation chain which will be required to ensure that all relevant GHG emission reduction targets are capable of being met.
The complexities involved here, whilst not a roadblock to e-fuel production, may make it more difficult for the RED III targets to be achieved given the need for developers to expend time and cost to navigate these regulatory requirements.
ANNEX
Sample Biogenic CO2 Pathways
| No. | CO2 Production Pathway | Description | Avoided CO2 Emission Requirements | Notes |
| 1 | Biomethane Production | Biomethane is typically used as a renewable replacement for natural gas (which can be injected into natural gas grids) or, alternatively, it can be used for transport fuel. The production of biomethane involves the anaerobic digestion of biomass to produce biogas which is then separated into biomethane and biogenic CO2. The CO2 can therefore be captured and sold/used for e-fuel production. | Captured CO2 from this process could constitute Avoided CO2 Emissions under section 3(c) of this Article; CO2 captured from the production of a biomass fuel provided that: (a) the biomethane produced complies with the applicable RED II sustainability and GHG saving criteria; and (b) in calculating whether the produced biomethane meets the GHG saving criteria, the captured CO2 emissions are accounted for. | The RED II sustainability criteria to be complied with will depend on: (a) whether any sustainability criteria apply. Note that only certain biomass fuels are required to fulfil the sustainability and GHG saving criteria under RED II. An example is if the installation producing the fuel has a specified average biomethane flow rate; (b) If the criteria are to be complied with then the specific criteria will depend on the type of biomass that is being used in the anaerobic digestion process (i.e. the feedstock). RED II contains different sustainability requirements depending on whether the biomass being used is agricultural biomass (including aquaculture and fisheries) or forestry biomass. If the biomass feedstock does not fall into either of these categories than only the GHG savings criteria need to be complied with. The GHG saving criteria to be obtained from the use of the biomethane will depend on how it is to be used (the overall GHG saving must be at least 65% if consumed in transport and between 70% and 80% if used for electricity, heating or cooling (depending on the total thermal rated input of the facility and the year in which such facility commenced operations)).( |
| 2 | Ethanol Production | Bio-ethanol is produced through the fermentation of starch rich crops (e.g. corn, sugarcane, wheat). Bio-ethanol can be used as a biofuel (i.e. a liquid fuel for transport produced from biomass). It is commonly used to replace petrol. As the fermentation process releases large amounts of CO2, this CO2 can be captured and sold/used for e-fuel production. | Captured CO2 from this process could constitute Avoided CO2 Emissions under section 3(c) of this Article; CO2 captured from the production of a biofuel provided that: (a) the ethanol produced complies with the applicable RED II sustainability and GHG saving criteria; and (b) in calculating whether the produced ethanol meets the GHG saving criteria, the captured CO2 emissions are accounted for. | (a) The sustainability criteria under RED II that apply to food and feed crops will apply here. Notably, RED II places limitations on the amount of biofuels, bioliquids and biomass fuels produced from food/feed crops that can be counted towards the EU’s decarbonisation targets. This is because production of these fuels present a risk of land use change (from food production to biofuel production). By 2030, biomass fuels produced from food or feed crop with high indirect land use change risk cannot contribute to the EU’s renewable energy targets. As such, in order for biofuels made from food or feed crop to contribute to the EU’s renewable energy target (subject to the mandated cap), they must be certified as “low indirect land use change risk”. Obtaining this certification requires the feedstock to have, amongst other things, been produced in a sustainable manner which avoids the displacement effect of food and feed crop based fuels. (b) The required GHG saving from the use of biofuels in the transport sector is 65%. |
| 3 | Combustion of municipal waste to produce electricity in facilities with a total thermal rated input exceeding 20 MW | Waste to energy plants can burn municipal solid waste, including the biomass portion of such waste. Burning the waste releases heat, which converts water to steam. The steam is then used in a turbine generator to produce electricity. | Under regulatory consideration. | Waste to energy facilities of this size are currently covered by the EU ETS for monitoring and reporting purposes only (meaning that, whilst such CO2 emissions have to be reported, they do not currently need to be covered by ETS allowances). The legislative rationale for this approach, as set out in the EU ETS, is to enable the Commission to consider the reported data by 31 July 2026 to ascertain whether the scope of the EU ETS should be expanded to cover incineration of municipal waste from 1 January 2028 and whether member states should be able to “opt out” until 31 December 2030. There is therefore currently regulatory uncertainty as to whether CO2 captured from the combustion of municipal waste will need to fulfil the criteria applicable to the Specified Industrial Source pathway (which will be the case if the scope of the EU ETS is expanded to include municipal waste incineration). In the event that the EU ETS is so expanded, and without contemplating any other changes to the EU ETS or RED III as a result, all CO2 emissions from the combustion of municipal solid waste in the EU in facilities of this size would be “accounted for” under the EU ETS regime (either through ETS allowances being required to cover emissions from the non-biomass portion of the waste or through the reporting of emissions stemming from the biomass portion of the waste (noting that such emissions are zero-rated and do not therefore require ETS allowances)). However, the CO2 captured from this source would need to be incorporated into the e-fuel prior to 1 January 2036 (notwithstanding that some of the CO2 will come from the biomass portion of municipal waste and will therefore be “biogenic”). |
| 4 | Combustion of municipal waste to produce electricity in facilities with a total thermal rated input below 20 MW | As above | Assuming that CO2 emissions from the combustion of any biomass portion of municipal waste in facilities below the 20MW thermal rating would not fall under the scope of the EU ETS, such emissions can qualify as an Avoided CO2 Emission under section 3(c) of this Article; CO2 captured from the combustion of biomass fuel, provided that: (a) the waste complies with the applicable RED II sustainability and GHG saving criteria; and (b) in calculating whether the GHG saving criteria have been met, the captured CO2 emissions are accounted for. | (a) In transposing RED II, member states are obliged to take into account the waste hierarchy set out in the Waste Framework Directive 2008/98 which places energy recovery towards the bottom, and prioritises prevention, re-use and recycling. The laws of each member state transposing RED II would therefore need to be considered to ascertain if any national sustainability requirements apply with respect to the combustion of municipal waste, in light of the above. (b) RED II specifies that electricity, heating and cooling produced from municipal solid waste shall not be subject to the GHG saving criteria. It is worth noting that, under RED II, member states are not permitted to grant direct financial support for the production of renewable energy from the incineration of waste, unless the waste collection obligations set out under the Waste Framework Directive have been complied with (which requires, for example, that bio-waste is separated and collected separately). It is therefore evident that biomass waste to energy is not the EU’s preferred source of renewable energy. |
- Directive 2018/2001/EU ↩︎
- Commission Delegated Regulation (EU) 2023/1184 of 10 February 2023 Supplementing Directive (EU) 2018/2001 of the European Parliament and of the Council by establishing a Union methodology setting out detailed rules for the production of renewable liquid and gaseous transport fuels of non-biological origin (First Delegated Act) and Commission Delegated Regulation (EU) 2023/1185 of 10 February 2023 Supplementing Directive (EU) 2018/2001 of the European Parliament and of the Council by establishing a minimum threshold for greenhouse gas emissions savings of recycled carbon fuels and by specifying a methodology for assessing greenhouse gas emissions savings from renewable liquid and gaseous transport fuels of non-biological origin and from recycled carbon fuels (Second Delegated Act) ↩︎
- Directive of the European Parliament and of the Council amending Directive (EU) 2018/2001, Regulation (EU) 2018/1999 and Directive 98/70/EC as regards the promotion of energy from renewable sources, and repealing Council Directive (EU) 2015/652 ↩︎
- Directive 2018/2001, Article 25(2) ↩︎
- Paragraph 10 of the Annex to the Second Delegated Act ↩︎
- In accordance with feedback provided by the European Commission pursuant to “Q&A Implementation of hydrogen delegated acts Version of 26/07/2023”, this may include CO2 from the treatment of biogenic wastes and biogenic CO2 stemming from processes which are outside the scope of the sustainability and GHG saving criteria. ↩︎
- Directive 2003/87/EC of the European Parliament and of the Council of 13 October 2003 establishing a scheme for greenhouse gas emission allowance trading within the Community and amending Council Directive 96/61/EC ↩︎
- The CO2 must be incorporated into the e-fuel before 1 January 2041 (or 2036 for CO2 from fuel combustion for electricity generation). ↩︎
