Commission Delegated Regulation (EU) 2025/2359 of 8 July 2025 supplementing Directive (EU) 2024/1788 of the European Parliament and of the Council by specifying a methodology for assessing greenhouse gas emissions savings from low-carbon fuels
Date: 2025-07-08
Institutions: Directorate-General for Energy, European Commission
Subjects: clean technology, energy cooperation, energy market, greenhouse gas, hydrogen, natural gas, reduction of gas emissions, renewable energy, security of supply, substitute fuel




L_202502359EN.000101.fmx.xml












Official Journal of the European Union


EN
L series













2025/2359


21.11.2025







            COMMISSION DELEGATED REGULATION (EU) 2025/2359
of 8 July 2025
         
supplementing Directive (EU) 2024/1788 of the European Parliament and of the Council by specifying a methodology for assessing greenhouse gas emissions savings from low-carbon fuels
(Text with EEA relevance)


THE EUROPEAN COMMISSION,

Having regard to the Treaty on the Functioning of the European Union,


Having regard to Directive (EU) 2024/1788 of the European Parliament and of the Council of 13 June 2024 on common rules for the internal markets for renewable gas, natural gas and hydrogen, amending Directive (EU) 2023/1791 and repealing Directive 2009/73/EC (1), and in particular Article 9(5) thereof,

Whereas:







(1)


The greenhouse gas emissions accounting methodology for low-carbon fuels should take into account the full life-cycle emissions and indirect emissions resulting from the diversion of rigid inputs for producing low-carbon fuels as well as methane upstream emissions and actual carbon capture rates. In order to ensure the consistency of the methodology set out in this Regulation with the methodology for assessing greenhouse gas emissions savings from renewable fuels of non-biological origin and from recycled carbon-fuels, similar approaches should be applied as in Commission Delegated Regulation (EU) 2023/1185 (2) for assessing greenhouse gas emissions savings.












(2)


The methodology set out in Delegated Regulation (EU) 2023/1185 applies for determining the greenhouse gas emissions savings of renewable fuels of non-biological origin, as well as for recycled carbon fuels which are a sub-category of low-carbon fuels. It is therefore appropriate to exclude recycled carbon fuels from the scope of the methodology set out in this Regulation.












(3)


The certification framework for low-carbon fuels set out in Directive (EU) 2024/1788 is fully aligned with the certification framework set out in Directive (EU) 2018/2001 of the European Parliament and of the Council (3) for renewable fuels. Accordingly, raw materials used for the production of low-carbon fuels as well as the low-carbon fuels themselves should be traced via the Union database in the same way as raw materials used for the production of renewable fuels and the renewable fuels themselves. Therefore, as regards the value for the upstream methane emissions, it is appropriate to distinguish between individual batches of fuels and raw material based on the methane performance profile of the supplier supplying the fuel used to produce the low-carbon fuel.












(4)


The global warming potential of hydrogen has not yet been determined with the level of precision required to be included in the methodology for calculating greenhouse gas emissions. Therefore, relevant values for the global warming potential of hydrogen should be added as soon as scientific evidence has sufficiently matured and is applied to measuring the impact of hydrogen leakage over the whole supply chain in the greenhouse gas emissions accounting methodologies for both low-carbon fuels and renewable fuels on non-biological origin.












(5)


The methodology should recognise capture and storage of emissions as a reduction of emissions where these are permanently stored in a geological storage site, including where emissions taking place in third countries are stored outside the Union, as long as the applicable national law ensures the detection and remediation of leaks in line with the legal provisions applicable in the EU, and leaks are taken into account so they are not credited as reductions. Geological storage sites that repeatedly leak should not be accepted for injection. Currently, surrendering of allowances is only avoided for the emissions under the EU ETS that are stored in a storage site permitted under Directive 2009/31/EC. There are opportunities to cooperate across borders on carbon capture and storage. A potential future recognition of the storage of EU ETS emissions in storage sites in third countries without a linked ETS would depend on there being equivalent conditions to ensure permanently secure and environmentally safe geological storage of captured CO2, provided that the storage is not used to increase hydrocarbon recovery and that this leads to an overall reduction in emissions.












(6)


To ensure consistency of this methodology with the methodology set out in Delegated Regulation (EU) 2023/1185 for renewable fuels of non-biological origin and recycled carbon fuels, it is appropriate to set out rules ensuring that the emission intensity of low-carbon hydrogen and the emission intensity of renewable hydrogen produced in an electrolyser over the same period are always the same, and that the reported energy shares are consistent.












(7)


The implementation of the European Green deal requires a swift shift of the use of fossil fuels for electricity generation. Both renewable and low-carbon hydrogen will contribute to the clean energy transition. The methodologies applicable to each, though based on different legal bases, should be coherent and reflect both technological specificities and economic efficiency. The Commission should, as soon as possible, initiate an assessment on the potential introduction of alternative approaches for recognising low-carbon electricity from nuclear power plants, based on adequate criteria. By 30 June 2026, the Commission should launch a public consultation on a draft methodology outlining these criteria. In addition, the Commission should assess the impact and the implications of evaluating the greenhouse gas emission intensity of electricity using average values. These assessments must consider the overall impact of such approaches on the energy system (including on its economic efficiency and the completion of interconnections), emission reduction potential, and the importance of maintaining a level playing field with fully renewable electricity as defined in Commission Delegated Regulation (EU) 2023/1184 (4) as well as the need to safeguard existing projects,





HAS ADOPTED THIS REGULATION:



Article 1
This Regulation specifies the methodology for calculating the greenhouse gas emissions savings from low-carbon fuels other than recycled carbon fuels.


Article 2
The greenhouse gas emissions savings from low-carbon fuels, other than recycled carbon fuels, shall be determined in accordance with the methodology set out in the Annex.


Article 3

Monitoring and review

By 1 July 2028, the Commission shall assess the impact of the introduction of alternative pathways, notably to consider low-carbon electricity from nuclear power plants based on appropriate criteria and approaches considering the greenhouse gas emission intensity of electricity based on averages. This assessment shall take into account the impact of the use of such pathways on the energy system and emission savings and the need of maintaining a level playing field with sourcing fully renewable electricity. The Commission shall also assess the introduction of a country- or region-specific approach for standard values for greenhouse gas emission intensities of inputs as reported in part B in the Annex. When assessing changes to the criteria the Commission shall safeguard existing projects.


Article 4
This Regulation shall enter into force on the twentieth day following that of its publication in the Official Journal of the European Union.




This Regulation shall be binding in its entirety and directly applicable in all Member States.
Done at Brussels, 8 July 2025.


For the Commission


The President

Ursula VON DER LEYEN
            





(1)  
            OJ L, 2024/1788, 15.7.2024, ELI: http://data.europa.eu/eli/dir/2024/1788/oj.

(2)  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 (OJ L 157, 20.6.2023, p. 20, ELI: http://data.europa.eu/eli/reg_del/2023/1185/oj).

(3)  Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (OJ L 328, 21.12.2018, p. 82, ELI: http://data.europa.eu/eli/dir/2018/2001/oj).

(4)  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 (OJ L 157, 20.6.2023, p. 11, ELI: http://data.europa.eu/eli/reg_del/2023/1184/oj).




ANNEX
Methodology for determining greenhouse gas emissions savings from low-carbon fuels other than recycled carbon fuels
A.   METHODOLOGY








1.


Greenhouse gas emissions from the production and use of low-carbon fuels other than recycled carbon fuels shall be calculated as follows:
E = e i + e p + e td + e u – e ccs – e ccu

where:








E



=


total emissions from the use of the fuel (gCO2eq / MJ fuel);





e i




=


e i elastic + e i rigid – e ex-use: emissions from supply of inputs (gCO2eq / MJ fuel);

e i elastic
 = emissions from elastic inputs (gCO2eq / MJ fuel);

e i rigid
 = emissions from rigid inputs (gCO2eq / MJ fuel);

e ex-use
 = emissions from inputs’ existing use or fate (gCO2eq / MJ fuel)





e p




=


emissions from processing (gCO2eq / MJ fuel);





e td




=


emissions from transport and distribution (gCO2eq / MJ fuel);





e u




=


emissions from combusting the fuel in its end use (gCO2eq / MJ fuel);





e ccs




=


net emission savings from carbon capture and storage (gCO2eq / MJ fuel);





e ccu




=


net emission savings from carbon captured and permanently chemically bound in long-lasting products (gCO2eq / MJ).




Emissions from the manufacture of machinery and equipment shall not be taken into account.
The greenhouse gas emissions intensity of low-carbon fuels shall be determined by dividing the total emissions of the process covering each element of the formula by the total amount of fuel stemming from the process and shall be expressed in terms of grams of CO2 equivalent per MJ of fuel (g CO2eq/MJ fuel). If a fuel is a mix of low-carbon fuels and other fuels, all fuel types shall be considered to have the same emission intensity. The exception to this rule is the case of co-processing where low-carbon fuels, renewable fuels of non-biological origin, biofuels, bioliquids and biomass fuels partially replace a relevant conventional fossil fuel input in a process.
In such a situation it shall be distinguished in the calculation of the greenhouse gas emissions intensity on a proportional basis of the energetic value of relevant energy inputs between:






—


the part of the process that is based on the conventional fossil fuel input as well as biofuels, bioliquids and biomass fuels; and










—


the part of the process that is based on low-carbon fuels and renewable fuels of non-biological origin, assuming that the process parts are otherwise identical.




If more than one relevant energy input is used in the process, the delineation between the two parts of the process is determined based on the share of the input qualifying as low-carbon fuels or renewable fuels of non-biological origin, that replaces the highest share of the conventional fossil fuel input (1).
Biofuels, bioliquids and biomass fuels used in the process are only considered in the calculation of the emission intensity, where used as non-relevant energy input, where used within the scope of the part of the process delineated as set out above (2) or where the feedstock used in the process already includes a biogenic share from the outset such as in the case of mixed municipal waste. The emission intensity of biofuels, bioliquids and biomass fuels is determined in accordance with the rules set out in Article 31 Directive (EU) 2018/2001.
The greenhouse gas emissions intensity of low-carbon fuels may be calculated as an average for the entire production of fuels occurring during a period of up to one calendar month (3). However, where electricity that is fully counted as renewable according to the methodology set out in Article 27(6) of Directive 2018/2001 is used as input to produce hydrogen in an electrolyser, the time interval shall be in line with the requirements applying for temporal correlation unless no specific requirements on temporal correlation apply. Greenhouse gas emissions intensity values calculated for individual time intervals may be used to calculate an average greenhouse gas emissions intensity for a period of up to one month, provided that the individual values calculated for each time period meet the minimum savings threshold of 70 %.












2.


Greenhouse gas emission savings from low-carbon fuels other than recycled carbon fuels shall be calculated as follows:
Savings = (E F – E ) / E F

where:








E



=


total emissions from the use of the fuel;





E F




=


total emissions from the fossil fuel comparator.




For all low-carbon fuels, the total emissions from the fossil fuel comparator shall be equal to the fossil fuel comparator for renewable fuels of non-biological origin set out in Delegated Regulation (EU) 2023/1185.












3.


If the output of a process does not fully qualify as low-carbon fuels other than recycled carbon fuels, the fraction of low-carbon fuels other than recycled carbon fuels shall be determined by dividing the respective relevant energy input into the process by the total relevant energy inputs into the process (4).
The relevant energy for material inputs is the lower heating value of the material input that enters into the molecular structure of the fuel (5).
For electricity inputs that are used to enhance the heating value of the fuel or intermediate products the relevant energy is the energy of the electricity.
For industrial off-gases, the relevant energy is the energy in the off-gas based on their lower heating value. In the case of heat that is used to enhance the heating value of the fuel or intermediate product, the relevant energy is the useful energy in the heat that is used to synthesise the fuel. Useful heat is the total heat energy multiplied by Carnot efficiency, as defined in Part C, point (1)(b) of Annex V to Directive (EU) 2018/2001. Other inputs are only taken into account when determining the emission intensity of the fuel.












4.


When determining emissions from supply of inputs e i, a distinction shall be made between elastic inputs and rigid inputs. Rigid inputs are those whose supply cannot be expanded to meet extra demand. Thus, all inputs qualifying as a carbon source for the production of recycled carbon fuels are rigid, as well as outputs produced in a fixed ratio by an incorporated process (6) and which represent less than 10 % of the economic value of the output. If it represents 10 % or more of the economic value, it shall be treated as elastic. In principle, elastic inputs are those whose supply can be increased to meet extra demand. Petroleum products from refineries fall into this category because refineries can change the ratio of their products. Emissions from energy and material inputs to carbon capture and storage (CCS) operations (for example, from fuel combustion, heat and electricity used, as well as from materials and chemicals) shall be calculated based on the approach set out in points 5 to 11 on process inputs.












5.


Electricity which may be fully counted as renewable in accordance with Article 27(6), second and third subparagraph, of Directive (EU) 2018/2001, shall be attributed zero greenhouse gas emissions.












6.


One of the four following alternative methods shall be applied during each calendar year to attribute greenhouse gas emissions values to the electricity that cannot qualify as fully renewable in accordance with to Article 27(6), second and third subparagraph, of Directive (EU) 2018/2001 and is used to produce low-carbon fuels:






(a)


greenhouse gas emissions values shall be attributed based on yearly averages as set out in Part C of this Annex;










(b)


greenhouse gas emissions values shall be attributed based on the hourly average greenhouse gas emissions value of the electricity mix at the time of production of the low carbon fuels in the bidding zone, as forecasted by the transmission system operators for the day-ahead market for the bidding zone where the low-carbon fuel is produced two hours before the market gate closure time of the day-ahead market. Where available a harmonised methodology shall be applied for this purpose. Until the establishment of a harmonised methodology, the methodology shall have been approved by the competent authority;










(c)


greenhouse gas emissions values shall be attributed depending on the number of full load hours that the installation producing low-carbon fuels is operating. Where the number of full load hours is equal or lower than the number of hours in which the marginal price of electricity was set by installations producing renewable electricity or nuclear power plants in the preceding calendar year for which reliable data are available, grid electricity used in the production process of low-carbon fuels shall be attributed a greenhouse gas emissions value of 0 g CO2eq/MJ; where this number of full load hours is exceeded, grid electricity used in the production process of low-carbon fuels shall be attributed a greenhouse gas emissions value of 183 g CO2eq/MJ;










(d)


greenhouse gas emissions values shall be calculated as an hourly average, based on the greenhouse gas emissions value of the marginal technology setting the clearing price of electricity in a given market time unit at the time of the production of the low-carbon fuels in the bidding zone. This option may only be used if this value has been made publicly available by the national transmission system operator.




If the method set in point (c) is used, it shall be applied to all the electricity that is used to produce low-carbon fuels, including electricity that may be fully counted as renewable in accordance with Article 27(6), second and third subparagraph of Directive (EU) 2018/2001.












7.


Greenhouse gas (GHG) emissions of elastic inputs that are obtained from an incorporated process shall be determined based on data from their actual production process. This shall include all emissions arising due to their production over the whole supply chain (including emissions arising from the extraction of the primary energy required to make the input, process and transport it). Combustion emissions related to the carbon content of fuel inputs shall not be included (7).
GHG emissions from elastic inputs that are not obtained from an incorporated process shall be determined based on the values included in Part B of this Annex. If the input is not included in the list, information on the emission intensity may be obtained from the latest version of the JEC-WTW report, the ECOINVENT database, official sources such as the IPCC, IEA or government, other reviewed sources such as the E3 database, the Global Emission Model for Integrated Systems (GEMIS) database and peer-reviewed publications.
The methane intensity of the production of fossil-based elastic inputs shall be calculated based on the following:






(a)


It shall be calculated as the sum of the methane intensity of the production and transport of inputs.










(b)


The methane intensity of the production of fossil-based elastic inputs shall for inputs produced in the Union be calculated based on the methane emissions reported by Union producers in accordance with Article 12 of Regulation (EU) 2024/1787 of the European Parliament and of the Council (8) and for inputs imported into the Union or used for production of low-carbon fuels outside the Union be based on the methane emissions information reported by importers in accordance with Article 28(1), (2) and (5) of Regulation (EU) 2024/1787 (9).










(c)


The methane intensity of the transport of fossil-based elastic inputs shall for inputs produced in the Union be calculated based on the methane emissions reported by Union producers and asset operators in accordance with Article 12 of Regulation (EU) 2024/1787 and for inputs imported into the Union or used for low-carbon fuels outside the Union be based on the values estimating the methane emissions related to the transport of crude oil, natural gas and coal from third countries published in the Methane Transparency database according to Article 30 point 2(d)(ii) of Regulation (EU) 2024/1787, complemented by relevant methane emissions information reported by asset operators in accordance with Article 12 of Regulation (EU) 2024/1787 and importers in accordance with Article 27(1), Article 28(1), (2) and (5), as well as Annex IX of Regulation (EU) 2024/1787.




However, where the methane intensity cannot be calculated due to the lack of data, or where the input does not enhance the heating value of the low-carbon fuel, the methane intensity of fossil-based elastic inputs may be the relevant value for the upstream methane emissions per unit of fuel included in Part B of this Annex.












8.


The supplier of each elastic input, excluding those inputs where the values are taken from Part B of this Annex, shall calculate the emissions intensity (10) of the input following the procedures in this Annex, and report the value to the next production step or final fuel producer. The same rule applies to the suppliers of inputs further back in the supply chain.












9.


Emissions from rigid inputs (e i rigid) shall include the emissions resulting from the diversion of those inputs from a previous or alternative use. Those emissions shall take into account the loss of production of electricity, heat or products that were previously generated using the input as well as any emissions due to additional treatment of the input and transport. The following rules shall apply:






(a)


Emissions attributed to the supply of rigid inputs shall be determined by multiplying the lost production of electricity, heat or other products with the relevant emission factor. In case of lost electricity production, the emission factors to consider are for grid electricity generation in the country where the displacement occurred, determined according to the methodology set out under points 5 or 6 (11). In case of diverted material, the emissions to be attributed to the replacement material shall be calculated as for material inputs. For the first 20 years after the start of production of low-carbon fuels, the loss of production of electricity, heat and materials shall be determined based on the average amount of electricity and heat that was produced from the rigid input over the last 3 years before the start of production of low-carbon fuels. After 20 years of production, the loss of production of electricity, heat or other products shall be determined based on the minimum energy performance standards assumed in pertinent best available technology (BAT) conclusions. Where the process is not covered by a BAT conclusion, the estimation of lost production shall be based on a comparable process applying state-of-the-art technology.










(b)


In case of rigid inputs that are intermediate streams in industrial processes, such as coke oven gas, blast furnace gas in a steelworks or refinery gas in an oil refinery, if the effect of diverting it towards fuel production cannot be measured directly, the emissions due to the diversion of inputs shall be determined based on simulations of the plant operation before and after it is modified. If the modification of the plant caused a reduction in the output of some products, the emissions attributed to the rigid input shall include the emissions associated with replacing the lost products.










(c)


Where the process makes use of rigid inputs from new installations, the impact of diverting the input from the most economical alternative use shall be taken into account. The emission implications shall be then calculated according to the minimum energy performance standards assumed in the relevant BAT conclusions. For industrial processes that are not covered by BAT conclusions, the emissions saved shall be calculated on the basis of the comparable process applying state-of-the-art technology.
















10.


Emissions from existing use or fate (e ex-use) include all emissions in the existing use or fate of the input that are avoided when the input is used for fuel production. Those emissions shall include the CO2 equivalent of the carbon incorporated in the chemical composition of the fuel that would have otherwise been emitted into the atmosphere. This includes all forms of carbon provided that at least one of the following conditions is fulfilled:






(a)


CO2 has been captured from an activity listed under Annex I to Directive 2003/87/EC of the European Parliament and of the Council (12) or from combustion of mixed municipal waste, has been taken into account upstream in an effective carbon pricing system and is incorporated in the chemical composition of the fuel before 1 January 2036. That date shall be extended to 1 January 2041 in other cases than CO2 stemming from the combustion of fuels for electricity generation;










(b)


the CO2 has been captured from the air;










(c)


the captured CO2 or carbon monoxide stems from biofuels, bioliquids or biomass fuels complying with the sustainability and greenhouse gas saving criteria set out in Article 29 of Directive (EU) 2018/2001;










(d)


the captured CO2 or carbon monoxide stems from renewable fuels of non-biological origin or low-carbon fuels complying with the greenhouse gas saving criteria set out in Article 29a of Directive (EU) 2018/2001 and in this Regulation;










(e)


the captured CO2 stems from a geological source of CO2 and the CO2 was previously released naturally;










(f)


the carbon stems from inputs qualifying as an energy source for the production of recycled carbon fuels.




Captured CO2 stemming from a fuel that is deliberately combusted for the exclusive purpose of producing the CO2, without making use of the energy and CO2 whose capture has received an emissions credit under other provisions of the law, shall not be included.
Emissions associated with inputs like electricity and heat, and consumable materials used in the capture process of CO2 shall be included in the calculation of emissions attributed to inputs.












11.


The dates referred to in point 10(a) shall be subject to review, taking into consideration implementation in the sectors covered by Directive 2003/87/EC of the Union-wide climate target for 2040 established in accordance with Article 4(3) of Regulation (EU) 2021/1119 of the European Parliament and of the Council (13).












12.


Emissions from processing (e p) shall include direct atmospheric emissions from the processing itself, from waste treatment and from leakages, as well as






(a)


any fossil CO2 stream that leaves the processing plant and is captured at the carbon capture plant and considered under e ccs
 or e ccu
; and










(b)


any fossil CO2 emitted into the atmosphere at the end of life of the co-products, calculated on a stoichiometric basis for the carbon incorporated in the chemical composition of all co-products, unless the operator demonstrates that such CO2 is captured and stored permanently or permanently chemically bound in long-lasting products listed in Commission Delegated Regulation (EU) 2024/2620 (14). Solid carbon incorporated in co-products because it is permanently chemically bound in products listed in Delegated Regulation (EU) 2024/2620 or solid carbon stored in line relevant requirements for ensuring permanent storage set out in the methodology adopted pursuant to Article 8(2) of Regulation (EU) 2024/3012 of the European Parliament and of the Council (15) is not considered as emitted.
















13.


Emissions from combustion of the fuel (e u) shall refer to the total combustion emissions of the fuel in use, including emissions from the combustion of carbon of biological origin.












14.


The greenhouse gases taken into account in emissions calculations and their carbon dioxide equivalents shall be the same as specified in Part C, point 4 of Annex V to Directive (EU) 2018/2001.












15.


Where a process yields multiple co-products such as fuels or chemicals as well as energy co-products such as heat, electricity or mechanical energy exported from the plant, greenhouse gas emissions shall be allocated to those co-products applying the following approaches in the following manner:






(a)


The allocation shall be conducted at the end of the process that produces the co-products. The emissions allocated shall include the emissions from the process itself as well as the emissions attributed to inputs to the process.










(b)


The emissions to be allocated shall be e i
 plus any fractions of e p
, e td
 and e ccs
 that take place up to and including the process step at which the co-products are produced. If an input into the process is itself a co-product of another process, the allocation at the other process shall be done first to establish the emissions to be attributed to the input. Emissions of e ex-use
 are to be allocated only to co-products that qualify as renewable fuels of non-biological origin or low-carbon fuels.










(c)


If any installation inside the project boundary treats only one of the project’s co-products, then the emissions from that installation shall be ascribed entirely to that co-product.










(d)


Where the process allows the ratio of the co-products produced to be changed, the allocation shall be done based on physical causality by determining the effect on the process emissions of incrementing the output of just one co-product while keeping the other outputs constant.










(e)


Where the ratio of the products is fixed and the co-products are all fuels, electricity or heat, the allocation shall be done by energy content. If allocation concerns exported heat on the basis of the energy content, only the useful part of the heat may be considered, as defined in Part C, point 16 of Annex V to Directive (EU) 2018/2001.










(f)


Where the ratio of the products is fixed and some co-products are materials with no energy content, the allocation shall be done based on the economic value of the co-products. The economic value considered shall be the average factory gate value of the products over the last 3 years. If such data is not available, the value shall be estimated from commodity prices minus the cost of transport and storage.
















16.


Emissions from transport and distribution (e td) shall include emissions from the storage and distribution of the finished fuels. Emissions attributed to inputs e i
 shall include emissions from their associated transport and storage.












17.


Where a process for making low-carbon fuels produces carbon emissions that are permanently stored in a geological storage site, that carbon (expressed as CO2eq) may be credited to the products of the process as a reduction in emissions under e ccs
 (in gCO2eq/MJ fuel). The term e ccs
 shall consider the capture rate of CO2 from low carbon fuel production, as well as all emissions from the operation activities for carbon capture, transport of CO2 and emissions from injection into the permanent storage site as follows:
e ccs = c CO2
 – e CO2-c – e CO2-t – e CO2-i

where:








c CO2





=


CO2 captured at the carbon capture plant (gCO2eq/MJ fuel);





e CO2-c




=


emissions associated with all operations for carbon capture, dehydration, compression and liquefaction of CO2 (gCO2eq/MJ fuel);





e CO2-t




=


emissions from the transport of CO2 by pipeline, ship, barge, rail or truck from the capture site to the permanent storage site (gCO2eq/MJ fuel);





e CO2-i




=


emissions from injection operations of CO2 into the permanent storage site (gCO2eq/MJ fuel).




The term e ccs
 shall include:






(a)


GHG emissions per MJ of fuel captured at the carbon capture plant (c CO2
) for the purpose of permanent geological storage in a storage site permitted under Directive 2009/31/EC of the European Parliament and of the Council (16) or under applicable national law in third countries, and which is not used for enhanced oil and gas recovery. The applicable national law that regulates geological storage sites shall provide for appropriate monitoring, reporting and verification requirements to detect leaks, as well as place legal obligations on the storage operator to ensure remediation in line with the legal provisions applicable in the Union. In case of a leak the equivalent amount of carbon emissions shall not be credited as a reduction in emissions under e ccs
. Geological storage sites that repeatedly leak shall not be accepted for injection (e CO2-i).










(b)


GHG emissions per MJ of fuel from CO2 capture operations (e CO2-c) Those emissions shall include emissions from fuel, heat and electricity use and material input use for capture, as well as all material replacements (due to losses or degradation). Those emissions shall be calculated in accordance with Section 21 of Annex IV to Commission Implementing Regulation (EU) 2018/2066 (17).










(c)


GHG emissions per MJ of fuel from the transport of CO2 (e CO2-t) by pipeline, ship, rail, truck or other maritime modal from the capture site. GHG emissions due to the transportation of CO2 shall be calculated based on the distance travelled, modal type and load. If the injected CO2 comes via two or more different transport modes, the emissions shall be calculated as a sum for each transport mode. Transport emissions for multiple sources shall be allocated using the mass-based allocation method. If a pipeline carries CO2 to multiple geological sites or serves multiple uses, CO2 transport emissions shall be allocated using the mass-based allocation method. GHG emissions from dispatching CO2 by pipeline shall be calculated in accordance with Section 22 of Annex IV to Implementing Regulation (EU) 2018/2066.










(d)


GHG emissions per MJ of fuel from injection (e CO2-i) into a permanent geological storage site permitted under Directive 2009/31/EC or under applicable national law in third countries. Those emissions shall include all emissions from fuel combustion at stationary equipment used in CO2 transport, including emissions from electricity and emissions of fuels used in CO2 transport by associated booster stations and other combustion activities including on-site power plants. Those emissions shall be calculated in accordance with Section 23 of Annex IV to Implementing Regulation (EU) 2018/2066.




GHG emissions from fuel, heat and electricity use and material input use for capture, dehydration, compression and liquefaction operations shall be considered for all steps in the CO2 value chain, from capture to storage.
For cases not covered by the specific calculation methods prescribed in this point, emissions from energy and material inputs to the CCS operations (for example, from fuel combustion, heat and electricity used, as well as from materials and chemicals) shall be calculated by applying by analogy points 5 to 11 on process inputs.
All emissions from venting as well as fugitive emissions and other CO2 leakages from carbon capture, dehydration, compression and liquefaction, transport of CO2 and from injection operations shall be considered.
In installations that have started operation before 11 December 2025 CO2 may be allocated to a part of the total output of the process provided the carbon capture rate for the part of the incorporated process does not surpass 100 %. For all other installations the net emission savings must be proportionally allocated to the entire fuel output.












18.


Where a process for producing low-carbon fuels generates CO2 emissions that are permanently chemically bound in one of the products listed in the delegated act adopted in accordance with Article 12(3b), second subparagraph, of Directive 2003/87/EC, this shall be credited to the low carbon fuel products of the process as a reduction in emissions under e ccu
 (in gCO2eq/MJ fuel). The term e ccu
 shall consider the capture rate of CO2 from low carbon fuel production, as well as all emissions from the operation activities for carbon capture, transport of CO2 and emissions from the transformation and utilisation process to make them permanently chemically bound in a product, as follows:

e ccu
 = c CO2
 – e CO2-c – e CO2-t – e CO2-u

where:








c CO2





=


CO2 captured at the carbon capture plant (gCO2eq/MJ fuel);





e CO2-c




=


emissions associated with all operations for carbon capture, dehydration, compression and liquefaction of CO2 (gCO2eq/MJ fuel);





e CO2-t




=


emissions from the transport of CO2 by pipeline, ship, barge, rail or truck from the capture site to the utilisation site (gCO2eq/MJ fuel);





e CO2-u




=


emissions from the utilisation of CO2 to chemically bind it permanently in products (gCO2eq/MJ fuel).




Emissions shall only be considered to be permanently chemically bound in a product where the product is listed in the delegated act adopted pursuant to Article 12(3b), second subparagraph, of Directive 2003/87/EC.
In installations that have started operation before 11 December 2025 CO2 may be allocated to a part of the total output of the process provided the carbon capture rate for the part of the incorporated process does not surpass 100 %. For all other installations the net emission savings must be proportionally allocated to the entire fuel output.




B.   ‘STANDARD VALUES’ FOR GHG EMISSION INTENSITIES OF INPUTS
The Tables 1 and 2 establish the GHG emission intensities of inputs other than electricity:

Table 1


Default lifecycle GHG emissions of different energy inputs, expressed in g of substance per MJ of product; greenhouse gases other than CO2 shall be converted into CO2eq by multiplying their amount by the respective values for their global warming potential set out in the Annex to Commission Delegated Regulation (EU) 2020/1044
 (18)
. Excluding emissions from the combustion of the fuel in its use phase









Fuel


CO2



CH4
 (19)



N2O






Solid fossil fuels




 


 


 




Anthracite


6,50 


0,390 


0,00026 




Coking coal


6,50 


0,390 


0,00026 




Other bituminous coal


6,50 


0,390 


0,00026 




Sub-bituminous coal


1,70 


0 


0 




Lignite


1,70 


0 


0 




Patent fuel


5,00 


0,228 


0 




Coke oven coke


5,00 


0,228 


0 




Gas coke


5,00 


0,228 


0 




Coal tar


5,00 


0,228 


0 




Brown coal briquettes


1,70 


0 


0 






Manufactured gases




 


 


 




Gas works gas


5,00 


0,228 


0 




Coke oven gas


5,00 


0,228 


0 




Blast furnace gas


5,00 


0,228 


0 




Other recovered gases


5,00 


0,228 


0 





Peat and peat products



0 


0 


0 





Oil shale and oil sands



5,00 


0,228 


0 






Oil and petroleum products




 


 


 




Crude oil


5,00 


0,228  (= CH4 _crude)


0 




Natural gas liquids


5,00 


0,228 


0 




Refinery feedstocks


5,00 


0,228 


0 




Additives and oxygenates


5,00 


0,228 


0 




Other hydrocarbons


5,00 


0,228 


0 




Refinery gas


5,00 


0,228 


0 




Ethane


5,00 


0,228 


0 




Liquefied petroleum gases


5,00 


0,228 


0 




Motor gasoline


13,40 


1,08 * CH4 _crude


0 




Aviation gasoline


13,40 


1,08 * CH4 _crude


0 




Gasoline-type jet fuel


13,40 


1,08 * CH4 _crude


0 




Kerosene-type jet fuel


13,40 


1,08 * CH4 _crude


0 




Other kerosene


13,40 


1,08 * CH4 _crude


0 




Naphtha


13,40 


1,08 * CH4 _crude


0 




Gas oil and diesel oil


15,65 


1,09 * CH4 _crude


0 




Fuel oil


0 


1,01 * CH4 _crude


0 




White spirit and SBP


13,40 


1,08 * CH4 _crude


0 




Lubricants


15,65 


1,09 * CH4 _crude


0 




Bitumen


5,00 


0,228 


0 




Petroleum coke


5,00 


0,228 


0 




Paraffin waxes


5,00 


0,228 


0 




Other oil products


5,00 


0,228 


0 




Natural gas (excluding LNG liquefaction, shipping and regasification) (20)



4,90 


0,190 


0,00037 






Waste




 


 


 




Industrial waste (non-renewable)


0 


0 


0 




Non-renewable municipal waste


0 


0 


0 






Nuclear energy




 


 


 




Nuclear heat


0,50 


0 


0 











Source:



JRC internal elaboration based on:






—


JEC v5, IPCC 2006 & 2019 Guidelines for National Greenhouse Gas Inventories, V2Ch2, Stationary combustion










—


IFEU 2023










—


Energy and Environmental Research Associates, LLC 2024










—


UNECE 2022, Carbon Neutrality in the UNECE region: Integrated Life-cycle Assessment of Electricity Sources.
















Table 2


Default lifecycle GHG emissions of material inputs







Material input


Total emissions
gCO2eq/kg




Ammonia


2 351,3 




Calcium chloride (CaCl2)


38,8 




Cyclohexane


723,0 




Hydrochloric acid (HCl)


1 061,1 




Lubricants


947,0 




Magnesium sulphate (MgSO4)


191,8 




Nitrogen


56,4 




Phosphoric acid (H3PO4)


3 124,7 




Potassium hydroxide (KOH)


419,1 




Pure CaO for processes


1 193,2 




Sodium carbonate (Na2CO3)


1 245,1 




Sodium chloride (NaCl)


13,3 




Sodium hydroxide (NaOH)


529,7 




Sodium methoxide (Na(CH3O))


2 425,5 




Sulphur dioxide (SO2)


53,3 




Sulphuric acid (H2SO4)


217,5 




Urea


1 846,6 











Source:



JEC-WTW report and Renewable Energy Directive calculations.








C.   GHG EMISSION INTENSITY OF ELECTRICITY

Methodology to calculate GHG emission intensities of electricity

The GHG emission intensity of electricity shall be determined at the level of countries or at the level of bidding zones. The GHG emission intensity of electricity may be determined at the level of bidding zones only if the required data are publicly available. The carbon intensity of electricity, expressed as gCO2eq/MJ electricity, shall be calculated by considering all potential primary energy sources for electricity generation, actual type of plant, conversion efficiencies and own electricity consumption in each power plant.
The calculation shall consider all CO2 equivalent emissions associated with the combustion and supply of the fuels used for electricity production. That calculation shall rely on the amount of different fuels used in the electricity production facilities, together with the emission factors from fuel combustion and upstream (production, refining and transport stages) fuel emission factors.
Greenhouse gases other than CO2 shall be converted into CO2eq by multiplying their amount by the respective values for their global warming potential set out in the Annex to Delegated Regulation (EU) 2020/1044. When combusting biogenic fuels, CO2 emissions shall not be accounted for because of their biogenic origin, but emissions of CH4 and N2O shall be accounted for.
For the calculation of GHG emissions from fuel combustion, the IPCC default emission factors for stationary combustion in energy industries shall be used, see Table 3). The upstream emissions shall include emissions from all the processes and phases required to make the fuel ready to supply power production. They shall result from the extraction, refining and transport of the fuel used for electricity production.
In addition, all the upstream emissions from the cultivation, harvesting, collection, processing and transport of biomass shall be considered. Peat and the components of waste materials that are from fossil origin shall be treated as a fossil fuel.
The fuels used for gross electricity production in electricity-only plants shall be determined based on the electricity production and the efficiency of conversion to electricity. In the case of combined heat and power (CHP) plants, the fuels used for heat produced in CHP shall be counted by considering alternative heat production with average overall efficiencies of 85 %, while the rest shall be attributed to electricity generation.
For nuclear power plants, the conversion efficiency from nuclear heat shall be assumed to be 33 % or data provided by Eurostat or a similar, accredited source.
No fuels shall be associated with electricity production from renewables that include hydro, solar, wind and geothermal. The emissions from the construction, decommissioning and waste management of electricity-producing facilities shall not be considered. The carbon equivalent emissions associated with renewable electricity production (wind, solar, hydro and geothermal) shall therefore be considered to be equal to zero.
The CO2 equivalent emissions from gross electricity production shall include upstream emissions listed in Table 1 and the default emission factors for stationary combustion listed in Tables 3 and 4. The upstream emissions for supplying the fuel used shall be calculated applying the upstream emission factors in Table 1.
The calculation of the carbon intensity of electricity shall be done following the following formulas:





where:







e gross_prod



=


CO2 equivalent emissions [gCO2eq]




c i-ups



=


Upstream CO2 equivalent emission factors [gCO2eq/MJ]




c i-comb



=


CO2 equivalent emission factors from fuel combustion [gCO2eq/MJ] from Tables 3 and 4; it includes emissions of CH4 and N2O expressed as CO2eq/MJ. For the cases where the CO2 is permanently stored by CCS facilities, the CO2 emission factor from fuel combustion shall use the default values for CO2 given in Table 3 reduced by the CCS net impact





Bi




=


Consumption of fuel i for electricity generation [MJ]





i = 1…k



=


Fuels used for electricity production




The amount of net electricity production is determined by the gross electricity production, own electricity consumption in the power plant and the electricity losses in pump storage.
E net = E gros – E own – E pump

where:








E net




=


net electricity production [MJ]





E gross




=


gross electricity production [MJ]





E own




=


own internal electricity consumption in power plant [MJ]





E pump




=


electricity losses in pump storage [MJ]




The carbon intensity of net produced electricity shall be the total gross GHG emissions for producing the net electricity:
CI = e gros_prod / E net

where:

CI = CO2 equivalent emissions from electricity production expressed in [gCO2eq/MJ].

Electricity production and fuel consumption data

Data on electricity production and fuel consumption shall be sourced for IEA member and associate countries from IEA data and statistics that provide data on energy balances and electricity produced using various fuels, for example, from the IEA website, Data and Statistics section (‘Energy Statistics Data Browser’) (21).
For Member States, Eurostat data are more detailed and may be used instead. Where the GHG emission intensity is established at the level of bidding zones, data from official national statistics, transmission system operators or the European Network of Transmission System Operators for Electricity (ENTSO-E) with the same level of detail as the IEA data shall be used. Fuel consumption data shall include available data at the highest level of detail available from national statistics: solid fossil fuels, manufactured gases, peat and peat products, oil shale and oil sands, oil and petroleum products, natural gas, renewables and biofuels, non-renewable waste and nuclear. Renewables and biofuels include all biogenic fuels, biogenic waste, hydro, ocean, tidal, wave, geothermal, wind, solar and ambient energy from heat pumps.

Net trade of electricity

Once the national electricity production and its carbon intensity calculated, net yearly imports from other countries shall be taken into account. For each exchanging country, the net import is calculated as the difference between imports and exports. If greater than zero, which means that the country is a net importer of electricity, the national carbon intensity is calculated considering proportionally the emissions associated to the net imported electricity. To take into account also imports of the exporting country, this calculation should be carried out iteratively until values converge, at least three times. Where the GHG emission intensity of electricity is determined at the level of bidding zones, the same approach shall be applied at the level of the bidding zones.

Input data from literature sources


Table 3


Default emission factors for stationary combustion [g CO2eq/MJ fuel on a net calorific value]









Fuel


CO2



CH4



N2O






Solid fossil fuels




 


 


 




Anthracite


98,3 


0,03 


0,41 




Coking coal


94,6 


0,03 


0,41 




Other bituminous coal


94,6 


0,03 


0,41 




Sub-bituminous coal


96,1 


0,03 


0,41 




Lignite


101,0 


0,03 


0,41 




Patent fuel


97,5 


0,03 


0,41 




Coke oven coke


107,0 


0,03 


0,41 




Gas coke


107,0 


0,03 


0,03 




Coal tar


80,7 


0,03 


0,41 




Brown coal briquettes


97,5 


0,03 


0,41 






Manufactured gases




 


 


 




Gas works gas


44,4 


0,03 


0,03 




Coke oven gas


44,4 


0,03 


0,03 




Blast furnace gas


260,0 


0,03 


0,03 




Other recovered gases


182,0 


0,03 


0,03 





Peat and peat products



106,0 


0,03 


0,41 





Oil shale and oil sands



107,0 


0,03 


0,41 






Oil and petroleum products




 


 


 




Crude oil


73,3 


0,09 


0,16 




Natural gas liquids


64,2 


0,09 


0,16 




Refinery feedstocks


73,3 


0,09 


0,16 




Additives and oxygenates


73,3 


0,09 


0,16 




Other hydrocarbons


73,3 


0,09 


0,16 




Refinery gas


57,6 


0,03 


0,03 




Ethane


61,6 


0,03 


0,03 




Liquefied petroleum gases


63,1 


0,03 


0,03 




Motor gasoline


69,3 


0,09 


0,16 




Aviation gasoline


70,0 


0,09 


0,16 




Gasoline-type jet fuel


70,0 


0,09 


0,16 




Kerosene-type jet fuel


71,5 


0,09 


0,16 




Other kerosene


71,9 


0,09 


0,16 




Naphtha


73,3 


0,09 


0,16 




Gas oil and diesel oil


74,1 


0,09 


0,16 




Fuel oil


77,4 


0,09 


0,16 




White spirit and SBP


73,3 


0,09 


0,16 




Lubricants


73,3 


0,09 


0,16 




Bitumen


80,7 


0,09 


0,16 




Petroleum coke


97,5 


0,09 


0,16 




Paraffin waxes


73,3 


0,09 


0,16 




Other oil products


73,3 


0,09 


0,16 




Natural gas


56,1 


0,03 


0,03 






Waste




 


 


 




Industrial waste (non-renewable)


143,0 


0,89 


1,09 




Non-renewable municipal waste


91,7 


0,89 


1,09 











Source:


IPCC, 2006.












Table 4


Default emission factors for stationary combustion of fuels of biomass origin [g CO2eq/MJ fuel on a net calorific value]









Fuel


CO2



CH4



N2O




Primary solid biofuels


0 


0,89 


1,09 




Charcoal


0 


5,96 


1,09 




Biogases


0 


0,03 


0,03 




Renewable municipal waste


0 


0,89 


1,09 




Pure biogasoline


0 


0,09 


0,16 




Blended biogasoline


0 


0,09 


0,16 




Pure biodiesels


0 


0,09 


0,16 




Blended biodiesels


0 


0,09 


0,16 




Pure bio jet kerosene


0 


0,09 


0,16 




Blended bio jet kerosene


0 


0,09 


0,16 




Other liquid biofuels


0 


0,09 


0,16 











Source:


IPCC, 2006.








Table 5 includes the annual average values for the GHG emission intensity of electricity calculated following the aforementioned formulas in this Part C at country level in the Union. One of the five most recent available annual values may be selected for electricity sourced in the respective countries (22).

Table 5


Emission intensity of generated and net imported electricity in Member States from 2019 to 2023











Country


Emission intensity of generated and net imported electricity (gCO2eq/MJ)




 



2019




2020




2021




2022




2023





Austria


65,2 


55,6 


62,7 


65,3 


43,8 




Belgium


57,0 


58,2 


47,9 


53,2 


48,2 




Bulgaria


136,7 


117,6 


129,4 


149,7 


100,5 




Croatia


76,1 


63,0 


79,9 


87,8 


64,3 




Cyprus


203,4 


199,3 


194,3 


191,7 


184,6 




Czechia


146,5 


132,0 


142,5 


146,7 


127,6 




Denmark


37,1 


22,6 


27,5 


26,3 


15,9 




Estonia


162,6 


88,8 


111,0 


135,4 


78,0 




Finland


24,3 


18,7 


21,5 


18,9 


12,5 




France


18,8 


17,8 


18,3 


25,0 


15,4 




Germany


110,5 


99,7 


110,2 


117,2 


103,8 




Greece


158,3 


127,9 


115,5 


115,4 


101,1 




Hungary


80,2 


73,0 


70,8 


71,3 


54,6 




Ireland


100,0 


92,2 


110,5 


101,4 


85,6 




Italy


97,6 


92,4 


97,0 


108,1 


87,9 




Latvia


84,7 


57,5 


68,4 


85,9 


44,6 




Lithuania


33,8 


31,8 


35,6 


32,1 


19,1 




Luxembourg


86,2 


76,5 


76,1 


87,1 


70,6 




Malta


122,7 


129,8 


120,4 


121,7 


115,7 




Netherlands


123,9 


99,7 


101,8 


96,0 


77,8 




Poland


211,9 


198,1 


211,2 


202,8 


174,8 




Portugal


81,0 


64,4 


53,1 


56,9 


39,1 




Romania


108,0 


91,3 


88,1 


93,9 


73,1 




Slovakia


85,8 


79,1 


86,6 


93,2 


60,9 




Slovenia


72,3 


66,4 


68,8 


67,9 


54,2 




Spain


69,4 


54,7 


52,6 


60,8 


47,3 




Sweden


4,3 


3,3 


3,7 


3,6 


3,4 











Source:


JRC, 2025 from Eurostat data.










(1)  This share is determined by comparing the same type of input, for example the share of low-carbon hydrogen, in all hydrogen used in the process.

(2)  Biofuels, bioliquids and biomass fuels may be part of the delineated process where they are replacing another input than the conventional fossil fuel input, of which low-carbon fuels and renewable fuels are replacing the highest share.

(3)  Where both renewable fuels of non-biological origin and low-carbon fuels are produced in the same facility, the period chosen under Regulation (EU) 2023/1185 and under this methodology shall be the same.

(4)  If a fuel is produced in several subsequent processes, the fraction shall be determined for each process unless it is common industrial practice to integrate the processes technically and geographically.

(5)  For material inputs containing water, the lower heating value is taken to be the lower heating value of the dry part of the material input (that is to say not taking into account the energy needed to evaporate the water). Renewable liquid and gaseous transport fuels of non-biological origin used as intermediate products for the production of conventional fuels and biofuels are not considered.

(6)  Incorporated processes include processes that:






—


take place in the same industrial complex, and










—


reuse heat or other hard-to-transport outputs of one of the processes.





(7)  If carbon intensities are taken from Part B of this Annex, combustion emissions shall not be considered. This is because combustion emissions are counted in processing or in the combustion emissions of the final fuel.

(8)  Regulation (EU) 2024/1787 of the European Parliament and of the Council of 13 June 2024 on the reduction of methane emissions in the energy sector and amending Regulation (EU) 2019/942 (OJ L, 2024/1787, 15.7.2024, ELI: http://data.europa.eu/eli/reg/2024/1787/oj).

(9)  The reported values shall be calculated in accordance with the methodology set by the Commission in accordance with Article 29(4) of Regulation (EU) 2024/1787. Until such date when that methodology is established, other scientific methods such as the OGMP 2.0 methodology may be applied as appropriate.

(10)  Consistent with point 6, the emissions intensity shall not include the emissions embedded in the carbon content of the supplied input.

(11)  Equivalent rules to the rules set under Article 27(6) for renewable fuels of non-biological origin (RFNBO) may be applied for determining the emission factors for lost electricity production due to the use of waste processing gas and exhaust gas of non-renewable origin which are produced as an unavoidable and unintentional consequence of the production process in industrial installations.

(12)  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 (OJ L 275, 25.10.2003, p. 32, ELI: http://data.europa.eu/eli/dir/2003/87/oj).

(13)  Regulation (EU) 2021/1119 of the European Parliament and of the Council of 30 June 2021 establishing the framework for achieving climate neutrality and amending Regulations (EC) No 401/2009 and (EU) 2018/1999 (‘European Climate Law’) (OJ L 243, 9.7.2021, p. 1, ELI: http://data.europa.eu/eli/reg/2021/1119/oj).

(14)  Commission Delegated Regulation (EU) 2024/2620 of 30 July 2024 supplementing Directive 2003/87/EC of the European Parliament and of the Council as regards the requirements for considering that greenhouse gases have become permanently chemically bound in a product (OJ L, 2024/2620, 4.10.2024, ELI: http://data.europa.eu/eli/reg_del/2024/2620/oj).

(15)  Regulation (EU) 2024/3012 of the European Parliament and of the Council of 27 November 2024 establishing a Union certification framework for permanent carbon removals, carbon farming and carbon storage in products (OJ L, 2024/3012, 6.12.2024, ELI: http://data.europa.eu/eli/reg/2024/3012/oj).

(16)  Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006 (OJ L 140, 5.6.2009, p. 114, ELI: http://data.europa.eu/eli/dir/2009/31/oj).

(17)  Commission Implementing Regulation (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 (OJ L 334, 31.12.2018, p. 1, ELI: http://data.europa.eu/eli/reg_impl/2018/2066/oj).

(18)  Commission Delegated Regulation (EU) 2020/1044 of 8 May 2020 supplementing Regulation (EU) 2018/1999 of the European Parliament and of the Council with regard to values for global warming potentials and the inventory guidelines and with regard to the Union inventory system and repealing Commission Delegated Regulation (EU) No 666/2014 (OJ L 230, 17.7.2020, p. 1, ELI: http://data.europa.eu/eli/reg_del/2020/1044/oj).

(19)  An allocation factor shall be considered for calculating the upstream emissions of oil products (from the actual methane upstream emission factor of the crude oil considered): 1,09, 1,08, 1,01 (MJ crude oil/MJ product) for diesel, gasoline and heavy fuel oil (HFO) respectively.

(20)  For natural gas that was transported in liquid form additional GHG emissions (CO2, CH4 and N2O) due to liquefaction, shipping and regasification of natural gas shall be added.
For methane emissions stemming from LNG liquefaction, shipping, and regasification steps, operators shall follow point (7) of this Annex, in accordance with Regulation (EU) 2024/1787.

(21)  Example: https://www.iea.org/data-and-statistics/data-tools/energy-statistics-data-browser?country=GERMANY&fuel=Energy%20supply&indicator=TESbySource.

(22)  Updated data will be made available by the European Commission on a regular basis.



ELI: http://data.europa.eu/eli/reg_del/2025/2359/oj
ISSN 1977-0677 (electronic edition)