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EUROPEAN COMMISSION DIRECTORATE-GENERAL CLIMATE ACTION Directorate B – Carbon Markets & Clean Mobility Unit B.2 – ETS (II): Implementation, Policy Support & ETS Registry

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Guidance Document 2

The Monitoring and Reporting Regulation – 3

General guidance for ETS2 regulated 4

entities 5

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MRR Guidance document for ETS2, 7

1st Draft for discussion, 7 December 2023 8

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This document is part of a series of documents provided by the Commission 11

services for supporting the implementation of the “Monitoring and Reporting 12

Regulation (the “MRR”), i.e. Commission Implementing Regulation (EU) 13

2023/2122 of 17 October 2023 in its current version1. 14

The guidance represents the views of the Commission services at the time of 15

publication. It is not legally binding. 16

This guidance document takes into account the discussions within the meetings 17

of the Commission expert group on climate change policy (CCEG) ETS2 18

implementation formation and the informal Technical Working Group on MRVA 19

(Monitoring, Reporting, Verification and Accreditation) under the Working Group 20

III (WGIII) of the Climate Change Committee (CCC), as well as written comments 21

received from stakeholders and experts from Member States2. 22

All guidance documents and templates can be downloaded from the 23

documentation section of the Commission’s website at the following address:24

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https://ec.europa.eu/clima/eu-action/eu-emissions-trading-system-eu-26

ets/monitoring-reporting-and-verification-eu-ets-emissions_en . 27

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1 Updated by Commission Implementing Regulation (EU) 2023/2122 of 17 October 2023 amending

Implementing Regulation (EU) 2018/2066 as regards updating the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council; the consolidated MRR can be found here: http://data.europa.eu/eli/reg_impl/2018/2066/2022-01-01

2 “Member States” in this document means all countries that apply the EU ETS, i.e. the 27 EU Member States plus the EFTA countries Norway, Iceland and Liechtenstein.

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TABLE OF CONTENTS 1

1 INTRODUCTION ........................................................................ 5 2

1.1 About this document ............................................................................ 5 3

1.2 How to use this document ................................................................... 5 4

1.3 Where to find further information ........................................................ 6 5

2 THE ‘UPSTREAM’ SYSTEM AND SCOPE OF ANNEX III ......... 9 6

2.1 General aspects..................................................................................... 9 7

2.2 Types of fuels covered by ETS2 ........................................................11 8

3 THE EU ETS2 COMPLIANCE CYCLE ..................................... 12 9

3.1 Importance of MRV in the EU ETS .....................................................12 10

3.2 Overview of the compliance cycle.....................................................13 11

3.3 The importance of the monitoring plan ............................................14 12

3.4 Milestones and deadlines ...................................................................16 13

3.4.1 The annual compliance cycle ................................................................16 14

3.4.2 Preparing for the ETS2 .........................................................................17 15

3.5 Roles and responsibilities ..................................................................19 16

4 CONCEPTS AND APPROACHES ........................................... 20 17

4.1 Underlying principles .........................................................................20 18

4.2 Fuel streams ........................................................................................22 19

5 MONITORING METHODOLOGY ............................................. 23 20

5.1 The calculation-based approach .......................................................23 21

5.2 The tier system ....................................................................................24 22

5.3 Monitoring of released fuel amounts ................................................25 23

5.3.1 Tier definitions .......................................................................................25 24

5.3.2 Relevant elements of the monitoring plan .............................................26 25

5.4 The scope factor..................................................................................30 26

5.4.1 End consumers covered by the ETS2 scope ........................................30 27

5.4.2 Methods to determine end consumers ..................................................32 28

5.4.3 Avoiding double counting between ETS1 and ETS2 ............................38 29

5.5 Calculation factors – Principles .........................................................40 30

5.5.1 Default values ........................................................................................40 31

5.5.2 Laboratory analyses ..............................................................................43 32

5.6 Calculation factors – specific requirements ....................................44 33

5.6.1 Unit conversion factor (UCF) .................................................................44 34

5.6.2 Emission factor ......................................................................................45 35

5.6.3 Biomass fraction ....................................................................................46 36

5.6.4 Applicability of RED II criteria ................................................................46 37

5.6.5 Special rules for biogas .........................................................................48 38

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6 THE MONITORING PLAN ....................................................... 49 1

6.1 Developing a monitoring plan ............................................................ 49 2

6.2 Selecting the correct tier .................................................................... 52 3

6.3 Categorisation of regulated entities and fuel streams .................... 55 4

6.3.1 Regulated entity categories ................................................................... 55 5

6.3.2 Regulated entity with low emissions ..................................................... 55 6

6.3.3 Identification and categorisation of fuel streams ................................... 56 7

6.4 Reasons for derogation ...................................................................... 58 8

6.4.1 Unreasonable costs .............................................................................. 59 9

6.4.2 Simplified uncertainty assessment for the scope factor ........................ 62 10

6.5 Uncertainty assessment ..................................................................... 62 11

6.5.1 General principles ................................................................................. 62 12

6.5.2 General requirements ........................................................................... 64 13

6.6 Procedures and the monitoring plan ................................................ 66 14

6.7 Data flow and control system ............................................................ 69 15

6.8 Keeping the monitoring plan up to date ........................................... 70 16

6.8.1 Significant modifications ........................................................................ 72 17

6.8.2 Non-significant modifications of the monitoring plan............................. 73 18

6.9 The improvement principle ................................................................ 73 19

7 REGULATED ENTITIES WITH LOW EMISSIONS .................. 75 20

8 IDENTIFYING THE ETS2 REGULATED ENTITIES ................. 76 21

9 ANNEX II .................................................................................. 79 22

9.1 Acronyms ............................................................................................. 79 23

9.2 Legislative texts .................................................................................. 80 24

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Version History 1

Date Version status Remarks

6 December 1st Draft for comments

First draft version of the general MRR guidance for ETS2 regulated entities

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1 INTRODUCTION 1

1.1 About this document 2

This document has been written to support the MRR (Monitoring and Reporting 3

Regulation), by explaining its requirements in a non-legislative language. This 4

document is written to be a standalone document for ETS2 regulated 5

entities and usually the other guidance documents should not be relevant. 6

However, for some more specific technical issues, further guidance documents3 7

are available, although mainly written for ETS1 stationary installations or aircraft 8

operators. Where this is the case, this guidance document makes specific 9

reference in the relevant sections to such further details which could be of interest 10

for ETS2 regulated entities. The set of guidance documents is further 11

complemented by electronic templates4 for information to be submitted by 12

regulated entities to the competent authority. It should always be remembered 13

that only the Regulation is legally binding. 14

This document interprets the Monitoring and Reporting Regulation regarding 15

requirements for ETS2 regulated entities. It builds on similar guidance for 16

stationary installations and aircraft operators and takes into account the valuable 17

input from the Climate Change Expert Group (CCEG) on ETS2 implementation,), 18

the informal Technical Working Group on Monitoring, Reporting, Verification and 19

Accreditation (TWG on MRVA) of Member State experts established under 20

Working Group 3 (WG III) of the Climate Change Committee (CCC). 21

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1.2 How to use this document 23

Where article numbers are given in this document without further specification,

they always refer to the MRR in its current version5. For acronyms, references to

legislative texts and links to further important documents, please see the Annex.

This symbol points to important hints for regulated entities, verifiers and

competent authorities.

This indicator is used where significant simplifications to the general requirements

of the MRR are promoted.

The light bulb symbol is used where best practices are presented.

The tools symbol tells the reader that documents, templates or electronic tools

are available from other sources.

The book symbol points to examples given for the topics discussed in the

surrounding text.

3 See section 1.3. 4 Note that Member States may define their own templates, which must contain at least the same

information as the Commission’s templates. 5 Implementing Regulation (EU) 2018/2066; The consolidated MRR can be found here:

https://eur-lex.europa.eu/eli/reg/2018/2066

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1.3 Where to find further information 2

All guidance documents and templates provided by the Commission on the basis

of the MRR and the AVR can be downloaded from the Commission’s website at

the following address:

https://ec.europa.eu/clima/eu-action/eu-emissions-trading-system-eu-

ets/monitoring-reporting-and-verification-eu-ets-emissions_en

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The following documents are provided6 (documents not relevant for regulated 4

entities are highlighted in light grey, documents which might contain elements 5

also relevant for regulated entities are highlighted in green): 6

 “Quick guides” as introduction to the guidance documents below. Separate 7

documents are available for each audience: 8

 Operators of stationary installations; 9

 Aircraft operators; 10

 ETS2 Regulated entities (planned); 11

 Competent Authorities; 12

 Verifiers; 13

 National Accreditation Bodies. 14

 General guidance (this document): “The Monitoring and Reporting Regulation 15

– General guidance for ETS2 regulated entities” 16

 Guidance document No. 1: “The Monitoring and Reporting Regulation – 17

General guidance for installations”. 18

 An exemplar simplified monitoring plan in accordance with Article 13 MRR. 19

 Guidance document No. 2: “The Monitoring and Reporting Regulation – 20

General guidance for aircraft operators”. This document outlines the principles 21

and monitoring approaches of the MRR relevant for the aviation sector. It also 22

includes guidance on the treatment of biomass in the aviation sector, making 23

it a stand-alone guidance document for aircraft operators. 24

 Guidance document No. 3: “Biomass issues in the EU ETS”: This document 25

discusses the application of sustainability criteria for biomass, as well as the 26

requirements of Articles 38 and 39 of the MRR. This document is relevant for 27

operators of installations and useful as background information for aircraft 28

operators. 29

 Guidance document No. 4: “Guidance on Uncertainty Assessment”. This 30

document for installations gives information on assessing the uncertainty 31

associated with the measurement equipment used, and thus helps the 32

operator to determine whether he can comply with specific tier requirements. 33

 Guidance document No. 4a: “Exemplar Uncertainty Assessment”. This 34

document contains further guidance and provides examples for carrying out 35

6 This list reflects the status at the time of writing this updated guidance. Further documents may be

added later.

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uncertainty assessments and how to demonstrate compliance with tier 1

requirements. 2

 Guidance document No. 5: “Guidance on sampling and analysis”. This 3

document deals with the criteria for the use of non-accredited laboratories, 4

development of a sampling plan, and various other related issues concerning 5

the monitoring of emissions in the EU ETS. 6

 Guidance document No. 5a: “Exemplar Sampling Plan”. This document 7

provides an example sampling plan for a stationary installation. 8

 Guidance document No. 6: “Data flow activities and control system”. This 9

document discusses possibilities to describe data flow activities for monitoring 10

in the EU ETS, the risk assessment as part of the control system, and 11

examples of control activities. 12

 Guidance document No. 6a: “Risk Assessment and control activities – 13

examples”. This document gives further guidance and an example for a risk 14

assessment. 15

 Guidance document No. 7: “Continuous Emissions Monitoring Systems 16

(CEMS)”. This document gives information on the application of measurement-17

based approaches where GHG emissions are measured directly in the stack, 18

and thus helps the operator to determine which type of equipment has to be 19

used and whether he can comply with specific tier requirements. 20

 Guidance document No. 8: “EU ETS Inspection”: Targeted at competent 21

authorities, this document outlines the role of the CA’s inspections for 22

strengthening the MRVA system of the EU ETS. 23

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The Commission also provides the following electronic templates: 25

 Template No. 1: Monitoring plan for the emissions of stationary installations 26

 Template No. 2: Monitoring plan for the emissions of aircraft operators 27

 Template No. 3: Monitoring plan for the tonne-kilometre data of aircraft 28

operators 29

 Template No. 4: Annual emissions report of stationary installations 30

 Template No. 5: Annual emissions report of aircraft operators 31

 Template No. 6: Tonne-kilometre data report of aircraft operators 32

 Template No. 7: Improvement report of stationary installations 33

 Template No. 8: Improvement report of aircraft operators 34

 ETS2 Monitoring Plan template (planned) 35

 ETS2 Annual Emissions Report template (planned) 36

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In addition, there are the following tools available: 38

 Unreasonable costs determination tool; 39

 Tool for the assessment of uncertainties; 40

 Frequency of Analysis Tool; 41

 Tool for operator risk assessment. 42

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The following MRR training material is available: 44

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 Roadmap through M&R Guidance 1

 Uncertainty assessment 2

 Unreasonable costs 3

 Sampling plans 4

 Data gaps 5

 Round Robin Test 6

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Besides these documents dedicated to the MRR, a separate set of guidance 8

documents on the AVR is available under the same web address. 9

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All EU legislation is found on EUR-Lex: http://eur-lex.europa.eu/ 11

The most important relevant legislation is listed in the Annex of this document. 12

13

Also, competent authorities in the Member States may provide useful guidance 14

on their own websites. The egulated entities should follow if the competent 15

authority provides workshops, FAQs, helpdesks etc. 16

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2 THE ‘UPSTREAM’ SYSTEM AND SCOPE OF 1

ANNEX III 2

2.1 General aspects 3

The EU ETS started in 2005 by putting a carbon price on stationary installations 4

(power plants, steel, cement, etc.) for their annual direct emissions (i.e. the 5

entities that combust the fuel, called “down-stream” regulation, henceforth the 6

“ETS1”). Over the course of time, the scope has been expanded to fuels 7

combusted in aviation and, recently, to maritime transport. When considering 8

expansion of the EU ETS to the further large fuel consuming sectors, in particular 9

transport and buildings, the entities responsible for monitoring and reporting 10

under a “downstream” EU ETS would be individual car owners, building owners, 11

etc. In order to avoid the high administrative burden that would come with putting 12

the reporting obligation on those individuals, the new and separate ETS for road 13

transport, buildings and additional sectors (henceforth the “ETS2”) puts the point 14

of regulation “upstream” on the entities releasing the fuel for consumption (i.e. 15

putting the fuels onto the market). 16

In order to benefit from the existing reporting infrastructure for the types and 17

amounts of fuels in consideration, the ETS2 aims to align with the existing 18

infrastructure under the energy taxation / excise duty regime for the same type of 19

fuels. This is established via the national transposition of the Energy Taxation 20

Directive (Directive 2003/96/EC, henceforth “ETD”)7 and Directive 2020/262/EU8 21

(henceforth called the ‘Excise Directive’ or ‘ED’). The links between these three 22

Directives (see illustration in Figure 1) concern the following elements: 23

 Identifying the ETS2 regulated entities to ensure there are no gaps or double 24

counting: this aspect is relevant for the Member States (not the regulated 25

entities) and described inchapter 8. 26

 Defining the types of fuels covered by the scope of ETS2: the relevant types 27

of fuels are defined in Article 3(af) of the EU ETS Directive ( section 2.2). 28

 Defining the event that triggers the ETS2 reporting obligation: this is achieved 29

by defining the ‘release for consumption’ in Article 3(ag)9 of the EU ETS 30

Directive referring to the respective definitions set out in Article 6(3) of the ED. 31

 Identifying the amounts released for consumption and eventually combusted 32

in sectors listed within the scope of Annex III of the EU ETS Directive and 33

distinguishing them from other final consuming sectors. This comprises the 34

following two aspects: 35

 How to categorise the end consumers into their respective categories 36

listed in Annex III of the EU ETS Directive: the category format for sectoral 37

distinction used is the Common Reporting Format (CRF) used for compiling 38

national GHG inventories following the IPCC Guidelines ( section 5.4.1). 39

7 Council Directive 2003/96/EC of 27 October 2003 restructuring the Community framework for the

taxation of energy products and electricity 8 Council Directive (EU) 2020/262 of 19 December 2019 laying down the general arrangements for

excise duty. 9 Article 3(ag): ‘release for consumption’ for the purposes of Chapter IVa of this Directive means

release for consumption as defined in Article 6(3) of Directive (EU) 2020/262

10

 What types of methods can be used to demonstrate that fuel amounts are 1

supplied to sector A and not sector B: this is a core element of the ETS2 2

monitoring methodology ( chapter 5), the determination of the so-called 3

‘scope factor’ which is described in detail later in section 5.4.2. 4

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Figure 1: Relation between the EU ETS Directive, the ETD and ED with respect to 7

the ETS2 8

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1

2.2 Types of fuels covered by ETS2 2

Article 3(af)10 defines the scope of fuels covered by the ETS2, which are basically 3

all relevant commercial fuels and other energy products listed in Article 2(1) of 4

the ETD as combined nomenclature (CN) codes. More precisely, it includes the 5

following: 6

 fuels listed in Tables A and C of the ETD: (un)leaded petrol, gas oil, 7

kerosene, LPG, natural gas, heavy fuel oil, coal and coke; 8

 any other fuel offered for sale, used as motor fuel or heating fuel as specified 9

in Article 2(3) of the ETD. This includes any fuel additives, certain bio-based 10

fuels, and any other hydrocarbons, except for peat. 11

This means that indicatively the following types of fuels are currently excluded 12

from the ETS2: 13

 Peat; 14

 Waste used as fuels (hazardous or municipal waste used as fuel, as explicitly 15

excluded from the ETS2 scope in Annex III of the Directive); 16

 Waste-derived fuels (mostly used in ETS1 installations anyway); 17

 Solid biomass (e.g. wood-based fuels); 18

 Charcoal from wood. 19

. 20

10 Article 3(af): ‘fuel’ for the purposes of Chapter IVa of this Directive means any energy product

referred to in Article 2(1) of Directive 2003/96/EC, including the fuels listed in Table A and Table C of Annex I to that Directive, as well as any other product intended for use, offered for sale or used as motor fuel or heating fuel as specified in Article 2(3) of that Directive, including for the production of electricity

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3 THE EU ETS2 COMPLIANCE CYCLE 1

3.1 Importance of MRV in the EU ETS 2

Monitoring, reporting and verification (MRV) of emissions play a key role in the 3

credibility of any emissions trading system. Without MRV, compliance would lack 4

transparency and be much more difficult to track, and enforcement compromised. 5

This holds true also for the European Union Emissions Trading System for 6

buildings, road transport and additional sectors (ETS2). It is the complete, 7

consistent, accurate and transparent monitoring, reporting and verification 8

system that creates trust in emissions trading. Only in this way can it be ensured 9

that regulated entities meet their obligation to surrender sufficient allowances. 10

This observation is based on the twofold nature of the ETS2: On the one hand it 11

is a market-based instrument. It has allowed a significant market to evolve, in 12

which market participants want to know the monetary value of the allowances 13

they get allocated, they trade and they have to surrender. On the other hand it is 14

an instrument for achieving an environmental benefit. But in contrast to other 15

environmental legislation, the goal is not to be achieved by individuals, but the 16

whole group of ETS2 participants having to achieve the goal jointly. This requires 17

a considerable level of fairness between participants, ensured by a solid MRV 18

system. The competent authorities’ oversight activities contribute significantly to 19

ensuring that the goal set by the cap is reached, meaning that the anticipated 20

emissions reductions are delivered in practice. It is therefore the responsibility of 21

the competent authorities together with the accreditation bodies to protect the 22

integrity of the ETS2 by supervising the effective and robust functioning of the 23

MRV system. 24

Both, carbon market participants and competent authorities want to have 25

assurance that one tonne CO2 equivalent emitted finds its equivalent in one tonne 26

reported (for the purpose of one allowance to be surrendered). This principle has 27

been known since the early days of the EU ETS as the proverbial postulation: “A 28

tonne must be a tonne!” 29

In order to ensure that this is achieved in a robust, transparent, verifiable and yet 30

cost-effective way, the EU ETS Directive11 provides a solid basis for a good 31

monitoring, reporting and verification system. This is achieved by Articles 14 and 32

15 in connection with Annexes IV and V of the EU ETS Directive.12 Based on 33

Article 14, the Commission has adopted the Monitoring and Reporting 34

Regulation13” (MRR), which has been amended several times. 35

However, it has always been recognised by the Commission, as well as by 36

Member States, that complex and technical legislation such as the MRR needs 37

to be supported by further guidance, in order to ensure harmonised 38

11 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 including all amendments.

12 Article 30f of the EU ETS Directive declares Article 14 and 15 as well as Annex IV and V of the Directive equally applicable to ETS2.

13 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.

13

implementation throughout all Member States, and for paving the way to smooth 1

compliance through pragmatic and agreed approaches wherever possible. 2

A Regulation for verification and accreditation of verifiers has also been adopted 3

(the Accreditation and Verification Regulation (AVR)14), for which a separate 4

series of guidance documents has been developed by the Commission 5

(dedicated guidance for verifiers will be published later). 6

7

3.2 Overview of the compliance cycle 8

The annual process of monitoring, reporting, verification of emissions, surrender 9

of allowances, and the competent authority’s procedure for accepting emission 10

reports is often referred to as the “compliance cycle”. Figure 2 shows the main 11

elements of this cycle. 12

On the right side of the picture is the “main cycle”: The regulated entity monitors 13

its emissions throughout the year. After the end of the calendar year (within four 14

months15) it must prepare its annual emissions report (AER), seek verification 15

and submit the verified report to the competent authority (CA). The verified 16

emissions must correlate with the surrender of allowances in the Registry 17

system16 as of 2027. Here the principle “a tonne must be a tonne” translates into 18

“a tonne must be an allowance”, i.e. at this point the market value of the allowance 19

is correlated with the costs of meeting the environmental goal of the ETS2. 20

Thereafter monitoring goes on, as shown in the picture. More precisely, 21

monitoring continues without any stop at the end of the year from one cycle to 22

the next. 23

The monitoring process needs a firm basis. Resulting data must be sufficiently 24

robust for creating trust in the reliability of the ETS, including the fairness of the 25

surrender obligation, and it must be consistent over the years. Therefore the 26

regulated entity must ensure that its monitoring methodology is documented in 27

writing, and cannot be changed arbitrarily. In the case of the EU ETS, this written 28

methodology is called the Monitoring Plan (MP) of the regulated entity (see Figure 29

2). It is part of the permit17, which every regulated entity in the EU ETS must have 30

for the emission of greenhouse gases. 31

Figure 2 also shows that the MP, although specific to an individual regulated 32

entity, must follow the requirements of the EU-wide applicable legislation, in 33

particular the MRR. As a result, the MRV system of the EU ETS is able to square 34

the circle between strict EU-wide rules providing reliability and preventing 35

arbitrary and undue simplifications, and allowing for sufficient flexibility for the 36

circumstances of individual regulated entities. 37

38

14 Commission Implementing Regulation (EU) 2018/2067 of 19 December 2018 on the verification of

data and on the accreditation of verifiers pursuant to Directive 2003/87/EC of the European Parliament and of the Council.

15 According to national legislation, this period may be shorter, see footnote 23. 16 For the purpose of simplification, the surrender of allowances has not been included in the picture.

Similarly, the picture also ignores the processes of free allocation and trading of allowances. 17 This permit pursuant to Article 30b of the EU ETS Directive is referred to as the GHG emission

permit. Note that for simplifying administration, according to Article 30b(5), the monitoring plan may be treated separately from the permit when it comes to formal changes to the monitoring plan.

14

1

Figure 2: Principle of the ETS2 compliance cycle 2

3

Figure 2 also shows some key responsibilities of the competent authority. It has 4

to supervise the compliance of the regulated entities. As the first step, the CA has 5

to approve every MP before it is applied. This means that the MP developed by 6

the regulated entity is checked for compliance with the MRR’s requirements. 7

Where the regulated entity makes use of some simplified approaches allowed by 8

the MRR, this must be justified by the regulated entity, for example, based on the 9

grounds of technical feasibility or unreasonable costs, where otherwise required 10

higher tiers cannot be achieved. 11

Finally, it is the responsibility of the competent authority to carry out checks on 12

the annual emission reports. This includes spot checks on the already verified 13

reports, as well as cross-checks with figures entered in the verified emissions 14

table of the registry system, and checking that sufficient allowances have been 15

surrendered. 16

Moreover, the compliance cycle has a wider perspective. As Figure 2 shows, 17

there is a second cycle. This is the regular review of the MP, for which the 18

verification report may provide valuable input. Besides which the regulated entity 19

is required to continuously strive for further improving its monitoring methodology. 20

21

3.3 The importance of the monitoring plan 22

From the previous section it becomes apparent that the approved monitoring plan 23

(MP) is the most important document for every regulated entity participating in 24

the EU ETS. Like a recipe for a cook or the management handbook for a certified 25

quality management system, it serves as the manual for the regulated entity’s 26

tasks. Therefore, it should be written in a way that allows all, particularly new staff 27

to immediately understand the process and follow the instructions. It must also 28

allow the CA to quickly understand the regulated entity’s monitoring activities. 29

Monitoring throughout the year

Verification

Annual Report

Surrender allowances

Legislation MRR

Monitoring plan (entity-specific)

Improvement suggestions

Picture by

Competent Authority

Compliance checks

Accreditation body

Accreditation & Surveillance

Legislation AVR

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Finally, the MP is the ‘criteria’ for the verifier against which the regulated entity’s 1

emission report is to be judged. 2

Typical elements of a MP include the following activities of the regulated entity 3

(applicability depends on the specific regulated entity’s circumstances): 4

 Data collection (metering data, invoices, etc.); 5

 Sampling of materials and fuels; 6

 Laboratory analyses of fuels and materials; 7

 Maintenance and calibration of meters; 8

 Description of calculations, formulae and software to be used; 9

 Description of the methods to identify end consumers’ CRF categories; 10

 Control activities to ensure validation and quality of data processed and 11

reported (e.g. four eyes principle for data collection); 12

 Data archiving (including protection against manipulation and distruction); 13

 Regular identification of improvement possibilities. 14

MPs must be drafted carefully ( chapter 6), so that administrative burden is 15

minimised and yet they are clear enough for situations when the regulated entity’s 16

experienced personnel are not available18. Since the MP is to be approved by the 17

CA, it goes without saying that changes to the MP are only allowed with the 18

consent of the CA. The MRR reduces the administrative efforts here by allowing 19

two approaches which should be taken into account when drafting MPs: 20

 Only changes which are “significant” need the approval by the CA (Article 21

75b(3) of the MRR, see section 6.8 below); 22

 Monitoring activities which are not crucial in every detail, and which by their 23

nature tend to be frequently amended as found necessary, may be put into 24

“written procedures”, which are mentioned and described briefly in the MP, but 25

the details of which are not considered part of the approved MP. The 26

relationship between MP and written procedures is described in more detail in 27

section 6.6. 28

Because of the importance of the MP, the Commission will also providing 29

templates for MPs. Some Member States may have provided customized 30

templates based on the Commission’s templates, other Member States use a 31

dedicated (usually web-based) electronic reporting system (that must also meet 32

minimum stated Commission requirements). Before developing a MP, regulated 33

entities are therefore advised to check their CA’s website or make direct contact 34

with the CA in order to find out the specific requirements for submitting a MP in 35

their Member State. National legislation may also state specific requirements. 36

37

18 E.g. they include clear reference to other systems, processes and procedures that may be required

for successful application of the MP

16

3.4 Milestones and deadlines 1

3.4.1 The annual compliance cycle 2

The EU ETS compliance cycle is built around the requirement that monitoring is 3

always related to the calendar year19, as shown in Table 1. Regulated entities 4

have four months after the end of the year to finalise their emission reports and 5

to get them verified by an accredited verifier in accordance with the AVR. 6

Thereafter regulated entities have to surrender the corresponding amount of 7

allowances by 31 Oct each year. Subject to national legislation, the competent 8

authority may or shall perform (spot) checks on the reports received, and must 9

determine a conservative estimate of the emissions, if the regulated entity fails to 10

submit an emissions report, or where a report has been submitted, but it is either 11

not compliant with the MRR or not verified as satisfactory in accordance with the 12

AVR (Article 75r(1) of the MRR). The CA detects any kind of error in the submitted 13

reports, which may result in corrections to the verified emissions figure to be done 14

by the ETS2 entity (and subject to re-verification). Note that for such corrections 15

no deadline is given by EU legislation. However, there may be some requirement 16

given in national legislation. 17

18

Table 1: Common timeline of the annual EU ETS compliance cycle for emissions in 19

year N. 20

When? Who? What?

By 31 Aug 2024 20 Regulated entity

Submit to the competent authority a MP for approval

Before 1 Jan 2025 CA Approve MP and issue a GHG permit

30 April 2025 Regulated entity

Submit report on historic emissions (2024)

1 January N 21 Start of monitoring period

31 December N End of monitoring period

by 30 April22 N+1 Verifier Finish verification and issue verification report to the regulated entity

By 30 April23 N+1 Regulated entity

Submit verified annual emissions report to CA

By 30 April N+1 Regulated entity / Verifier24

Enter verified emissions figure in the verified emissions table of the Registry

19 Article 3(12) of the MRR defines: ‘reporting period’ means a calendar year during which emissions

have to be monitored and reported […]. 20 unless the competent authority has set an alternative time limit for this submission. It is however

advised to submit the MP as soon as possible, in particular when having in mind that reporting on historic emissions in April 2025 implies monitoring of emissions already during 2024.

21 First year N is 2025. 22 Footnote 23 applies here as well. 23 According to Article 75p(1), competent authorities may require regulated entities to submit the

verified annual emission report earlier than by 30 April, but by 31 March at the earliest. 24 This may be regulated differently in the Member States.

17

When? Who? What?

April – May N+1 CA Subject to national legislation, possible spot checks of submitted annual emissions reports. Require corrections by regulated entity, if applicable. N.B. Subject to national legislation, there is no obligation for CAs to provide assistance or acceptance of regulated entity reports either before or after 30 April).

By 31 July N+125 Regulated entity

Submit report on possible improvements of the MP to the CA, if applicable26

By 31 Oct N+1 Regulated entity

Surrender allowances (amount corresponding to verified annual emissions) in Registry system

(No specified deadline)

CA Carry out further checks on submitted annual emissions reports, where considered necessary or as may be required by national legislation; require changes to the emissions data and surrender of additional allowances, if applicable (in accordance with Member State legislation).

1

2

3.4.2 Preparing for the ETS2 3

In order to make the compliance cycle work, the MPs of all regulated entities need 4

to be approved by the competent authority before the start of the monitoring 5

period for ETS2 starting on 1 January 2025. Based on experience from previous 6

phases in ETS1, this approval process may require several months and should 7

be well prepared. Relatively long timescales are assumed: Firstly, preparation of 8

the MP by the regulated entity can take up to several months, depending on the 9

complexity of their operations and in particular the market structure when trying 10

to identify end consumers’ sectors. Because the CA also needs a few weeks or 11

months for assessing all submitted MPs (depending on current workload) and 12

because regulated entities then need some weeks for finally implementing the 13

new approved MP, the MRR requires regulated entities to submit their MPs for 14

approval at the latest four months before monitoring starts (i.e. by end of August 15

2024).27 16

17

25 Article 75q(1) allows the CA to set a later date, but not later than 30 Sep. 26 There are two different types of improvement reports pursuant to Article 75q of the MRR. One is

to be submitted in the year where a verifier reports improvement recommendations, and the other (which may be combined with the first, if applicable) every 3 years for category B, and every 5 years for category A entities. For categorisation, see section 0 of this document. The CA may set a different deadline, but no later than 30 September of that year.

27 Unless the competent authority has set an alternative time limit for this submission

18

An idealised example timeline for the start of the new ETS2 is shown in Table 2. 1

Table 2: Idealised model timeline for preparing the EU ETS compliance cycle for the 2

start of the ETS2. Note that deadlines may significantly differ according to 3

the Member States. 4

When? Who? What?

March – Aug 2024 Regulated

entity

Develop new MP

at the latest by end

Aug 2024

Regulated

entity

Submit new MP to CA (deadline set by CA)

Aug – Dec 2024 CA Check and approve MPs

Oct – Dec 2024 Regulated

entity

Prepare for implementation of approved MP

1 January 2025 Regulated

entity

Start of monitoring period using the approved

MP based on the MRR requirements

30 April 2025 Regulated

entity

Submit report on historical emissions (2024),

i.e. the first annual emissions report

30 April 2026 Regulated

entity

Submit first verified report on emissions

concerning the reporting year 2025

1 Jan 2027 Trading starts for ETS2

5

6

19

3.5 Roles and responsibilities 1

The different responsibilities of the regulated entities, verifiers and competent 2

authorities are shown in Figure 3, taking into account the activities mentioned in 3

the previous sections. For the purpose of completeness, the accreditation body 4

is also included. The picture clearly shows the high level of control which is 5

efficiently built into the MRV system. The monitoring and reporting is the main 6

responsibility of the regulated entities (who are also responsible for hiring the 7

verifier and for providing all relevant information to the verifier). The CA approves 8

the MPs, receives and checks the emission reports, is in charge of inspections 9

and may make corrections to the verified emissions figure when errors are 10

detected. Thus, the CA has control over the final result. Finally, the verifier is 11

ultimately answerable to the accreditation body28. Note that based on Article 66 12

of the AVR, Member States must also monitor the performance of their national 13

accreditation bodies, thereby fully ensuring the integrity of the EU ETS system of 14

MRV and accreditation. 15

16

17

18

Figure 3: Overview of responsibilities of the main actors in the EU ETS. Regarding 19

“Accreditation body” see also footnote 28. 20

28 The AVR also allows in exceptional cases verifiers (if natural persons) to be certified and

supervised by a national authority appointed by that Member State (in accordance with AVR Article 55).

ETS2

regulated entity

Competent

Authority Verifier

National

Accreditation Body

Picture by

ETS1

(installation)

Prepare monitoring plan

Carry out

monitoring

Prepare

annual

emissions

report

Submit verified

emissions report

Apply for accreditation

Maintain

accredi-

tation

Inspection and

enforcement

Verify

emissions

report

Surrender allowances

Carry out

spot-checks

Accredi-

tation

process

Surveil-

lance

Accept report or

prescribe emissions Improvement measures

Year +1

Open registry account

ETS2 Annually repeating ‘compliance cycle’

Open registry account

Check and approve

monitoring plan /

Issue GHG permit Year N-1

1 Jan

Year N

31 Dec

Year N

31 Mar

Year N+1

31 Oct

Year N+1

Confirm amounts

of fuel consumed

Submit verified

emissions report

30 Apr

Year N+1

31 Jul

Year N+1

20

4 CONCEPTS AND APPROACHES 1

This chapter is dedicated to explaining the most important terms and concepts 2

needed for developing a MP. 3

4

4.1 Underlying principles 5

Articles 5 to 9 of the MRR29 outline the guiding principles which the regulated 6

entities have to follow when fulfilling their obligations. These are: 7

1. Completeness (Article 5): The completeness of fuel streams is at the very 8

core of the EU ETS monitoring principles. In order to ensure completeness of 9

emissions monitored, the regulated entity should take into account the 10

following considerations: 11

 Article 4 of the MRR requires that all emissions associated with all fuel 12

streams ( section 0) are to be included, where these belong to combustion 13

in sectors listed in Annex III of the EU ETS Directive, or which are included 14

in the EU ETS by “opt-in” (pursuant to Article 30j of the Directive). 15

 For completeness of system boundaries see ‘designating ETS2 regulated 16

entities’ in section 8 and ‘types of fuels covered’ in section 2.2. 17

2. Consistency and comparability (Article 6(1)): Time series30 of data need to 18

be consistent across the years. Arbitrary changes of monitoring 19

methodologies are prohibited. This is why the MP has to be approved by the 20

competent authority, for significant changes to the MP. Because the same 21

monitoring approaches are defined for all regulated entities the data created 22

is also comparable between regulated entities; although depending on their 23

circumstances the regulated entities may be required to apply different 24

methods according to the tier system ( section 5.2). 25

3. Transparency (Article 6(2)): All data collection, compilation and calculation 26

must be made in a transparent way. This means that the data itself, the 27

methods for obtaining, processing and reporting them (in other words: the 28

whole data flow) have to be documented transparently, and all relevant 29

information has to be securely stored and retained allowing for sufficient 30

access by authorised third parties. In particular, the verifier and the competent 31

authority must be allowed access to this information. 32

It is worth mentioning that transparency is in self-interest of the regulated 33

entity: It facilitates transfer of responsibilities between existing and new staff 34

and reduces the likelihood of errors and omissions. In turn this reduces the 35

risk of over-surrendering, or under-surrendering allowances and penalties. 36

Without transparency, verification activities are more onerous and time-37

consuming and hence costly to the regulated entity. 38

Furthermore Article 67 of the MRR31 specifies that relevant data is to be stored 39

29 Article 75a of the MRR declares these Articles equally applicable to ETS2. 30 This does not imply a requirement to produce time series of data, but assumes that the regulated

entity, verifier or competent authority may use time series as a means of consistency checks. 31 Article 75o of the MRR declares this Article equally applicable to ETS2.

21

for 10 years32 from submission of the verified report. The minimum data to be 1

retained is listed in Annex IX of the MRR. 2

4. Accuracy (Article 7): Regulated entities have to take care that data is 3

accurate, i.e. neither systematically nor knowingly inaccurate. Due diligence 4

is required by regulated entities, striving for the highest achievable accuracy. 5

As the next point shows, “highest achievable” may be read as where it is 6

technically feasible and “without incurring unreasonable costs”. 7

5. Integrity of the methodology and of the emissions report (Article 8): This 8

principle is at the very heart of any MRV system. The MRR mentions it 9

explicitly and adds some elements that are needed for good monitoring: 10

 The monitoring methodology and the data management must allow the 11

verifier to achieve “reasonable assurance33” on the emissions report, i.e. the 12

monitoring must be able to endure a quite intensive test; 13

 Data shall be free from material34 misstatements and avoid bias; 14

 The data shall provide a credible and balanced account of a regulated 15

entity’s emissions. 16

 When looking for greater accuracy, regulated entities may balance the 17

benefit against additional costs. They shall aim for “highest achievable 18

accuracy, unless this is technically not feasible or would lead to 19

unreasonable costs”. 20

6. Continuous improvement (Article 9): In addition to the requirement of Article 21

75q, which requires the regulated entity to regularly submit reports on 22

improvement possibilities, e.g. for reaching higher tiers, this principle also is 23

the foundation for the regulated entity’s duty of responding to the verifier’s 24

recommendations (see also Figure 2 on page 14). 25

26

27

32 In practice this means 11 years and 4 months for data originating on 1/1/YN, if the report is submitted

on 30/4/YN+1 33 Article 3(18) of the AVR defines: “‘reasonable assurance’ means a high but not absolute level of

assurance, expressed positively in the verification opinion, as to whether the operator’s or aircraft operator’s report subject to verification is free from material misstatement.” For more details on the definition this term, see guidance documents on the A&V guidance, in particular the AVR Explanatory Guidance (EGD I). Section 1.3 provides a link to those documents.

34 See footnote 33.

22

4.2 Fuel streams 1

Fuel streams35: This term refers to all the types of fuels which a regulated entity 2

releases for consumption, for which the emissions associated with the eventual 3

consumption (i.e. combustion) have to be monitored when applyingthe 4

calculation-based approach ( chapter 5). There are however certain 5

requirements in the definition on how to split relevant types of fuels into fuel 6

streams, as well as further practical considerations. The latter include the ‘scope 7

factor’ ( section 5.4) and the types of end consumers ( section 5.4.1) which 8

also play a role when splitting the total amount of fuel released for consumption 9

into ‘fuel streams’. Such splitting is discussed in further detail in section 6.3.3. 10

Commercial standard fuels36: This term refers to types of fuels which are 11

internationally standardised and for which the net calorific value therefore only 12

varies within small intervals in all countries. This includes the most important road 13

transport fuels such as gas oil (diesel) or gasoline. For those types of fuels, 14

monitoring requirements are a lot simpler in the MRR ( section 6.2). 15

Fuels meeting equivalent criteria to commercial standard fuels37: This term 16

refers to fuels which exhibit similar characteristics to commercial standard fuels 17

but only at the Member State level or regional level. Where those conditions are 18

met, monitoring requirements are equally simplified in the same way as for 19

commercial standard fuels ( section 6.2). 20

21

35 MRR Article 3(64): ‘fuel stream’ means a fuel as defined in Article 3, point (af), of Directive

2003/87/EC, released for consumption through specific physical means, such as pipelines, trucks, rail, ships or fuel stations, and giving rise to emissions of relevant greenhouse gases as a result of its consumption by categories of consumers in sectors covered by Annex III to Directive 2003/87/EC. EU ETS Directive Article 3(af): ‘fuel’ for the purposes of Chapter IVa of this Directive means any energy product referred to in Article 2(1) of Directive 2003/96/EC, including the fuels listed in Table A and Table C of Annex I to that Directive, as well as any other product intended for use, offered for sale or used as motor fuel or heating fuel as specified in Article 2(3) of that Directive, including for the production of electricity

36 Article 3(32): ‘commercial standard fuel’ means the internationally standardised commercial fuels that exhibit a 95 % confidence interval of not more than 1 % for their specified calorific value, including gas oil, light fuel oil, gasoline, lamp oil, kerosene, ethane, propane, butane, jet kerosene (jet A1 or jet A), jet gasoline (jet B) and aviation gasoline (AvGas)

37 Article 75k(2): “The competent authority may require the regulated entity to determine the unit conversion factor and emission factor of fuels as defined in Article 3(af) of Directive 2003/87/EC using the same tiers as required for commercial standard fuels provided that, at the national or regional level, any of the following parameters exhibit a 95 % confidence interval of:

(a) below 2 % for net calorific value;

(b) below 2 % for emission factor, where the released fuel amounts are expressed as energy content.

23

5 MONITORING METHODOLOGY 1

5.1 The calculation-based approach 2

Regulated entities haveto determine the emissions associated with the 3

combustion of fuels released for consumption using the calculation-based 4

approach. 5

The principle of this method is the calculation of emissions by multiplying, for 6

each fuel stream, the released fuel amount by the corresponding unit conversion 7

factor, the corresponding scope factor and the corresponding emission factor. 8

Figure 4 illustrates this. 9

10

11

Figure 4: Calculation-based methodology to determine emissions 12

Parameter Description

Released

fuel

amounts

This is the amount of fuel released for consumption ( section 5.3), expressed

usually as t, Nm³ or TJ. Where applicable, this will correspond to the total fuel

amount for each fuel type released through the excise duty point.

Scope factor This is a dimensionless factor between 0 (all fuel released consumed outside

sectors covered by Annex III of the Directive) and 1 (all fuel released consumed in

sectors covered by Annex III of the Directive). The determination of this factor

involves the ability to identify the relevant category of end consumers in terms of

their coverage in Annex III ( section 5.4).

Unit

conversion

factor

Where applicable, this converts the fuel quantity into units ( section 5.6.1)

compatible with the (preliminary) emission factor. E.g. where fuel quantities are

expressed as t or Nm³ this is could be the net calorific value (NCV) with the

corresponding EF expressed as t CO2/TJ.

= Annual emissions

t CO2





Activity data

t*

Emission factor

t CO2 / t*

Fossil fraction

%

Unit conversion

factor

t* / X



Released fuel

amount

X = t, m³, GWh,…

Scope

factor

[ - ]



Preliminary

emission factor

t CO2 / t*

Renewable Energy Directive

(2018/2001/EU) criteria

Distinction of final consumers

B (1A4a&b) Oth. fin. cons.

EU ETS inst.

Covered by the scope of Annex III

Outside the scope of Annex III

RT (1A3b)*** Ind (1A2)*

Energy (1A1)**

**Energy Industries (1A1) and Manufacturing Industries and Construction (1A2) including

installations or units excluded under Art. 27a EU ETS-D, excluding other EU ETS installations

***Road Transport (1A3b) excluding the use of agricultural vehicles on paved roads

* may also refer to other units

than tonnes (e.g. TJ or Nm³)

as long as consistency

between activity data and

emission factor is ensured.

24

Preliminary

emission

factor (EF)

This factor is usually expressed as t CO2/t, t CO2/litre or t CO2/TJ and converts

amounts or energy content of the fuels released for consumption into emissions

( section 5.6.2).

Biomass/

fossil

fraction

This is a dimensionless fraction taking into account the fossil fraction of carbon in

fuels that comprises the following two aspects ( section 5.6.3):

 The fraction of carbon arising from biogenic origin

 The compliance of the biomass component with the sustainability and GHG

savings criteria of the RED II.

1

2

5.2 The tier system 3

The EU ETS system for monitoring and reporting provides for a building block 4

approach for monitoring methodologies. Each parameter needed for the 5

determination of emissions can be determined by applying different “data quality 6

levels”. These “data quality levels” are called “tiers”38. The building block 7

approach is illustrated by Figure 5, which shows the tiers which can be selected 8

for determining the emissions from a fuel stream. The descriptions of the different 9

tiers (i.e. the requirements for complying with those tiers) are presented in more 10

detail in the subsequent sections for each parameter. 11

In general, it can be said that tiers with lower numbers represent methods with 12

lower requirements and being less accurate than higher tiers. Tiers of the same 13

number (e.g. tier 2a and 2b) are considered equivalent. 14

15

16

Figure 5: Illustration of the tier system. 17

38 Article 3(8) of the MRR defines: ‘tier’ means a set requirement used for determining activity data,

calculation factors, annual emission and annual average hourly emission, and payload.

Released amounts

Tier 1

Tier 2

Tier 3

Tier 4

Unit conversion

factor

Tier 1

Tier 2a/2b

Tier 3

(Prelim.) Emission

factor

Tier 1

Tier 2a/2b

Tier 3

Biomass fraction

Tier 1

Tier 2

Tier 3a/3b

Scope factor

Tier 1

Tier 2

Tier 3

Picture by

25

Higher tiers are considered, in general, more accurate but more difficult and 1

costly to meet than lower ones (e.g. due to more expensive measurements 2

applied). Therefore, lower tiers are usually allowed for smaller quantities of 3

emissions, i.e. for de-minimis fuel streams (see section 6.3.3) and for smaller 4

regulated entities (for categorisation see section 6.3.1). A cost-effective approach 5

is thus ensured. 6

Which tier a regulated entity must select according to the requirements of the 7

MRR is discussed in detail in section 6.2. 8

9

5.3 Monitoring of released fuel amounts 10

5.3.1 Tier definitions 11

As discussed earlier, the tiers ( section 5.2) for released fuel amounts of a fuel 12

stream are defined using thresholds for a maximum uncertainty allowed for the 13

determination of the quantity of fuel or material over a reporting period. Whether 14

a tier is met, must be demonstrated by an uncertainty assessment. Elements of 15

this uncertainty assessment are discussed in section 6.5. Such an uncertainty 16

assessment is however not required where the measurement methods applied to 17

determine released fuel amounts correspond to the same regulated entity and 18

fuel stream covered by ETD/ED regime, provided those methods are subject to 19

national legal metrological control ( section 0). For illustration, Table 3 shows 20

the tier definitions for combustion of fuels. A full list of the tier definitions in the 21

MRR is given in section 1 of Annex IIa of the MRR. 22

Table 3: Typical definitions of tiers for activity data based on uncertainty, given for the 23

combustion of fuels as example. 24

Tier No. Definition

1 Amount of fuel [t] or [Nm3] or [TJ] over the reporting period39 is determined with a maximum uncertainty of less than ± 7.5 %.

2 Amount of fuel [t] or [Nm3] or [TJ] over the reporting period is determined with a maximum uncertainty of less than ± 5.0 %.

3 Amount of fuel [t] or [Nm3] or [TJ] over the reporting period is determined with a maximum uncertainty of less than ± 2.5 %.

4 Amount of fuel [t] or [Nm3] or [TJ] over the reporting period is determined with a maximum uncertainty of less than ± 1.5 %.

25

Note that the uncertainty is meant to refer to “all sources of uncertainty, including 26

uncertainty of instruments, of calibration, environmental impacts”, unless some 27

of the simplifications mentioned in section 6.5.2 are applicable. 28

29

30

39 Reporting period is the calendar year.

26

5.3.2 Relevant elements of the monitoring plan 1

When developing its MP, the regulated entity has to make several choices 2

regarding the way released fuel amounts are determined. 3

The released fuel amounts comprise the total amount of fuel released for 4

consumption (i.e. put on the market) before taking into consideration which type 5

of consumers (transport, heating of buildings, industry, agriculture, etc.) the fuels 6

are eventually consumed by. The conversion of these total amounts into the 7

relevant amounts consumed only in sectors covered by the ETS2 scope will be 8

done later when multiplying by the scope factor ( section 5.4). 9

10

Quantification of released fuel amounts 11

The MRR provides for the following three methods to determine the released fuel 12

amounts: 13

 Measurement methods used under the ETD/ED regime, provided that: 14

 the regulated entity corresponds to the entity that has reporting obligations 15

for energy products under the ETD/ED regime; 16

 the measurement methods are subject to national legal metrological control 17

(NLMC). This should usually be the case for all commercial transaction 18

based on the measurements of fuels for which taxes are paid and duties 19

levied. 20

Without explicitly mentioning it, those measurement methods will be based on 21

batch metering or continual metering (see below). 22

 based on batch metering, i.e. aggregation of measurement of quantities at the 23

point where the fuel streams are released for consumption, such as individual 24

truck deliveries of solid fuels, liquid fuels, or LPG. 25

 based on continual metering at the point where the fuel streams are released 26

for consumption, such as pipeline transport of liquid or gaseous fuels. 27

The MRR provides for special provisions for the first method (ETD/ED regime) by 28

allowing CAs to require regulated entities to use this method, if applicable, as well 29

as by allowing regulated entities to assume meeting the highest tier listed in 30

section 5.3.1 without assessment of the measurement uncertainty. Furthermore, 31

the MRR also allows the released fuel amounts to be expressed as the relevant 32

units used for energy taxation, e.g. TJ, litres, GWh (gross calorific value). In all 33

other cases, the units are limited to tonnes, Nm³ and TJ (as shown in Table 3). In 34

all cases, the released fuel amounts will be converted in a subsequent step into 35

units (e.g. t or TJ) by multiplying with the appropriate unit conversion factor ( 36

section 5.6.1) compatible with the units of the relevant emission factor (e.g. t CO2 37

per t or TJ). 38

39

Regulated entity’s instruments vs. trading partner’s instruments 40

The MRR does not require every regulated entity to own the measuring 41

instruments at any cost. That would contradict the MRR’s approach regarding 42

cost effectiveness. Instead, instruments which are under the control of other 43

parties (in particular fuel trading partners) may be used. Especiallyin the context 44

of commercial transactions such as fuel trading, it is often the case that metering 45

is done by only one of the trade partners. The other partner may assume that the 46

27

uncertainty associated with the measurement is reasonably low, because such 1

measurements are often governed by legal metrological control. Alternatively, 2

requirements on quality assurance for instruments, including maintenance and 3

calibration can be included in purchase contracts. However, where the 4

measurement methods are not the ones used under ETD/ED regime, the 5

regulated entity must assess the uncertainty applicable to such meters in order 6

to assess if the required tier can be met (Article 75j(2), 2nd sub-paragraph). 7

Thus, the regulated entity may choose whether to use its own instruments or to 8

rely on instruments used by the fuel supplier. However, a slight preference is 9

given by the MRR to own instruments: If the regulated entity decides to use or 10

rely on other instruments despite having its own instruments at its disposal, the 11

trading partner’s instruments have to allow compliance with at least the same tier, 12

give more reliable results and be less prone to control risks than the methodology 13

based on its own instruments. 14

In many cases this uncertainty assessment will be short and simple. In particular, 15

if the regulated entity has no alternative instrument available under its own 16

control, so the regulated entity does not have to compare the tier applicable using 17

its own instrument with the tier applicable to the trading partner’s instrument. 18

Furthermore, control risk may be low where invoices are subject to an accounting 19

department’s controls40. In the case that invoices are used as primary data for 20

determining the material or fuel quantity, the MRR requires the regulated entity 21

to demonstrate that the trade partners are independent. In principle, this should 22

be considered a safeguard for ensuring that meaningful invoices exist. In many 23

cases it will also be an indicator of whether national legal metrological control is 24

applicable. 25

26

Timing of measurements 27

Theoretically, the cut-off time for annual amounts would have to be determined 28

at midnight on 31 December every year, which may not be possible in practice. 29

Therefore, the MRR allows for choosing the next most appropriate day to 30

separate one reporting year from the following one. Data must be reconciled 31

accordingly to the required calendar year. The deviations involved for one or more 32

fuel streams shall be clearly recorded, form the basis of a value representative 33

for the calendar year, and be considered consistently in relation to the next year 34

(Article 75j(2)). 35

E.g. in the natural gas market, where the tax liable entity (hence most commonly 36

the ETS2 regulated entity) is the natural gas supplier, but the measurements 37

instruments for measuring household consumption are owned by the distribution 38

system operator (DSO). Subject to internal procedures, the DSO will read the 39

meters only once per year on a predefined date (e.g. in May, after the ETS2 40

reporting deadline) and make the results available to the supplier. Where this 41

transfer of information comes too late for the ETS2 annual emissions reporting 42

deadline of 30 April each year, the released fuel amounts will be based on the 43

same proxy consumption amounts used as the basis for invoicing the household 44

40 Note that the existence of the accounting’s controls does not automatically dispense the regulated

entity from including appropriate risk mitigation measures in the EU ETS related control system. The risk assessment according to Article 59(2) and 75o must include this risk as appropriate.

28

consumers and only adjusted for in the year Y+1 emissions report based on the 1

actual consumption measurement results. 2

3

Example: A natural gas supplier (the ETS2 regulated entity in this example)

has direct contractual relationships with households. The annual natural gas

consumption is measured once per year on 15 May with a flow meter that is

owned and read by the natural gas distribution system operator (DSO). This

means that the latest actual measurements available to the regulated entity for

reporting on historic emissions during 2024 by 30 April 2025 will be from 15

May 2024. Let’s assume this measurement has shown annual consumption of

2 500 kWh between 15 May 2023 and 15 May 2024.

The regulated entity may propose the following procedure to calculate released

fuel amounts:

 The regulated entity may use this value of 2 500 kWh as the best available

information to estimate the released fuel amounts for the total calendar year

2024 and report this figure in the annual emissions report due by 30 April

2025.

 On 15 May 2024 the DSO reports to the regulated actual consumption

between 15 May 2023 and 15 May 2024 to have been 2 300 kWh.

 For reporting on emissions during 2025 due by 30 April 2026, the best

available data for released fuel amounts is therefore 2 300 kWh. However,

in order to correct for the over-reporting in the previous year, the regulated

entity has to deduct the 2 500 kWh – 2 300 kWh = 200 kWh which will lead

to reporting released fuel amounts of 2 100 kWh for 2025.

 The above steps would be reported for subsequent years as well.

This approach would take into account a ‘balance’ between reported and –

only available after the reporting deadline of 30 April – actual emissions. This

balance will be set to zero when reporting emissions in the next year. This

approach would be reminiscent of the down payment rates the natural gas

suppliers charge their consumers. The result is shown in the table below.

kWh

Actual

consumption

(May Y-2 to

May Y-1)

Best estimate (for year Y-1)

Reported 'released fuel amounts' in

AER (in year Y for Y-1)

Balance (reported -

actual)

2024 April

May 2 500

2025 April 2 500 2 500

May 2 300 200

2026 April 2 300 2 100 0

May 2 600 -300

2027 April 2 600 2 900 0

May 2 500 100

2028 April 2 500 2 400 0

May … … … …

The fuel suppliers may also propose more sophisticated approaches taking

into account e.g. longer history of consumption levels and splits based on

estimates of consumption levels before and after 15 May of each year

29

(winter/summer patterns, e.g. with the support of DSO’s data) instead of the

‘equal distribution’ split implicitly assumed in this example, ‘benchmarks’ for

similar consumers, historic and projected heating degree days, etc. However,

whatever approach is proposed, it should be consistent with the down payment

plan for the same consumer in order to avoid inconsistenties and incentives for

strategic behaviour for arbitrage gains.

1

There are a couple of take-aways from the above example: 2

 Actual consumption levels will always lag behind by one year. However, with 3

every year on the relative impacts on the cumulative reported amounts will 4

diminish. This is also how the market works based on down payments and 5

cannot be avoided until there is a wider uptake of smart gas meters which allow 6

for real-time measurements. 7

 There will always remain uncertainty on which were the actual consumption 8

levels in the first year (in this case between 1 Jan 2024 and 15 May 2025). Like 9

for the above, the uncertainty around this figure will have diminishing relative 10

impacts over time. 11

 The example table above shows that this ‘balance method’ can considerably 12

amplify small differences between estimated and actual emissions to the 13

differences in reported ‘released fuel amounts’ across years. However, since 14

a natural gas supplier will usually have thousands of different consumers, the 15

differences between estimated and actual amounts can be expected to 16

average out at the aggregated level. 17

In reality, there will also not only be one meter reading day for all consumers, but 18

reading days spread out over the year. The DSO will read meters of some 19

consumers on e.g. 18 Jan, of others on 25 Feb, 10 May and so on. Therefore, 20

the regulated entity may propose a reasonable cut-off date for taking meter 21

readings into consideration for the current year and which ones to base on best 22

estimates and only reconcile in next year’s report. Such a date could be e.g. [one] 23

week before the verification takes place. The methodology applied will have to be 24

described in the approved MP. 25

26

Information on further requirements regarding determination of released fuel 27

amounts: Further information on maintenance, calibration and adjusting of 28

measuring instruments is listed in section 6.3. 29

30

31

32

30

5.4 The scope factor 1

Article 3(66) of the MRR applies the definition that the “‘scope factor’ means the 2

factor between zero and one that is used to determine the share of a fuel stream 3

that is used for combustion in sectors covered by Annex III to [EU ETS] Directive 4

2003/87/EC”. 5

This means that for each fuel stream the regulated entity has to determine the 6

share of the released fuel amounts being combusted in sectors listed in Annex 7

III. For each fuel stream the scope factor can take values of 0 (not covered by 8

Annex III), 1 (fully covered by Annex III) or any value in between (partly covered 9

by Annex III). 10

The regulated entity will have to identify those amounts eventually combusted by 11

consumers in sectors covered by Annex III and distinguish them from amounts 12

supplied to all other types of end consumers. However, correct identification of 13

the category of end consumer might not be easy in all cases, especially if there 14

is no direct supply connection between the regulated entity and the end 15

consumer. Furthermore, related information must be verifiable. This means that 16

the regulated entity must be able to collect evidence which is sufficiently robust 17

for being used by a verifier for building an opinion with a reasonable level of 18

assurance. 19

 What type of information is needed to determine in which CRF category an end 20

consumer falls ( section 5.4.1)? 21

 What methods can be used to identify end consumers ( section 5.4.2) 22

23

24

5.4.1 End consumers covered by the ETS2 scope 25

The method used to identify the end consumers in section 5.4.2 will have to be 26

combined with being able to put those consumers into their respective category 27

with respect to ETS2 coverage. Annex III of the EU ETS Directive lists the sectors 28

buildings, road transport and additional sectors, see details below) for which 29

consumption of the fuels released for consumption by the ETS2 regulated entities 30

should be covered by the ETS2, including any sectors Member States opt-in via 31

Article 30j of the Directive. The sectoral categorisation is done using the Common 32

Reporting Format (CRF) used for compiling national GHG inventories following 33

the IPCC 2006 Guidelines. 34

 The guidelines can be downloaded from here: 35

https://www.ipcc-nggip.iges.or.jp/public/2006gl/vol2.html 36

 The most important definitions for stationary combustions (closely 37

corresponding to ‘heating fuels’ as used under the ETD/ED regime) can be 38

found in Table 2.1 of the following document: 39

https://www.ipcc-40

nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf 41

 The most important definitions for mobile combustions (closely corresponding 42

to ‘motor fuels’ as used under the ETD/ED regime) can be found in Table 3.1.1 43

of the following document: 44

https://www.ipcc-45

nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_3_Ch3_Mobile_Combustion.pdf 46

31

Regulated entities will have to report emissions from fuels combusted in the 1

sectors listed along with their CRF category in Annex III of the Directive (i.e. CRF 2

1A1, 1A2, 1A3b, 1A4a and 1A4b). This includes the following sectoral uses, as 3

well as the main excluded sectors from which a regulated entity needs to 4

distinguish uses as part of the scope factor determination: 5

 CRF 1A4a & CRF 1A4b: fuel combustion in commercial/institutional and 6

residential buildings 7

 CRF 1A4a includes: emissions from fuel combustion in commercial and 8

institutional buildings (space heating, warm water, cooking, etc.); all 9

activities included in ISIC41 divisions 41, 50, 51, 52, 55, 63-67, 70-75, 80, 10

85, 90-93 and 99; 11

 CRF 1A4b includes: all emissions from fuel combustion in households 12

(space heating, warm water, cooking, etc.); 13

 excludes: main uses to be separated from the above are other stationary 14

and mobile combustion, in particular excludes any emissions from fuel 15

combustion in agriculture, forestry, fishing and fishing industries such as fish 16

farms (CRF 1A4c; activities included in ISIC Divisions 01, 02 and 05). 17

 CRF 1A3b: Road Transportation 18

 includes: all combustion and evaporative emissions arising from fuel use in 19

road vehicles such as from cars, motorcycles, light- and heavy-duty vehicles 20

such as trucks, busses, urea-based additives for catalysts, etc. However, as 21

an important difference, agricultural vehicles used on paved roads (i.e. 22

where the vehicle type is primarily designed for the agricultural purpose but 23

can also be used on paved roads, e.g. tractors) are excluded according to 24

Annex 3 from the ETS2 scope despite being included in CRF 1A3b. 25

 excludes: main uses to be separated from the above are emissions from 26

other modes of transportation such as aviation (1A3a, mostly covered by 27

ETS1 apart from private aviation), off-road vehicles in agriculture (1A4c), 28

railways (1A3c) water-borne navigation (1A3d, mostly covered by ETS1), 29

military operations etc. (1A5b), etc. 30

 CRF 1A1: Energy Industries 31

 includes: emissions from fuels combusted for production of electricity 32

(power plants), combined heat and power (CHP plants) and Heating plants, 33

refineries (1A1b), combustion in coke ovens within the iron and steel 34

industry (1A1c), etc. The majority of these end consumers (in particular 35

where combustion units exceed a capacity of 20 MW) are covered by ETS1. 36

 CRF 1A2: Manufacturing Industries and Construction 37

 includes: emissions from fuels combustion in industry (iron & steel, cement, 38

chemicals, etc.), including combustion for the generation of electricity and 39

heat for own use in these industries. This also includes emissions from fuel 40

combustion in any off-road or mobile machinery (such as excavators or 41

construction site mobile machinery) as well as head offices of industrial 42

companies (same economic activity as the industrial sites). As can be seen 43

41 International Standard Industrial Classification of All Economic Activities

https://unstats.un.org/unsd/publication/SeriesM/seriesm_4rev4e.pdf

32

in the IPCC GL, the sectoral definitions often refer to ISIC42 classification. 1

The larger installations are already covered by ETS1. 2

 excludes: fuels used for non-energetic purposes for process input (CRF 3

category 2A to 2H), such as as chemical reactant (e.g. natural gas for 4

ammonia production) or reducing agent (e.g. iron & steel industry). The 5

larger installations are already covered by ETS1. 6

7

Furthermore, Annex III explicitly excludes from the ETS2 scope activities listed in 8

Annex I (i.e. emissions already covered by ETS1). Table 4 compares the main 9

sectors covered by those two Annexes. 10

11

Table 4: Comparison of coverage of Annexes I and III of the EU ETS Directive 12

Annex III coverage Covered by ETS1 43 Not covered by ETS1 44

CRF category covered

by Annex III

Large-scale energy industry and

industrial activities (CRF 1A1 & 1A2)

Aviation activity above the thresholds in

Annex I of the Directive

Martitime activity above the thresholds in

Annex I of the Directive

Large building complexes with

combustion units >20MW

Road transport and heating in buildings

(<20MW)

Small-scale energy industry and

industrial , aviation and maritime/water-

borne navigation activities below the

thresholds in Annex I of the Directive

CRF category not

covered by Annex III

Some other stationary combustion

activities >20 MW (e.g. pipeline transport

1A3e)

Agriculture, forestry, fishery, etc.

13

14

5.4.2 Methods to determine end consumers 15

The MRR provides a hierarchy of methods for regulated entities to determine the 16

scope factor of each fuel stream taking into account each method’s i.a. 17

robustness, risk of fraud, possibility for targeted cost pass-through and 18

administrative burden. 19

20

42 International Standard Industrial Classification of All Economic Activities

https://unstats.un.org/unsd/publication/SeriesM/seriesm_4rev4e.pdf 43 including installations excluded from the EU ETS pursuant to Article 27 of the Directive 44 including installations excluded from the EU ETS pursuant to Article 27a of the Directive

33

Table 5: Overview of the tier definitions for the scope factor 1

Tier Tier definition

1

Art. 75l(3): Default value of 1 (full scope coverage)

Art. 75l(4): (Default value lower than 1 if certain conditions are met; see below)

2

Art. 75l(2)(e): Chain-of-custody (IT-based or paper-based)

Art. 75l(2)(f): National marking

Art. 75l(2)(g): Indirect methods (correlations)

3

Art. 75l(2)(a): Physical distinction of flows

Art. 75l(2)(b): Chemical distinction of fuels

Art. 75l(2)(c): Chemical marking (Euromarker)

Art. 75l(2)(d): ETS1 verified annual emissions report data

2

Each method listed in 3

34

Table 5 is described in more detail below: 1

 Methods based on the physical distinction of fuel flows (Tier 3): 2

application of this method requires two criteria to be demonstrated: 3

 there is a physical distinction of fuel flows: for example, direct 4

measurements of fuel flows in pipeline networks to which only certain types 5

of end consumers are connected (e.g. households, or fuel stations only 6

dedicated for agriculture or heavy duty vehicles) or fuel flows to remote 7

areas (islands or areas without the existence of outward pipelines). In some 8

Member States, there are separate meters installed for the use of energy 9

products for a specific purpose, e.g. use of electricity only for heating 10

purposes. Potentially these methods could also be used for fuels covered 11

by the ETS2 or to distinguish them from non-ETS2 uses where it can be 12

demonstrated that only certain types of consumers are connected to those 13

separate meters. 14

 evidence can be provided that the end consumers either fall under the scope 15

of Annex III or not: this could be based on ‘legal zoning’, e.g. where the 16

consumers in an area connected to the pipeline are only, e.g. industrial 17

users (CRF 1A2), and legally are not to be allowed to carry out any other 18

economic activities. This evidence could also contain elements as explained 19

under ‘chain-of-custody’ below, such as a self-declaration from a fuel station 20

to which the pipeline is connected. This self-declaration could have the fuel 21

station confirm that they exclusively supply fuel to road transport, e.g. based 22

on commercial permits. 23

Note: despite possibly using similar elements as the ‘chain-of-custody’ 24

methods described below, this method is considered of higher quality. This 25

is because 1) this method is based on physical infrastructure, which cannot 26

be changed as easily (i.e. it cannot be supplied to other consumers) and 2) 27

due to this limited number of consumers, it is easier to identify the CRF 28

categories of end consumers. 29

 Methods based on the chemical properties of fuels (Tier 3): application of 30

this method requires two criteria to be demonstrated: 31

 that the chemical properties are distinct from other (similar) fuels: the purity, 32

the carbon or sulphur content, calorific value, or any additives added, etc. 33

This might be supported by laboratory analysis (e.g. in accordance with 34

Articles 32 to 35, where applicable) 35

 that this fuel is only suitable for specific purposes due to legal, technical or 36

economic reasons: 37

 Legal reasons: e.g. high-sulphur content fuels are for environmental 38

reasons legally only allowed to be combusted in combustion units 39

equipped with desulphurisation units, which small-scale consumers 40

outside Annex III (e.g. agricultural, small boats) do not have; 41

 Technical reasons: e.g. certain impurities in fuels would cause damage 42

to standard combustion units or engines and can therefore only be 43

combusted in large scale industrial sites covered by existing ETS; 44

 Economic reasons: e.g. high purity, high C-content coal is sold with a 45

price premium which makes it only viable for use as process material in 46

industry, but not for energy-purposes in e.g. for use in (non-)ferrous metal 47

industries. 48

35

 Use of fiscal marker in accordance with Council Directive 95/60/EC 1

(Tier 3): this would build on the existing practices of fiscal marking of gas oil 2

and kerosene under the Euromarker Directive. The provisions could be 3

extended to other fuels to distinguish between types of uses, i.e. end 4

consumers. This would likely be limited to liquid fuels, while application to 5

natural gas grids would need to be explored further. This is a common method 6

in some Member States to identify agricultural, navigation and aviation fuel 7

use, which are both outside the scope of ETS2. However, the sectoral 8

coverage of end consumers for which a certain colourant is used (i.e. 9

benefitting from reduced tax rates or exemptions) may differ from the CRF 10

sectors within the meaning of the scope of the ETS2. Even though the fiscal 11

marking method may therefore not solve all problems, it could be combined 12

with other methods and could nevertheless be helpful to solve parts of the 13

problem as many Member States have differentiated tax rates for e.g. 14

agricultural activities (although sometimes only for either motor fuels used in 15

off-road machinery or heating fuels), inland water navigation, aviation, etc. 16

 Use ETS1 operator’s annual emissions report ( section 5.4.3 on avoiding 17

double counting) 18

 Chain of traceable contractual arrangements and invoices (“chain of 19

custody”) (Tier 2): this would include e.g. IT-based or paper-based 20

documentation starting from end consumers (declaring their CRF category as 21

consumers for heating of buildings, for agricultural or industrial purposes, etc.) 22

up the supply chain to the reporting entity (supported by corresponding 23

contracts between the consumer and the supplier, where applicable, and 24

further contracts along the supply chain to report the information upstream, 25

where relevant). IT facilities could be systems established and owned by the 26

regulated entity extending to any trading partners, IT systems developed by 27

Member States, or extension of the existing EMCS45 to further trading partners 28

downstream of the excise duty point. In any case, end consumers would 29

confirm their type of use and amount of fuel (e.g. use for heating offices, 30

industrial or agricultural use, for example by using fuel cards upon pre-31

registration; see also example below). The potentially most suitable candidate 32

for such approach could be natural gas. Other than self-declaration further 33

sources of information about end consumers could be obtained from ex-ante 34

fiscal/technical or energy audits under the existing excise duty and energy 35

taxation procedures. Although these are often enforcement measures aimed 36

at consumers of the fuel, they could potentially be adapted to ensure regulated 37

entities (fuel suppliers) receive information on the use of the fuels they sell.38

39

Furthermore, it would not be necessary to have a self-declaration from all 40

(types of) end consumers, but only from either all that are covered by the scope 41

of ETS2, or from those that are not covered. In practice, as end users covered 42

by the scope would have no incentive to prove their CRF category as the price 43

of the fuel for them would be anyway the same, it is more practical to establish 44

a chain of custody to end users that are not covered by the scope. For instance, 45

as the number of agricultural consumers – who are not covered by the scope 46

of the ETS2 – is limited, self-declaration providing sufficient evidence as 47

regards their ETS2 scope from those consumers would be easier to implement 48

than self-declaration from the buildings or road transport sectors. Furthermore, 49

45 Excise Movement Control System (for use under Directive (EU) 2020/262)

36

a Member State’s national ETS2 authority may even already require a central 1

registration of those industrial consumers, e.g. consumers that are connected 2

to the gas grid, or consumers that choose to centrally register (via their 3

address, VAT number, their economic activity to confirm the status as 4

agricultural consumers46; CRF category 1A4c). Subsequently the Member 5

State could grant regulated entities access to this list in order to exclude 6

corresponding fuel amounts supplied from the annual emissions report. This 7

central registration could lead to higher legal certainty, more robust MRV and 8

easier verification, lower admin burden (due to centralisation) and lower risk of 9

any fraud (i.e. false self-declaration). 10

 Use of national markers or colours (dyes) for fuels (Tier 2): similar to the 11

fiscal markers under Euromarker Directive above but refers to markers only 12

regulated at the national level. Similar considerations apply. 13

 Indirect methods or estimation methods (Tier 2): here the CRF category of 14

the end consumers would not be determined directly but via other data or 15

information for which a high correlation with the type of sector is expected. This 16

would however not be a default value at the aggregated level (see example 17

below), but a correlation which allows distinction at the individual consumer 18

level, including: 19

 Pressure levels of natural gas supplied: e.g. large industrial customers 20

purchase gas at transmission pressure levels while buildings receive gas 21

at low-pressure level. 22

 Fuel consumption capacities or profiles: this would be based on e.g. certain 23

seasonal or day-and-night consumption capacities or patterns that could 24

allow attribution of the consumption to certain types of end consumers, such 25

as households or industrial sites. 26

 Using existing public databases: e.g. on urbanisation or zoning plans (to 27

distinguish industrial areas from the rest). Note: this is similar to ‘physical 28

distinction of fuel flows’ above. However, it is not accompanied with 29

infrastructural limititions (such as pipelines which simply do not allow the 30

supply to other consumers not connected to it), but on other considerations 31

such as economic reasons (e.g. transport costs to other areas might not be 32

viable). 33

 Default values (Tier 1): where none of the above methods is applicable ( 34

section 6.4 on derogations), the MRR allows for the use of default scope 35

factors and gives clear preference to setting this factor to “1” (i.e. assumes full 36

ETS2 coverage of end consumers and pass through carbon costs 37

correspondingly). However, the MRR also allows for the following exemptions 38

to deviate from this principle and use default values lower than 1: 39

 Years 2024 to 2026: for this period the MRR allows the use of a default 40

scope factor lower than 1, if the regulated entity can demonstrate that this 41

leads to more accurate determination of emissions (see example below); 42

 Years 2027+: default scope factors lower than 1 are only allowed if the 43

regulated entity can demonstrate that this leads to more accurate 44

46 Note: in order to confirm the correct system boundaries of activities that are exempted, the

information provided about the industrial facility would need to correspond to the exact meter the amounts measured by which are exempted. Such details will usually not be listed, but this information should be traceable in the internal procedures being part of the regulated entity’s monitoring plan under the MRR, granting verifiers access to this information.

37

determination of emissions and at least one of the following conditions 1

applies: 2

 The fuel stream is a de-minimis fuel stream, OR 3

 The default scope factor is either 0.05 or lower (where the tend 4

consumers are mostly not covered by ETS2), or 0.95 or higher (where they 5

mostly are covered by ETS2) 6

Note: Member States may require the regulated entities to use a specific method 7

listed below or a default value for a certain fuel type or in a certain region within 8

their territory, to allow for consistent monitoring and reporting in their jurisdiction. 9

In that case regulated entities might have limited options in choosing among the 10

methods below. The hierarchy of the required tiers, i.e. which methods have to 11

be applied and the reasons for regulated entities to deviate from those and use 12

lower tier methods is described in section 6.2 ff. 13

14

38

1

Example: illustration of the difference between the method ‘indirect/estimation’ and a ‘default

value lower than 1’

On the left side of Figure 6 the regulated entity has access to the consumption profiles of the

end consumers (e.g. a natural gas supplier directly connected to end consumers). Since the

regulated entity could demonstrate that Tier 3 methods are either not available or incur

unreasonable costs, it proposes to determine the scope factor based on indirect/estimation

methods. For the sake of simplifiaction of this example, the larger consumers (larger bubbles)

are considered outside the ETS2 scope (red bubbles), whereas smaller consumers are

considered covered by the scope (green bubbles). Correspondingly, a scope factor of “1” is

assigned to the fuel stream supplied to the green bubble and a scope factor of “0” to the

amounts supplied to the red bubbles. Correspondingly, the carbon costs are either passed

through or not. This method could lead to some end consumers being incorrectly assigned to

their respective CRF category (i.e. ETS2 coverage), which is the reason this method is

considered only Tier 2.

On the right side of Figure 6 the regulated entity supplies fuel to the same consumers, but does

not have access to consumption profiles (e.g. because intermediary parties are involved and a

‘chain-of-custody’ method cannot be established without the incurring unreasonable costs).

However, since the fuel is only consumed by consumers located in a certain area (e.g. to a city

connected to the natural gas grid), the regulated entity proposes to use a default scope factor

of lower than 1 that corresponds to the share of end consumers’ ETS2 coverage e.g. based on

national energy statistics for this city. If, for example, that factor was 0.5 (corresponding to 50%

ETS2 coverage of end consumers), the CA could only accept such a default value for 2024-

2026 (or also for 2027+, provided that the fuel stream is a de-minimis fuel stream), provided

that the regulated entity can demonstrate that it leads to a more accurate determination of

emissions.

The example shows that the main difference is that in the example 1: the regulated entity is

able to pass carbon costs through corresponding to the individual categorisation of each end

consumer; and in the example 2: the regulated entity is only able to identify the scope factor at

the aggregated level and a targeted cost pass-through is not feasible. Some consumers would

have too high cost pass-through and some too low. Furthermore, if all consumers in that region

were (not) covered by the ETS2 scope, this would qualify as the method: ‘physical distinction

of fuel flows’.

39

Figure 6: Example determination of the scope factor

1

2

5.4.3 Avoiding double counting between ETS1 and ETS2 3

ETS2 regulated entities are expected to pass on carbon costs to their consumers 4

downstream. Where the end consumers are ETS1 operators (installations, 5

aircrafts, ships) such cost pass-through would constitute double counting or a 6

double burden on them as they would have to bear both the ETS1 and ETS2 7

costs, this should be avoided. Before talking about the practical implications on 8

the ETS2 regulated entity’s monitoring of emissions, the following elements 9

contained in the MRR are relevant: 10

 The use of ETS1 operators’ annual emissions reports is considered as one of 11

the highest tiers (tier 3) methods available to determine the scope factor ( 12

section 5.4.2); 13

 Article 75v contains further provisions as to how to avoid double counting. 14

Article 75v(2) obliges ETS1 operators to report, together with their annual 15

emissions report, information on their fuel suppliers (whether an ETS2 16

regulated entity or not) and the annual amounts of fuels purchased from each 17

entity and consumed in the ETS1 regulated activities (Annex Xa)47; 18

 For the purpose of the 2nd bullet point above, Annex I(10) introduces a new 19

provision for the ETS1 operator to include in their MP a related description of 20

procedure on the calculation steps for the Annex Xa information. This will 21

include calculation methods on how to attribute fuel amounts to each regulated 22

entity from whom fuel has been acquired, parameters such as ‘fuel used for 23

ETS1 activities during the reporting year’, which requires to separate actual 24

consumption from ‘fuel put on stock’ and ‘fuel exported or used for non-ETS 25

47 Member States may require that operators make this information available to the regulated entity

concerned earlier than 31 March of the reporting year

Cut-off for

inclusion/exclusion

erroneously

included erroneously

excluded

Regulated entity Regulated entity

Identified as covered by ETS2 scope

Identified as not covered by ETS2 scope

Bubble size indicates fuel consumption capacity

[50]% cost pass-through 100% cost

pass-

through

0% cost

pass-

through

Scope factor method:

indirect/estimation

Scope factor method:

Default value

40

purposes (e.g. on-site vehicles)’. This provision will however only apply 1

mandatorily from30 June 2024 (earlier only on a voluntary basis), which means 2

that the first time Annex Xa information in the emission reports is made 3

available by ETS1 operators will likely not be submitted to the regulated entity 4

before the reporting year 2026. Guidance for ETS1 operators on calculations 5

and how to report results will be developed at a later stage; 6

 Annex Xb requires regulated entities to report on the amounts of fuels supplied 7

to each ETS1 operator including information such as clear identification of the 8

operators with their name address and the unique ID used for the EU ETS (this 9

could the one used for the EUTL registry or any national ID assigned by the 10

CA). 11

12

Based on the above, the following steps for regulated entities monitoring of fuels 13

supplied to ETS1 operators can be identified: 14

 As part of the scope factor, the requirements set out in Article 75v as well as 15

in Annexes Xa and Xb of the MRR, ETS2 regulated entity should aim to 16

establish a connection to the ETS1 operators they supply fuels to. 17

 Where there is a direct contractual relationship, this will be straightforward. 18

Where there are intermediary parties involved, i.e. fuel traders, the regulated 19

entity should engage with them to establish a ‘chain-of-custody’ ( see 20

guidance in section 5.4.2 on what this entails). 21

 If the regulated entity can demonstrate that if the methods listed in Art 75l(2) 22

(a-g) is technically not feasible or would incur unreasonable costs, it does not 23

have to identify corresponding amounts of fuel released and can apply a scope 24

factor of 1 to them. 25

 In order to apply a scope factor of 0 for those amounts of the respective fuel 26

stream, the following conditions would be necessary: 27

 There needs to be a direct contractual partnership between ETS2 entities 28

and the ETS1 operator and a contractual arrangement to agree on how the 29

supplied fuels will be invoiced. This could be called a declaration of intent to 30

use the fuels. 31

 After the reporting year, the ETS1 operator will provide the information 32

required by Annex Xa to the regulated enitity. This can be done directly, or 33

via the CA, as allowed for by Article 75v(1 and 2). 34

 The information and data pursuant to Annex Xa will contain a confirmation 35

of actual use of the fuel amounts. Implicitly, the difference between acquired 36

and used amounts will be a confirmation of any amounts put into stock or 37

exported further. Only the amounts labelled as confirmation of actual use 38

can have a scope factor of 0 applied. 39

 For any remaining amounts supplied to an ETS1 operator but confirmed as 40

per above, a scope factor of 1 has to be applied, and the carbon costs can 41

be passed through (once trading starts in 2027).The risk for the regulated 42

entity to surrender too many or too little allowances due to the difference 43

between sold fuel amounts and actual use in ETS1 installation has to be 44

agreed in contractual arrangements between the regulated entity and the 45

ETS1 installation. There are several ways for the regulated entity and the 46

ETS1 installation to arrange the risk. 47

48

41

1

5.5 Calculation factors – Principles 2

Besides the released fuel amounts, the “calculation factors” are important parts 3

of any MP based on the selected calculation methodology. These factors are the 4

(preliminary) emission factor, unit conversion factor and biomass fraction. The 5

scope factor is not included in the definition of ‘calculation factors’ and is 6

described in detail in section 5.4. 7

Calculation factors can be determined by one of the following principles: 8

a. As default values ( Section 5.5.1); or 9

b. by laboratory analyses ( section 5.5.2). 10

The applicable tier will determine which of these options is used. Lower tiers allow 11

for default values, i.e. for values which are kept constant across the years, and 12

updated only when more accurate data becomes available. The highest tier 13

defined for each parameter in the MRR is usually laboratory analysis, which is 14

more demanding, but of course more accurate. The result of each analysis is 15

valid for the batch from which the sample has been taken, while a default value 16

is usual an average or conservative value determined on the basis of big 17

quantities of that material. E.g. emission factors for coal as used in national 18

inventories might be applicable to a country-wide average of several coal types 19

as may also be used in energy statistics, while an analysis will be valid for only 20

one batch of one coal type. 21

22

Important note: In all cases the regulated entity must ensure that activity data 23

and all calculation factors are used consistently. I.e. where a fuel’s quantity is 24

determined in the wet state or of certain purity, the calculation factors must also 25

refer to those conditions. Regulated entities must also be careful not to mix up 26

parameters with inconsistent units. Where the amount of fuel is determined per 27

volume, also the unit conversion factor (UCF) or NCV and/or emission factor must 28

refer to volume rather than mass or energy48. 29

For almost all commercially traded fuels, this will be easily ensured as their 30

qualtify and properties will already be specified by the market actors. 31

Furthermore, in many cases, the fuels in question are deemed ‘commercial 32

standard fuels’ or ‘national standard fuels’ ( for further definition see section 0), 33

in which case national default values can be used for the calculation factors such 34

as the emission factor or NCV ( section 6.2). 35

36

5.5.1 Default values 37

When a regulated entity intends to use a default value for a calculation factor, the 38

value of that factor must be documented in the MP. The only exception is where 39

the default value or its information source changes on an annual basis. In 40

principle, this is the case where the competent authority regularly updates and 41

48 See section Fehler! Verweisquelle konnte nicht gefunden werden., in which conditions are

mentioned under which the regulated entity may use emission factors expressed as t CO2/t fuel instead of t CO2/TJ.

42

publishes the standard factors used in the national GHG inventory. In such cases, 1

the MP should contain the reference to the place (webpage, official journal, etc.) 2

where these values are published, instead of the value itself. 3

The applicable type of default value is determined by the applicable tier definition. 4

Sections 2 to 4 of Annex II of the MRR give a general scheme for these 5

definitions. The sector-specific monitoring methodologies in Annex IV further 6

specify those tiers, or sometimes overrule the tier definitions with more specific 7

ones. A complete listing of all tier definitions would significantly exceed the scope 8

of this guidance. However, a simplified overview of tier definitions given by Annex 9

II is presented in Table 6. 10

11

Table 6: Overview of the most important tier definitions for calculation factors, based 12

on Annex II of the MRR. The following abbreviations are used: 13

EF…Emission factor, UCF…Unit conversion factor, NCV…Net calorific 14

value, BF…Biomass fraction. The tier definitions are further specified in the 15

text below. 16

Factor Tier Tier definition

EF49 1 Type I default values

2a Type II default values

2b Empirical correlations (specific coal types)

3 Laboratory analyses or empirical correlations

UCF (e.g. NCV)

1 Type I default values

2a Type II default values

2b Purchasing records (if applicable)

3 Laboratory analyses

BF 1 Type I biomass fraction

2 Type II biomass fraction

3a Laboratory analyses

3b Mass balance of fossil and biomass carbon

17

As can be seen from Table 6, the lowest tier usually applies an internationally 18

applicable default value (IPCC standard factor or similar, as listed in Annex VI of 19

the MRR). The second tier uses a national factor, which is in principle that used 20

for the national GHG inventory under the UNFCCC. However, further types of 21

default values or proxy methods are allowed, which are deemed equivalent. The 22

highest tier usually requires the factor to be determined by laboratory analyses. 23

The definitions of tier levels in Table 6 have to be understood using the full text 24

as follows: 25

49 According to section 2.1 of Annex II of the MRR, the tiers defined shall relate to the preliminary

emission factor, where a biomass fraction is determined for a mixed fuel or material.

43

 Type I default values: Either standard factors listed in Annex VI (i.e. in 1

principle IPCC values) or other constant values in accordance with point (e) of 2

Article 31(1), i.e. analyses carried out in the past but still valid50. 3

 Type II default values: Country specific emission factors in accordance with 4

points (b), (c) and (d) of Article 31(1), i.e. values used for the national GHG 5

inventory51, other values published by the CA for more disaggregated fuel 6

types, or other literature values which are agreed by the competent authority52. 7

For category A entities, commercial standard fuels and fuel meeting 8

equivalent criteria ( section 0 for definitions) this will be the common 9

method to apply. 10

 Empirical correlations: These are methods based on empirical correlations 11

for specific coal types as determined at least once per year in accordance with 12

the requirements applicable for laboratory analyses (see 5.5.2). However, 13

because these rather complicated analyses are only carried out once per year, 14

this tier is considered a lower level than full analyses. 15

 Purchasing records: Only in the case of commercially traded fuels may the 16

unit coversion factor value be derived from the purchasing records provided by 17

the fuel trading partner, provided it has been derived based on accepted 18

national or international standards. 19

 Laboratory analyses: In this case, the requirements discussed in section 20

5.5.2 below are fully applicable. This also includes the use of the 'established 21

proxies', if applicable and where the uncertainty of the empirical correlation 22

does not exceed 1/3 of the uncertainty value associated with the applicable tier 23

for released fuel amounts. 24

 Type I biomass fraction53: One of the following methods is applied, these are 25

considered equivalent: 26

 Use of values published by the competent authority or by the Commission. 27

 Use of values in accordance with Article 31(1), i.e. a "Type I/II default value". 28

 Type II biomass fraction53: Use of a value determined in accordance with the 29

second subparagraph of Article 75m(3), i.e. use of an estimation method 30

approved by the competent authority. 31

 Mass balance of fossil and biomass carbon54: in this case the biomass 32

fraction is determined based on the mass balance of carbon of defined and 33

50 MRR Article 31(1)(e): “values based on analyses carried out in the past, where the [regulated entity]

can demonstrate to the satisfaction of the competent authority that those values are representative for future batches of the same fuel or material”. This is a considerable simplification for regulated entities, who do not have to carry out regular analyses as described in section 5.5.2. Article 75k declares Article 31(1) equally applicable to ETS2.

51 MRR Article 31(1)(b): “standard factors used by the Member State for its national inventory submission to the Secretariat of the United Nations Framework Convention on Climate Change“.Article 75k declares Article 31(1) equally applicable to ETS2.

52 MRR Article 31(1)(c): “literature values agreed with the competent authority, including standard factors published by the competent authority, which are compatible with factors referred to in point (b), but representative of more disaggregated sources of fuel streams”. Article 75k declares Article 31(1) equally applicable to ETS2.

53 Note that it is not discussed here how to determine whether the relevant sustainability and GHG savings criteria are met (if applicable). A short overview is given in section 5.6.4. For biogas in natural gas grids see section 5.6.5. More information on the treatment of biomass issues in the EU ETS are given in guidance document No. 3 (for reference see section 1.3).

54 Tier 3b: For fuels originating from a production process with defined and traceable input streams, the regulated entity may base the estimation on a mass balance of fossil and biomass carbon

44

traceable inputs. The typical example for this would be biofuel blended into 1

transport fuels, in which case the biomass fraction can simply be based on the 2

mass balance used to demonstrate compliance with the RED II criteria. This 3

should be readily available and consistent with biofuel amounts reported under 4

the Fuel Quality Directive55. 5

6

5.5.2 Laboratory analyses 7

Where the MRR refers to determination “in accordance with Article 32 to 35”56, 8

this means that a parameter must be determined by (chemical) laboratory 9

analyses. The MRR imposes relatively strict rules for such analyses, in order to 10

ensure a high quality of the results. In particular, the following points need 11

consideration: 12

 The laboratory must demonstrate its competence. This is achieved by one of 13

the following approaches: 14

 Accreditation in accordance with EN ISO/IEC 17 025, where the analysis 15

method required is within the accreditation scope; or 16

 Demonstrating that the criteria listed in Article 34(3) are satisfied. This is 17

considered a reasonably equivalent to the requirements of EN ISO/IEC 18

17 025. Note that this approach is allowed only where use of an accredited 19

laboratory is shown to be technically not feasible or involving unreasonable 20

costs ( section 6.4). 21

 The way samples are taken from the material or fuel to be analysed is 22

considered crucial for receiving representative results. Therefore, regulated 23

entities have to develop sampling plans in the form of written procedures ( 24

see section 6.6) and get them approved by the competent authority. Note that 25

this also applies where the regulated entity does not carry out the sampling 26

itself, but treats it as an outsourced process. 27

 Analyses methods usually have to follow international or national standards. 28

Preference is given to EN standards57. 29

Note that laboratory analyses are usually related to the highest tiers for 30

calculation factors. Therefore, these rather demanding requirements are rarely 31

applicable to smaller regulated entites. In particular regulated entities with low 32

emissions ( section 6.3.2) may use “any laboratory that is technically competent 33

and able to generate technically valid results using the relevant analytical 34

procedures, and provides evidence for quality assurance measures as referred 35

entering and leaving the process, such as the mass balance system in accordance with Article 30(1) of Directive (EU) 2018/2001.

55 Directive 2009/30/EC of the European Parliament and of the Council of 23 April 2009 amending Directive 98/70/EC as regards the specification of petrol, diesel and gas-oil and introducing a mechanism to monitor and reduce greenhouse gas emissions and amending Council Directive 1999/32/EC as regards the specification of fuel used by inland waterway vessels and repealing Directive 93/12/EEC

56 Article 75k declares Articles 32-35 of the MRR equally applicable to ETS2. 57 For the use of standards, Article 32(1) defines the following hierarchy: “The [regulated entity] shall

ensure that any analyses, sampling, calibrations and validations for the determination of calculation factors are carried out by applying methods based on corresponding EN standards. Where such standards are not available, the methods shall be based on suitable ISO standards or national standards. Where no applicable published standards exist, suitable draft standards, industry best practice guidelines or other scientifically proven methodologies shall be used, limiting sampling and measurement bias.”

45

to in Article 34(3)”. In fact, the minimum requirements would be that the laboratory 1

demonstrates that it is technically competent and “capable of managing its 2

personnel, procedures, documents and tasks in a reliable manner”, and that it 3

demonstrates quality assurance measures for calibration and test results58; 4

evidence for this needs to be sufficient to satisfy the competent authority and the 5

verifier However, it is in the regulated entity’s interest to receive reliable results 6

from the laboratory. Therefore regulated entities should strive to comply with the 7

requirements of Article 34 to the highest degree feasible. 8

Furthermore, it is important to note that the MRR in the activity-specific 9

requirements of Annex IV allows the use of “industry best practice guidelines” for 10

some lower tiers, where no default values are applicable. In such cases, where 11

despite approval to apply a lower tier methodology analyses are still required, it 12

may not be appropriate or possible to apply Articles 32 to 35 in full. However, the 13

competent authority should deem the following as minimum requirements: 14

 Where the use of an accredited laboratory is technically not feasible or would 15

lead to unreasonable costs, the regulated entity may use any laboratory that is 16

technically competent and able to generate technically valid results using the 17

relevant analytical procedures, and provides evidence for quality assurance 18

measures as referred to in Article 34(3). 19

 The regulated entity shall submit a sampling plan in accordance with Article 20

33. 21

 The regulated entity shall determine the frequency of analysis in accordance 22

with Article 35. 23

More detailed guidance on topics related to laboratory analyses, sampling, 24

frequency of analyses, equivalence to accreditation etc. are given in Guidance 25

Document No. 5. 26

27

5.6 Calculation factors – specific requirements 28

In addition to the general approaches for determining calculation factors (default 29

values / analyses) discussed in section 5.5, some specific rules for each factor 30

are laid down in the MRR. These are discussed below. 31

32

5.6.1 Unit conversion factor (UCF) 33

Article 3(6) of the MRR applies the definition “‘unit conversion factor’ meaning a 34

factor converting the unit in which released fuel amounts are expressed, into 35

amounts expressed as energy in terajoules, mass in tonnes or volume in normal 36

cubic metres or the equivalent in litres, where appropriate, which comprises all 37

relevant factors such as the density, the net calorific value or (for gases) the 38

conversion from gross calorific value to net calorific value, as applicable”. 39

In order to convert released fuel amounts into energy content (or to match the 40

units in the associated emissions factor where this is other than energy), the UCF 41

is an important parameter to be reported. Converting to an energy basis is the 42

58 Examples for such measures are given in Article 34(3), point (j): regular participation in proficiency

testing schemes, applying analytical methods to certified reference materials, or inter-comparison with an accredited laboratory.

46

standard approach defined in Article 75f and allows emission reports to be 1

compared with energy statistics and national GHG inventories under the 2

UNFCCC. 3

The UCF can comprise a range of different conversion factors, including the 4

following: 5

 For released fuel amounts expressed as tonnes or Nm³, the UCF could simply 6

be the net calorific value (NCV) of the fuel, expressed as TJ/t or TJ/1000Nm³. 7

 where the competent authority allowes the emission factors for fuels to be 8

expressed as t CO2/t fuel or t CO2/Nm3 (Article 75f59), the UCF would simply 9

equal 1 and NCV (the UCF in general) may be expressed determined based 10

on conservative estimates instead of using tiers, unless a defined tier is 11

achievable without additional effort (i.e. where tier-compliant information is 12

readily available, such as national GHG inventory values) (Article 75h(3)). 13

 For released fuel amounts already expressed as TJ (net energy content), the 14

UCF will equal 1 as no further conversion is necessary. 15

 Where released fuel amounts are expressed as gross GWh (as often the case 16

for natural gas), the UCF will be the conversion factor from gross GWh to net 17

TJ. 18

 For released amounts expressed as litres (e.g. liquid fuels), the UCF would 19

either be the density (t per litre) or the volumetric NCV, again depending on 20

the relevant units the emission factor is expressed as. 21

 etc. 22

23

5.6.2 Emission factor 24

Article 3(13) of the MRR applies the definition: “‘emission factor’ meaning the 25

average emission rate of a greenhouse gas relative to the activity data of …a fuel 26

stream assuming complete oxidation for combustion…”. Furthermore Article 27

3(36) is important for materials containing biomass, stating: “‘preliminary 28

emission factor’ means the assumed total emission factor of a fuel or material 29

based on the carbon content of its biomass fraction and its fossil fraction before 30

multiplying it by the fossil fraction to produce the emission factor”. 31

Important: According to section 2.1 of Annex II of the MRR, the tiers defined in 32

the MRR shall relate to the preliminary emission factor, where a biomass fraction 33

is determined for a fuel or material. I.e. tiers are always applicable to individual 34

parameters. The reporting of the preliminary emission factor is mandatory for all 35

fuel streams (i.e. including 100% biomass fuel streams)60. 36

As reflected by the definition, the emission factor (EF) is the stoichiometry-based 37

factor which converts the (fossil) carbon content (CC) of a material into the 38

equivalent mass of (fossil) CO2 assumed to be emitted. 39

59 This may be allowed by the competent authority if the use of an emission factor expressed as t

CO2/TJ would incur unreasonable costs, or where at least equivalent accuracy can be achieved with this method.

60 This is not a large administrative burden, since pure biomass fuel streams are always de-minims fuel streams, so that a low tier may be applied. Most appropriate will be the use of default values for the dry biomass, corrected for the moisture content. The latter may be estimated or measured. More guidance is found in Guidance Document No. 3, which also contains some typical preliminary emission factors in an Annex.

47

For combustion emissions, the standard approach to the emission factor is to 1

express it in relation to the energy content (NCV) of the fuel rather than its mass 2

or volume. However, the competent authority may allow the regulated entity to 3

use an alternate emission factor expressed as t CO2/t fuel or t CO2/Nm3 (Article 4

75f). 5

Where the applicable tier requires the emission factor to be determined by 6

analyses, the carbon content is to be analysed. For fuels, the NCV must also be 7

determined (depending on the tier, this may require another analysis of the same 8

sample). 9

If the emission factor of a fuel expressed as t CO2/TJ is to be calculated from the 10

carbon content, the following equation is used with f corresponding to the 11

stoichiometric factor of 3.664 to convert C into CO2: 12

(11) 13

If the emission factor of a material or fuel expressed as t CO2/t is to be calculated 14

from the carbon content (CC), the following equation is used: 15

(12) 16

17

18

5.6.3 Biomass fraction 19

In order for biomass used for combustion to be zero-rated (i.e. for

applying an emission factor of zero), the biomass must satisfy the

sustainability and GHG savings criteria defined by the RED II Directive61

(Article 38(5) of the MRR). From 1 January 2022, the MRR requires that

biomass complies with the criteria set out in the RED II.

An introduction to the topic is given in section 5.6.4. A separate guidance

document62 is provided explaining biomass-related topics in detail.

20

5.6.4 Applicability of RED II criteria 21

In most cases where “biomass” is mentioned in the MRR, it is added that “Article 22

38(5) applies”63 via reference in Article 75m(1). That article64 clarifies the 23

62 Guidance document No. 3. For reference see section 1.3. 63 An exception is Article 75d(2) on unreasonable costs. In that context, Article 38(5) applies only

“provided that the relevant information … is available to the [regulated entity]”. This condition is relevant because at the point in time when unreasonable costs are determined, it is often not clear yet whether the biomass intended to be used will comply with Article 38(5) or not.

64 Article 38(5) of the MRR:

„Where reference is made to this paragraph, biofuels, bioliquids and biomass fuels used for combustion shall fulfil the sustainability and the greenhouse gas emissions saving criteria laid down in paragraphs 2 to 7 and 10 of Article 29 of Directive (EU) 2018/2001.

However, biofuels, bioliquids and biomass fuels produced from waste and residues, other than agricultural, aquaculture, fisheries and forestry residues are required to fulfil only the criteria laid down in Article 29(10) of Directive (EU) 2018/2001. This subparagraph shall also apply to waste and residues that are first processed into a product before being further processed into biofuels, bioliquids and biomass fuels.

NCVfCCEF /

fCCEF 

48

relationship between the MRR requirements and the RED II, and in particular how 1

the sustainability and GHG saving criteria of the RED II are to be applied in order 2

to allow the emissions from biomass to be zero-rated. The following points are 3

worth noting: 4

 As the RED II applies to renewable energy, the RED II criteria apply only to 5

energy uses of biomass in the EU ETS. 6

 Not all the criteria given in Article 29 of the RED II apply. In particular: 7

 The “land-related” sustainability criteria of Article 29(2) to (7) of the RED II 8

apply; 9

 The GHG saving criteria of Article 29(10) of the RED II apply; 10

 The additional efficiency criteria for electricity production (Article 29(11) of 11

the RED II) do not apply; 12

 Some provisions contained in Article 29(1) of the RED II are copied into the 13

MRR in order to clarify their applicability. In particular, this includes the 14

simplification that for municipal solid waste the GHG saving criteria do not 15

apply. Furthermore, the RED II criteria apply irrespective of the geographical 16

origin of the biomass. 17

 The most relevant fuels in the ETS2 are biofuels blended with fossil petrol and 18

diesel for the transport sector and biogas ( section 5.6.5). For biofuels, 19

demonstration with the RED II compliance should already be ensured under 20

the corresponding reporting obligations of the Fuel Quality Directive65 and 21

evidence on the sustainability and GHG savings criteria therefore readily 22

available. 23

Article 75m(2) furthermore links the applicability of the RED II criteria to the 24

thresholds referred to in the fourth sub-paragraph of Article 29(1) of the RED II. 25

The latter says that, for the purposes of the RED II, the RED II criteria shall only 26

apply: 27

 to solid fuels produced from biomass, such as firewood, only if they are 28

combusted in installations exceeding 20 MW (the revised RED II lowers this 29

threshold to 7.5 MW). However, as discussed in section 2.2, solid biomass is 30

not part of the fuels covered by ETS2, hence the RED II criteria do currently 31

not apply. 32

 to gaseous biomass fuels, only if they are combusted in installations exceeding 33

2 MW ( section 5.6.5). 34

Electricity, heating and cooling produced from municipal solid waste shall not be subject to the criteria laid down in Article 29(10) of Directive (EU) 2018/2001.

The criteria laid down in paragraphs 2 to 7 and 10 of Article 29 of Directive (EU) 2018/2001 shall apply irrespective of the geographical origin of the biomass.

Article 29(10) of Directive (EU) 2018/2001 shall apply to an installation as defined in Article 3(e) of Directive 2003/87/EC.

The compliance with the criteria laid down in paragraphs 2 to 7 and 10 of Article 29 of Directive (EU) 2018/2001 shall be assessed in accordance with Articles 30 and 31(1) of that Directive.

Where the biomass used for combustion does not comply with this paragraph, its carbon content shall be considered as fossil carbon.”

Article 75m(1) declares Article 38 equally applicable to ETS2. 65 Directive 2009/30/EC of the European Parliament and of the Council of 23 April 2009 amending

Directive 98/70/EC as regards the specification of petrol, diesel and gas-oil and introducing a mechanism to monitor and reduce greenhouse gas emissions and amending Council Directive 1999/32/EC as regards the specification of fuel used by inland waterway vessels and repealing Directive 93/12/EEC.

49

1

If more details are needed, please consult Guidance Document No. 3 which can 2

be downloaded from DG CLIMA’s MRVA website66. 3

4

5.6.5 Special rules for biogas 5

Regulated entities may make use of a special approach to the accounting of 6

biogas pursuant to Article 39(4)67. Where biogas is injected into natural gas grids 7

and purchased by a regulated entity, the said entity may report that purchased 8

amount of biogas. This is done by determining and assigning a biomass fraction 9

to the total gas (natural gas plus biogas) based on the fraction of energy content 10

of biogas in the total gas consumption. Although not explicitly mentioned in the 11

MRR, it seems appropriate that such an approach should be considered 12

equivalent to tier 2 (like other estimation methodologies). 13

The preconditions for that approach are: 14

 The quantity of biogas used is determined from purchase records; 15

 The regulated entity demonstrates to the satisfaction of the CA that there is no 16

double counting of the same quantity of biogas. This can be done in particular 17

by making use of a “biogas registry” system or similar database, which also 18

ensures that there is no guarantee of origin disclosed to other users of the 19

biogas. This means that the guarantee of origin (if it has been generated at all) 20

must be closely linked to the defined physical quantity of biogas and cannot be 21

given (“disclosed”) to another gas consumer; 22

 The sustainability and GHG savings criteria laid down in the RED II are 23

complied with. 24

 Furthermore, as mentioned in the previous section 5.6.4, the RED II criteria 25

only apply if the biogas is combusted in installations exceeding 2 MW, 26

pursuant to Article 75m(2). Conversely, this means that the RED II criteria do 27

not apply where the regulated entity can demonstrate that the end consumer’s 28

combustion units are below 2 MW. However, in order to avoid administrative 29

burden where the end consumers’ capacity is not known (e.g. if not already 30

used for the determination of the scope factor  section 5.4), while at the same 31

time not follow an assumption that does not respect the relevant threshold in 32

the RED II, the regulated entity may assume the criterion to apply at the 33

aggregated consumer level. The latter would mean to sum up the capacity of 34

all consumers of the regulated entity, which equals their own total capacity of 35

supply, and compare it against the 2 MW threshold in order to determine 36

whether the RED II criteria apply. 37

Further guidance to the application of these criteria is given in Guidance 38

Document 3 (“Biomass issues in the EU ETS”). 39

40

66 https://climate.ec.europa.eu/system/files/2022-10/gd3_biomass_issues_en.pdf 67 Article 75m(1) declares Article 39, with the exception of paragraph 2 and 2a, applicable to ETS2.

50

6 THE MONITORING PLAN 1

6.1 Developing a monitoring plan 2

This chapter describes the way a regulated entity can develop a monitoring plan 3

(MP). When developing a MP, regulated entities should follow some guiding 4

principles: 5

 Knowing in detail the situation, the regulated entity should make the monitoring 6

methodology as simple as possible. This is achieved by attempting to use the 7

most reliable data sources, robust metering instruments, short data flows, and 8

effective control procedures. There will certainly be a lot of synergies with the 9

existing reporting requirements under the ETD/ED regime, where applicable. 10

 Regulated entities should imagine their annual emission report from the 11

verifier’s perspective. What would a verifier ask about on how the data has 12

been compiled? How can the end to end data flow be made transparent? 13

Which controls prevent errors, misrepresentations, omissions? 14

 Monitoring plans must be considered living documents to a certain extent. In 15

order to minimise administrative burden, regulated entities should be careful 16

which elements are laid down in the MP itself, and what can be put into written 17

procedures supplementing the MP. 18

Note: for regulated entities with low emissions and some other “simple” 19

entities, this chapter is only partly relevant. It is advisable to consult 20

chapter 7 of this document first. 21

22

The following step-by-step approach might be considered helpful: 23

1. Define the regulated entity’s boundaries taking into account the provisions 24

described in chapter 2. 25

2. Determine the regulated entity’s category ( see section 6.3.1) based on an 26

estimate of the annual GHG emissions. 27

3. List all fuel streams ( for definitions see section 0) and classify them into 28

major and de-minimis. 29

4. Identify the tier requirements based on the regulated entity category and the 30

fuel stream classification (see section 6.2). 31

5. List and assess potential sources of data: 32

a. For released fuel streams activity data (for detailed requirements see 33

section 5.3): 34

i. How can the amount of fuel or material be determined? 35

 Are measurement methods the same as used under the 36

ETD/ED regime and subject to national legal metrological 37

control? If so, those measurements methods can also be used 38

for the purposes of ETS2 and you may go directly to (b) below 39

for the ‘scope factor’. 40

 Are there instruments for continual metering, such as flow 41

meters, weighing belts etc. which give direct results for the 42

amount of material entering or leaving the stocks over time? 43

51

 Or must the fuel or material quantity be based on batches 1

purchased? In this case, how can the quantity in stock piles or 2

in tanks at the end of the year be determined? 3

ii. Are measuring instruments owned/controlled by the regulated entity 4

available? 5

 If yes: What is their uncertainty level? Are they difficult to 6

calibrate? Are they subject to national legal metrological 7

control68? 8

 If no: Can measuring instruments be used which are under the 9

control of the trading partner? (This is often the case for gas 10

meters, and for many cases where quantities are determined 11

based on invoices.) 12

iii. Estimate uncertainty associated with those instruments and 13

determine the achievable tier associated. Note: For uncertainty 14

assessment several simplifications are applicable, in particular if the 15

measuring instrument is subject to national legal metrological 16

control. 17

b. Scope factor 18

i. For all regulated entities and fuel streams, the starting point is to 19

apply the highest tier, Tier 3, unless Member States require the use 20

of a specific method. Therefore, can the end consumers’ sectors be 21

identified based on physical or chemical distinction of fuel (flows)? 22

Is the Euromarker Directive applicable? Can a contractual link be 23

established with the ETS1 operators fuels are supplied to? 24

ii. If none of the above are applicable or can be demonstrated to incur 25

unreasonable costs, can other methods lead to more accurate 26

results (demonstrated based on a simplified uncertainty 27

assessment)? 28

iii. Where ii. applies, are there national markers? If there is a direct 29

contractual relationship with end consumers, try to establish a 30

‘chain-of-custody’ via e.g. self-declaration by each consumer, or try 31

to establish ‘indirect methods’ for a correlation between the end 32

consumers’ sectors and e.g. annual consumption levels or 33

capacities, daily/seasonal consumption patterns. Where there is no 34

direct contractual relationship, try to involve intermediary traders in 35

passing information from end consumers back to you. 36

iv. If none of the above is possible without incurring unreasonable 37

costs, apply Tier 1: a default value of 1, unless a default value below 38

1 can be demonstrated to provide more accurate results. 39

c. Calculation factors (NCV, emission factor or carbon content, oxidation or 40

conversion factor, biomass fraction): Depending on the required tiers 41

68 Some measuring instruments used for commercial transactions are subject to national legal

metrological control. Special requirements (simplified approaches) are applicable to such instruments under the MRR. See guidance document No. 4 (for reference see section 1.3) for details.

52

(which are determined based on regulated entity category and fuel 1

stream classification): 2

i. Are default values applicable? If yes, are values available? (Annex 3

VI of the MRR, publications of the competent authority, national 4

inventory values)? 5

ii. If the highest tiers are to be applied, or if no default values are 6

applicable, chemical analyses have to be carried out for determining 7

the missing calculation factors. In this case the regulated entity must: 8

 Decide on the laboratory to be used. If no accredited 9

laboratory69 is available or its use incurs unreasonable costs, 10

establish evidence on the equivalence to accreditation of the 11

laboratory selected to EN ISO 17025 (see section 5.5.2); 12

 Select the appropriate analytical method (and applicable 13

standard); 14

 Design a sampling plan (see Guidance Document No. 5 (for 15

reference see section 1.3)). 16

6. Can all required tiers be met? If not, can a lower tier be met, if allowed in 17

accordance with rules on technical feasibility and unreasonable costs ( 18

section 6.4)? 19

7. In the next step, the regulated entity should define all end to end data flows 20

(who takes what data from where, does what with the data, hands over the 21

results to whom, etc.) from the measuring instruments or invoices to the final 22

annual report. The design of a flow diagram will be helpful. More details on 23

data flow activities are found in section 6.7. 24

8. With this overview of the data sources and data flows, the regulated entity 25

can carry out a risk analysis of its accounting process to identify potential 26

weaknesses (see section 6.7). Thereby it will determine where in the system 27

errors might occur most easily. 28

9. Using the risk analysis, the regulated entity should: 29

a. Assess which measuring instruments and data sources to use for activity 30

data (see point 5.a above). Where there are several possibilities, the one 31

with the lowest uncertainty and lowest risk should be used; 32

b. In all other cases which need decisions70, decide based on the lowest 33

associated risk; and 34

c. Define control activities for mitigating the identified risks (see section 6.7). 35

10. It may be necessary to repeat some of the steps 5 to 9, before finally writing 36

down the MP and the related procedures. In particular, the risk analysis will 37

need update after having the control activities defined. 38

11. The regulated entity will then write the MP (using the templates provided by 39

the Commission, an equivalent template by a Member State or a dedicated 40

69 „Accredited laboratory“ is used here as short form of “a laboratory which has been accredited

pursuant to EN ISO/IEC 17025 for the analytical method required”. 70 E.g. where several departments could handle the data, choose the most suitable with the lowest

number of error possibilities.

53

IT system provided by the Commission or a Member State), and the required 1

supporting documents (Article 12(1)): 2

a. The result of the risk assessment ( section 6.7), showing that the 3

defined control system is appropriately mitigating the identified risks (not 4

required for entities with low emissions  chapter 7); 5

b. Further documents (such as regulated entity description and diagram, 6

data flow diagram etc) may need to be attached; 7

c. The written procedures referenced by the MP need to be developed, but 8

do not need to be attached to the MP when submitting it to the CA71 (see 9

section 6.6 on procedures). 10

The regulated entity should make sure that all versions of the MP, the related 11

documents and procedures are clearly and uniquely identifiable, and that the 12

most recent versions are always used by all staff involved. A good document 13

management system is advisable from the beginning. 14

15

6.2 Selecting the correct tier 16

The system for defining the minimum required tiers is laid down in Articles 75h 17

(released fuel amounts) and 75i (scope factor). The overarching rule is that the 18

regulated entity should apply the highest tier defined for each parameter. 19

For major fuel streams within Category B regulated entities this is mandatory. For 20

other fuel streams and smaller entities, the following set of rules defines the 21

exceptions from the rule: 22

1. Instead of the highest tiers defined, category A regulated entities are required 23

to apply at least the tiers specified in Annex V of the MRR for major fuel 24

streams. 25

2. Regardless of the regulated entity category, the same tiers in Annex V for 26

calculation factors are applicable to commercial standard fuels72 or fuels 27

meeting equivalent criteria ( section 0). 28

3. Where the regulated entity demonstrates to the satisfaction of the competent 29

authority, that applying the tiers required by the previous points leads to 30

unreasonable costs ( section 6.4) or is technically not feasible ( section 31

6.4), the regulated entity may apply to major fuel streams a tier which is up 32

to two levels lower. Tier 1 is always the lowest possible tier. 33

Regulated entities are also expected to apply tiers equal to or higher than Tier 1 34

to de-minimis fuel streams where this can be achieved “without additional effort” 35

(i.e. without any notable costs). For released fuel amounts this means basing the 36

determination of released fuel amounts on invoices or purchase records, unless 37

a defined tier is achievable without additional effort. The regulated entity should 38

describe this method in the MP. 39

71 although the CA may ask to see copies of procedures as part of their approval process 72 Article 3(32) defines: ‘commercial standard fuel’ means the internationally standardised

commercial fuels that exhibit a 95% confidence interval of not more than 1% for their specified calorific value, including gas oil, light fuel oil, gasoline, lamp oil, kerosene, ethane, propane, butane, jet kerosene (jet A1 or jet A), jet gasoline (jet B) and aviation gasoline (AvGas). Commercial standard fuels are considered easy to monitor.

54

Where the CA has allowed to use emission factors expressed as t CO2 per tonne 1

(or Nm3) instead of t CO2/TJ, the NCV may be determined by using conservative 2

estimates instead of using tiers. However, the highest tier which does not involve 3

additional efforts should be the one applied. The full system of tier selection 4

requirements is summarised in Table 7. 5

6

Important note: The MP always has to reflect the tier actually applied, not the 7

minimum one required. The general principle is also that regulated entities should 8

attempt to improve their monitoring systems wherever possible. 9

10

55

55

Table 7: Summary of tier requirements. Note that this is only a brief overview. For detailed information the full text of this section should be consulted.

Regulated entity

category

Fuel stream

category

Tier required

(scope factor)

Minimum tier required

(released fuel amounts and

calculation factors)

Calculation factors for commercial

standard fuels or fuels meeting

equivalent criteria (Art. 75k(2))

Cat. B

(> 50kt)

Major

highest tier or

Member State requirement

highest tier

tier 2a/2b (Annex V)

de-minimis conservative estimates unless tier is

achievable without additional effort

Cat. A

(≤ 50kt)

Major tier in Annex V (EF: 2a/2b)

de-minimis conservative estimates unless tier is

achievable without additional effort

Entity with low

emissions

(< 1 000t)

Major tier 1

de-minimis conservative estimates unless tier is

achievable without additional effort

Reasons for derogation

from required tiers

technical infeasibility (or not

available), unreasonable

costs, or simplified

uncertainty assessment

technical infeasibility or unreasonable costs

56

6.3 Categorisation of regulated entities and fuel streams

It is the basic philosophy in the MRV system of the EU ETS, that the largest

emissions sources should be monitored most accurately, while less ambitious

methods may be applied so smaller emissions sources. By this method, cost

effectiveness is taken into account, and unreasonable financial and

administrative burden is avoided where the benefit of more efforts would be only

marginal.

6.3.1 Regulated entity categories

For the purpose of identifying the required “ambition level” for monitoring (details

will be given in section 6.2), the regulated entity has to categorise the regulated

entity according to its average annual emissions (Article 75e(2)):

 Category A: Annual average emissions are equal to or less than 50 000 tonnes

of CO2(e);

 Category B: Annual average emissions are more than 50 000 tonnes of CO2(e).

The “annual average emissions” here mean the annual average verified

emissions of the previous trading period from 2031 onwards. As for annual

reporting, emissions from sustainable73 biomass are excluded (i.e. zero-rated).

However, since verified emissions are not yet available (only as of 2026), the

regulated entity shall use a conservative estimate for the first MP.

Where those average annual verified emissions are not available or no longer

representative a conservative estimate of annual average emissions must be

applied concerning the projected emissions for the next five years.

The MRR allows that an entity which exceeds one of the mentioned thresholds

only once in six years does not have to change its categorisation. For example,

a category A entity that emits 51 000 t CO2 in one year only, does not have to

change its category if the regulated entity demonstrates to the CA that its

emissions were below 50 000 t CO2 in the five preceding years and will not be

exceeded again in subsequent reporting periods. What is more important, this

also means that the applicable minimum tiers do not change due to this one year

of higher emissions, and the regulated entity does not have to submit an updated

MP for approval.

6.3.2 Regulated entity with low emissions

Regulated entities which on average emit less than 1 000 t CO2(e) per year can

be classified as “regulated entity with low emissions” in accordance with Article

75n of the MRR. For these, special simplifications of the MRV system are

applicable in order to reduce administrative costs (see section 7).

As for other regulated entity categories, the annual average emissions are to be

determined from 2031 onwards as average annual verified emissions of the

73 This means that the biomass – if used for combustion – must comply with the sustainability

and GHG savings criteria established by the RED II in order to be “zero-rated”. For further details on biomass see section 5.6.4. Note that this requirement only applies from 1 January 2022.

57

previous trading period, with exclusion of CO2 arising from sustainable73 biomass.

From 2027 to 2030 the annual average emissions are based on the average

verified annual emissions in the 2 years preceding the reporting period.

Where those average emissions are not available a conservative estimate is to

be used concerning the projected emissions for the next five years.

A special situation then arises if the regulated entity’s emissions exceed the

threshold of 1 000 t CO2 per year. In that case it is necessary to revise the MP

and submit a new one to the CA, for which the simplifications can no longer be

applied. However, the wording of Article 75n(6) third subparagraph allows that

the regulated entity may continue as an entity with low emissions provided that it

can demonstrate to the competent authority that the 1 000 t CO2 per year

threshold has not been exceeded in the previous five years and will not be

exceeded again. Thus, high emissions in one single year out of six years may be

tolerable, but if the threshold is exceeded again in one of the following five years,

that exception will not be applicable anymore.

6.3.3 Identification and categorisation of fuel streams

The identification of fuel streams comprises the following two steps:

 Splitting the fuels released for consumption into fuel streams;

 Categorisation of those fuel streams.

Splitting into fuel streams

The split into fuel streams should take into account the following aspects:

 fuel streams can only be fuels that fall under the scope of EU ETS Directive

Article 3(af), which refers to the fuels covered in Article 2(1) of the ETD or any

other product intended for use, offered for sale or used as motor fuel or heating

fuel as specified in Article 2(3) of the ETD including for the production of

electricity ( section 2.2);

 fuels for consumption can be released by different means. Such means could

be via pipelines, truck deliveries, shipping, intermediary parties (e.g. further

fuel traders without their own tax warehouse), etc.

 the types of end consumers as identified by their CRF categories

( section 5.4.1);

 the methods applied to determine the scope factor ( section 5.4.2).

Ideally, the split into fuel streams should be at a level of aggregation which allows

for only one means through which the fuels are released, only one method for the

scope factor (at least only one tier) and only one CRF category. This would greatly

facilitate the competent authority’s approval of the MP and the verification of the

annual emissions report, allowing spotting of related risks more easily. The two

examples at the end of this section should help to illustrate this approach.

Categorisation of fuel streams

The regulated entity has to classify all fuel streams and compare the

corresponding emissions to the “total of all monitored items”.

58

The following steps have to be performed:

 Determine the “total of all monitored items”, by adding up:

 The emissions (CO2(e)) of all fuel streams which are determined (see below);

 For this calculation, CO2 from fossil sources as well as “non-sustainable73

biomass” is taken into account.

 Thereafter the regulated entity should list all fuel streams sorted in descending

order of associated emissions quantity.

 The regulated entity may then select fuel streams which it wants to be

classified as “de-minimis” fuel streams, in order to apply reduced monitoring

requirements to them, where relevant. For this purpose, the thresholds given

below must be complied with.

The regulated entity may select as de-minimis fuel streams: fuel streams which

jointly correspond to less than 1 000 tonnes of fossil CO2 per year. All other fuel

streams are classified as major fuel streams.

The MRR allows that an entity which exceeds one of the mentioned thresholds

only once in six years does not have to change its classification. This means that

the applicable minimum tiers do not change due to this one year of higher

emissions, and the regulated entity does not have to submit an updated MP for

approval.

Example: A supplier of oil products stores two different types of fuels in its tax

warehouse. One is Diesel oil which contains 10% of biomass liquids intended

for the road transport sector, the other is heating oil for buildings. While the

majority of the amount of fuels is transferred to fuel traders via pipelines, small

amounts of the heating oil is transferred onto trucks to fuel traders mostly active

in the buildings sector and fuel stations. It might therefore be most useful to

identify four different fuel streams:

1. the diesel oil released for consumption via pipelines to fuel traders;

2. the heating oil released for consumption via pipelines to fuel traders;

3. the heating oil released for consumption via trucks to fuel traders (mostly

active in the buildings sector);

4. the diesel oil transferred via trucks to fuel stations.

59

Example: categorisation of fuel streams

Fuel

stream

Emissions

(t CO2)

Means

through

which

released

(Intermediate)

consumer

End

consumer

sector

(CRF)

Scope

factor

method

Scope

factor

1. Light

fuel oil 1

50 000

(major)

Pipelines Energy

Industry

(non-ETS1)

1A1a Tier 2 (chain-

of custody)

1

2. Light

fuel oil 2

30 000

(major)

Pipelines ETS1

installations

Energy

Industry

(power plant)

1A1a Tier 3 (ETS1

verified

emission

report)

0

3.

Gasoline

25 000

(major)

Trucks Fuel stations 1A3b Tier 2 (chain-

of custody)

0.85

4. Light

fuel oil 3

5 000

(major)

Trucks ETS1

installations

Industry

1A2c Tier 3 (ETS1

verified

emission

report)

0

5. Light

fuel oil 4

1 500

(major)

Trucks Industry 1A2 Tier 2 (chain-

of custody)

1

6. Light

fuel oil 5

300

(de-minimis)

Trucks unknown 1A Tier 1 1

6.4 Reasons for derogation

The MRR allows derogation from the required tiers for released fuel amounts and

any factor if any of the following can be demonstrated ( see Table 7):

 Unreasonable costs

 Technically not feasible

 In addition, the following derogations apply only for the scope factor

 Tier 3 methods are not available

 Simplified uncertainty assessment ( section 6.4.2)

Cost effectiveness is an important concept for the MRR. It is generally possible

for the regulated entity to get permission from the competent authority to derogate

from a specific requirement of the MRR (in particular the required tier level), if

fully applying the requirement would lead to unreasonable costs. Therefore, a

clear-cut definition for “unreasonable costs” is required. This is found in Article

75d of the MRR. As outlined in section 6.4.1 below, it is based on a cost/benefit

analysis for the requirement under consideration.

60

Similar derogations may be applicable if a measure is technically not feasible.

Technical feasibility is not a question of cost/benefit, but whether the regulated

entity is able in practice to achieve a certain requirement at all. Article 75c of the

MRR requires that a regulated entity provides a justification where it claims

something to be technically not feasible. This justification must demonstrate that

the regulated entity does not have the technical resources available to meet the

specific requirement within the required time. Where this can be demonstrated, it

would usually lead to unreasonable costs as well.

6.4.1 Unreasonable costs

When assessing whether costs for a specific measure are reasonable, the costs

are to be compared with the benefit it would give. Costs are considered

unreasonable where the costs exceed the benefit (Article 75d).

Costs: It is up to the regulated entity to provide a reasonable estimation of the

costs involved. Only costs which are additional to those applicable for the

alternative scenario should be taken into account. The MRR also requires that

equipment costs are to be assessed using a depreciation period appropriate for

the economic lifetime of the equipment. Thus, the annual costs during the lifetime

rather than the total equipment costs are to be used in the assessment.

Furthermore, when applying a certain monitoring methodology, the MRR also

requires any costs incurred by (final) consumers to be take into consideration.

This can be particularly important when selecting the method for the scope factor.

Example: An old measuring instrument is to be exchanged for a new one. The

old instrument has allowed reaching an uncertainty of 3% corresponding to tier

2 (±5%) for released fuel amounts (for tier definitions see section 5.3.1).

Because the regulated entity would have to apply a higher tier anyway, it

considers whether a better instrument would incur unreasonable costs.

Instrument A costs 40 000 € and leads to an uncertainty of 2.8% (still tier 2),

instrument B costs 70 000 €, but allows an uncertainty of 2.1% (tier 3, ±2.5%)

to be achieved. Based on a typical economic lifetime of the measuring

equipment, a depreciation period of 8 years is considered appropriate.

The costs to be taken into account for the assessment of unreasonable costs

are 30 000 € (i.e. the difference between the two meters) divided by 8 years,

i.e. 3 750 €. No cost for the working time should be considered, as the same

workload is assumed to be necessary independent of the type of the meter to

be installed. Also the same maintenance costs can be assumed as an

approximation.

61

Example: For the determination of the scope factor, the regulated entity

demonstrates that none of the Tier 3 methods are available (i.e. no

physical/chemical distinction possible, Euromarker not applicable, etc.).

Therefore, the regulated entity explores the option to establish a Tier 2 ‘chain-

of-custody’ method involving a self-declaration from their directly connected

end consumers (i.e. those they already have a direct contractual relation with)

via an update of existing Terms & Conditions. As an alternative, the regulated

entity also considers the ‘indirect method’ via correlation between annual

amounts and CRF categories.

The assessment of unreasonable costs concerning implementation of either of

those approaches will be done by comparing it to the alternative Tier 1 –

Default value of 1 method, which would mean all end consumers not covered

by Annex III of the EU ETS Directive have to apply for ex-post compensation

of the incurred carbon costs that are passed through.

The costs to be taken into account will therefore include the regulated entity’s

own additional costs (investment in IT software, studies for the correlation, staff

costs, etc). But further to that, the assessment should also take into

consideration the administrative burden incurred (e.g. for paying a fee for ‘fuel

cards’) or also saved by the end consumers for not having to apply for ex-post

compensation (Tier 1) but only having to agree to the updated Terms &

Conditions (‘chain-of-custody’) or no action required at all (‘indirect methods’).

For this purpose, the corresponding costs saved (e.g. based on annual time

saved multiplied with the average staff costs assumed for the specific country)

would be deducted from the regulated entity’s own costs to obtain the total

costs to be compared with the benefit calculated below.

Benefit: As the benefit of e.g. more precise metering is difficult to express in

financial values, an assumption is to be made following the MRR. The benefit is

considered to be proportionate to an amount of allowances in the order of

magnitude of the reduced uncertainty. In order to make this estimation

independent from daily price fluctuations, the MRR (Article 75d (1)) requires a

constant allowance price of 60 € to be applied. For determining the assumed

benefit, this allowance price is to be multiplied by an “improvement factor”, which

is the improvement in uncertainty multiplied by the average annual emissions

caused by the respective fuel stream over the three most recent years74. The

improvement in uncertainty is the difference between the uncertainty currently

achieved75 and the uncertainty threshold of the tier which would be achieved after

the improvement.

Where no direct improvement to the accuracy of emissions data is achieved by

an improvement, the improvement factor is always 1%. Article 75d(3) lists some

of such improvements, e.g. applying a higher tier for the scope factor, switching

from default values to analyses, increasing the number of samples analysed,

improving the data flow and control system, etc.

Please note the minimum threshold given by the MRR: Accumulated

improvement costs below 4 000 € per year are always considered reasonable,

75 Please note that the “real” uncertainty is meant here and not the uncertainty threshold of the tier.

62

without assessing the benefit. For regulated entities with low emissions (

section 6.3.2) this threshold is only 1 000 €.

Summarising the above by means of a formula, the costs are considered

reasonable, if:

< ∙ ∙

(9)

Where:

C ......... Costs [€/year]

P ......... specified allowance price = 60 € / t CO2(e)

AEm .... Average emissions from related fuel stream(s) over the three most recent

years [t CO2(e)/year]

IF ......... Improvement factor (Ucurr – Unew tier, where applicable, or 1%)

Ucurr ..... Current uncertainty (actual uncertainty, not the tier threshold) [%]

Unew tier . Uncertainty threshold of the new tier that can be reached [%]

Example: For the replacement of meters described above, the benefit of

“improvement” for instrument A is zero, as it is a mere replacement maintaining

the current tier. It cannot be unreasonable, as the regulated entity cannot be

operated without at least this instrument.

In case of instrument B, tier 3 (threshold uncertainty = 2.5 %) can be reached.

Thus, the uncertainty improvement is Ucurr – Unew tier = 2.8% – 2.5% = 0.3%.

The average annual emissions are AEm = 120 000 t CO2/year. Therefore, the

assumed benefit is 0.3% · 120 000 · 60 € = 21 600 €. This is higher than the

assumed costs (see above). It is therefore not unreasonable to require

instrument B to be installed.

Example: for the same situation as for the example above, when assessing

the benefit of achieving a higher tier for any of the calculation factors or the

scope factor would equal 1% · 120 000 · 60 € = 72 000 €

Important note: For the reporting of historic emissions in 2024 (i.e. the report

due by 30 April 2025) Member States may exempt regulated entities from

justifying that a specific monitoring methodology would incur unreasonable costs

(Article 75d (1)).

 tiernewcurr UUAEmPC 

63

Further guidance76 can be found in the training event material on “unreasonable

costs” published on DG CLIMA’s MRVA website

(https://ec.europa.eu/clima/eu-action/eu-emissions-trading-system-eu-

ets/monitoring-reporting-and-verification-eu-ets-emissions_en). An Excel-

based “unreasonable costs determination tool” can also be downloaded there.

6.4.2 Simplified uncertainty assessment for the scope factor

For released fuel amounts and calculation factors, derogation from required tiers

( see Table 7) is only possible if technical infeasibility or unreasonable costs

( section 6.4.1) can be demonstrated. For the scope factor ( section 5.4), in

addition to that, derogation from applying the required tier is also possible if the

regulated entity can demonstrate that a lower tier method leads to a more

accurate identification of end consumers’ CRF categories, based on a simplified

uncertainty assessment.

Such an uncertainty assessment will take into account the elements discussed in

section 6.5 below. However it is simplified in the sense that non quantifiable

elements might be considered as well where quantifiable estimates are not

available. For example, when conducting a study to establish a correlation

between end consumers’ seasonal consumption profile and their respective

coverage of CRF categories listed in Annex III of the Directive (‘indirect methods’

scope factor method), the result may contain quantified estimates of the share of

end consumers erroneously identified as covered by the ETS2 scope and, vice

versa, erroneously identified as not covered by the ETS2 scope. In many other

instances, such quantified estimates might not be available, e.g. the share of non-

Annex III users as part of the ‘physical distinction’ scope factor method. For such

cases, the MRR introduces the concept of a ‘simplified’ uncertainty assessment.

This term may be understood as regulated entities taking account of the main

concepts, yet using any source of reasonable information (e.g. literature sources)

to demonstrate a certain lower tier method can lead to a more accurate

identification of end consumers.

6.5 Uncertainty assessment

6.5.1 General principles

When somebody would like to ask the basic question about the quality of the

MRV system of any emission trading system, they would probably ask: “How

good is the data?” or rather “Can we trust the measurements which produce the

emission data?” When determining the quality of measurements, international

standards refer to the quantity of “uncertainty”. This concept needs some

explanation.

There are different terms frequently used in a similar way as uncertainty.

However, these are not synonyms, but have their own defined meaning (see

illustration in Figure 7):

76 Written for ETS1 installations, but concepts are equally applicable to regulated entities.

64

 Accuracy: This means the closeness of agreement between a measured

value and the true value of a quantity. If a measurement is accurate, the

average of the measurement results is close to the “true” value (which may be

e.g. the nominal value of a certified standard material77). If a measurement is

not accurate, this can sometimes be due to a systematic error. Often this is

can be overcome by calibration and adjustment of instruments.

 Precision: This describes the closeness of results of repeated measurement

of the same measured quantity under the same conditions, i.e. the same thing

is measured several times. It is often quantified as the standard deviation of

the values around the average. It reflects the fact that all measurements

include a degree of random error, which can be reduced, but not completely

eliminated.

 Uncertainty78: This term characterises the range within which the true value

is expected to lie with a specified level of confidence. It is the overarching

concept which combines precision and assumed accuracy. As shown in Figure

7, measurements can be accurate, but imprecise, or vice versa. The ideal

situation is precise and accurate.

If a laboratory assesses and optimises its methods, it usually has an interest in

distinguishing accuracy and precision, as this leads the way to identification of

errors and mistakes. It can show diverse reasons for errors such as the need for

maintenance or calibration of instruments, or for better training of staff. However,

the final user of the measurement result (in the case of the ETS, this is the

regulated entity and the competent authority) simply wants to know how big the

interval is (measured average ± uncertainty), within which the true value is

probably found.

In the EU ETS, only one value is given for the emissions in the annual emissions

report. Only one value is entered in the verified emissions table of the registry.

The regulated entity can’t surrender “N ± x%” allowances, but only the precise

value N. It is therefore clear that it is in everybody’s interest to quantify and reduce

the uncertainty “x” as far as possible. This is the reason why MPs must be

approved by the competent authority, and why regulated entities have to

demonstrate compliance with specific tiers, which are related to permissible

uncertainties.

77 Also a standard material, such as e.g. a copy of the kilogram prototype, disposes of an uncertainty

due to the production process. Usually this uncertainty will be small compared to the uncertainties later down in its use.

78 The MRR defines in Article 3(6): ‘uncertainty’ means a parameter, associated with the result of the determination of a quantity, that characterises the dispersion of the values that could reasonably be attributed to the particular quantity, including the effects of systematic as well as of random factors, expressed in per cent, and describes a confidence interval around the mean value comprising 95% of inferred values taking into account any asymmetry of the distribution of values.

65

Figure 7: Illustration of the concepts accuracy, precision and uncertainty. The bull’s

eye represents the assumed true value, the “shots” represent

measurement results.

Further guidance79 can be found on DG CLIMA’s MRVA website

(https://ec.europa.eu/clima/eu-action/eu-emissions-trading-system-eu-

ets/monitoring-reporting-and-verification-eu-ets-emissions_en ):

 Guidance Document No. 4 (“Guidance on Uncertainty Assessment”) and No.

4a (“Exemplar Uncertainty Assessment”);

 Materials from training events on “uncertainty assessment”;

 Excel-based “Tool for the assessment of uncertainties”.

6.5.2 General requirements

As shown in section 5.3.1, the tiers for released fuel amounts are expressed using

a specified “maximum permissible uncertainty over a reporting period”. When

submitting a new or updated MP, the regulated entity must demonstrate the

compliance of its monitoring methodology (in particular of the measuring

instruments applied) with those uncertainty levels.

6.5.2.1 Simplifications for entities under the ETD/ED regime

Article 75j(2) of the MRR does not require an assessment of the uncertainty

where all of the following conditions are satisfied:

 the regulated entity corresponds to the same entity with reporting obligations

under the ETD/ED regime;

 the regulated entity uses the same measurement methods as under the

ETD/ED regime, including the ones used by fuel trading partners;

79 Written for ETS1 installations, but concepts are equally applicable to regulated entities.

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 the measurement methods referred to under the bullet point above are subject

to national legal metrological control (in most cases satisfied for all commercial

transactions).

Where this is the case, likely in the majority of cases for natural gas, liquid fuels

and parts of the coal market, no further assessment is needed and the regulated

entity may assume compliance with the highest tiers (as already discussed in

section 0). Therefore, the following sub-sections related to the uncertainty

assessment are not relevant.

6.5.2.2 Entities or methods not under the ETD/ED regime

For any remaining cases for determining the released fuel amounts, the

assessment shall cover (Article 75j(2) via reference to Article 2880and Article 29):

 the specified uncertainty of the applied measuring instruments,

 the uncertainty associated with the calibration, and

 any additional uncertainty connected to how the measuring instruments are

used in practice.

 Furthermore, the influence of the uncertainty related to determination of stocks

at the start/end of the year are to be included, if relevant.

However, for those cases the MRR also contains provisions to greatly simplify

the uncertainty assessment ( sections 6.5.2.3 and 6.5.2.4)

For a regulated entity with low emissions ( section 7) this assessment is even

further simplified. Such an entity may determine the amount of fuel released by

using available and documented purchasing records and estimated stock

changes, without any further assessment of tier compliance. Such regulated

entities are usually found in the coal market and in the small-scale parts of liquid

fuels market.

6.5.2.3 Simplification based on calibration results

The MRR (Art. 28 (2)) allows the regulated entity to use the “Maximum

Permissible Error (MPE) in service”81 specified for the instrument as overall

uncertainty, provided that the measuring instruments are installed in an

environment appropriate for their use specifications. Where no information is

available for the MPE in service, or where the regulated entity can achieve better

values than the default values, the uncertainty obtained by calibration may be

used, multiplied by a conservative adjustment factor for taking into account the

higher uncertainty when the instrument is “in service”.

The information source for the MPE in service and the appropriate use

specifications is not specified by the MRR, leaving some room for flexibility. It

may be assumed that the manufacturer’s specifications, specifications from legal

80 with the exception of Article 28(2), second subparagraph, second sentence and third subparagraph 81 The MPE in service is significantly higher than the MPE of the new instrument. The MPE in service

is often expressed as a factor times the MPE of the new instrument.

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metrological control, and also guidance documents such as the Commission’s

guidance are suitable sources.

6.5.2.4 Relying on national legal metrological control

The second simplification allowed by the MRR is even more simplifying in

practice: Where the regulated entity demonstrates to the satisfaction of the CA,

that a measuring instrument is subject to national legal metrological control, the

MPE (in service) allowed by the metrological control legislation may be taken as

uncertainty, without providing further evidence82.

6.6 Procedures and the monitoring plan

The MP should ensure that the regulated entity carries out all the monitoring

activities consistently over the years, like a recipe book. In order to prevent

incompleteness, or arbitrary changes by the regulated entity, the competent

authority’s approval is required. However, there are always elements in

monitoring activities, which are less crucial, or which may change frequently.

The MRR provides a useful tool for such situations: Such monitoring activities

may (or even shall) be put into “written procedures”83, which are mentioned and

described briefly in the MP, but are not considered part of the MP. These

procedures are tightly linked to, but not part of the MP. They must just be

described in the MP with a sufficient level of detail that the CA can understand

the content of the procedure, and can reasonably assume that the full

documentation of the procedure is maintained and implemented by the regulated

entity. The full text of the procedure would be provided to the competent authority

only upon request. The regulated entity shall also make procedures available for

the purposes of verification (Article 12(2))84. As a result, the regulated entity has

full responsibility for the procedure. This gives it the flexibility to make

amendments to the procedure whenever needed, without requiring an update of

the MP, as long as the procedure’s content stays within the limitations of its

description laid down in the MP.

Note, these procedures do not have to be special procedures for ETS2

compliance; they can be additional sections or clauses in existing procedures

used for other purposes. For example, for quality management of measurement

instruments, a regulated entity may already have control procedures, so for ETS2

purposes these can be updated with any additional elements needed for ETS2

compliance.

The MRR contains several elements which are by default expected to be put into

written procedures, such as:

 Managing responsibilities and competency of all relevant personnel;

82 The philosophy behind this approach is that control is exerted here not by the CA responsible for

the EU ETS, but by another authority which is in charge of the metrological control issues. Thus, double regulation is avoided and administration is reduced.

83 Article 11(1) 2nd sub-paragraph: “The monitoring plan shall be supplemented by written procedures which the [regulated entity] establishes, documents, implements and maintains for activities under the monitoring plan, as appropriate.”

84 Article 75b declares Article 12(2) equally applicable to ETS2.

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 Data flow and control procedures ( section 6.7);

 Quality assurance measures;

 Estimation method(s) for substitution data where data gaps have been found;

 Regular review of the MP for its appropriateness (including uncertainty

assessment where relevant);

 A sampling plan85, if applicable ( see section 5.5.2), and a procedure for

revising the sampling plan, if relevant;

 Procedures for methods of analyses, if applicable;

 Procedure for demonstrating evidence for equivalence to EN ISO/IEC 17025

accreditation of laboratories, if relevant.

The MRR furthermore outlines how the procedure must be described in the MP.

Note that for simple regulated entities the procedures will usually be simple and

straightforward. Where the procedure is simple, it may be useful to use the

procedure text directly as the “description” of the procedure as required for the

MP.

Table 8 and Table 9 outline the necessary elements of information required to

be put into the MP for each procedure (Article 12(2)), and give examples for

procedures.

Table 8: Example related to the management of staff: Descriptions of a written

procedure as required in the MP.

Item according to Article 12(2) Possible content (examples)

Title of the procedure ETS personnel management

Traceable and verifiable reference for identification of the procedure

ETS 01-P

Post or department responsible for implementing the procedure and the post or department responsible for the management of the related data (if different)

HSEQ deputy head of unit

Brief description of the procedure86  Responsible person maintains a list of personnel involved in ETS data management

 Responsible person holds at least one meeting per year with each involved person, at least 4 meetings with key staff as defined in the annex of the procedure; Aim: Identification of training needs

85 Containing information on the methodologies for preparation of samples, including information on

responsibilities, locations, frequencies and quantities and methodologies for the storage and transport of samples (Article 33).

86 This description is required to be sufficiently clear to allow the regulated entity, the competent authority and the verifier to understand the essential parameters and operations performed.

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Item according to Article 12(2) Possible content (examples)

 Responsible person manages internal and external training according to identified needs.

Location of relevant records and information

Hardcopy: HSEQ Office, shelf 27/9, Folder identified “ETS 01-P”.

Electronically: “P:\ETS_MRV\manag\ETS_01-P.xls”

Name of the computerised system used, where applicable

N.A. (Normal network drives)

List of EN standards or other standards applied, where relevant

N.A.

Table 9: QM-related example for a description of a written procedure in the MP. The

regulated entity of the example seems to be a rather complex one.

Item according to Article 12(2) Possible content (examples)

Title of the procedure QM for ETS instruments

Traceable and verifiable reference for identification of the procedure

QM 27-ETS

Post or department responsible for implementing the procedure and the post or department responsible for the management of the related data (if different)

Instrumentation Engineer / Business Unit 2

Brief description of the procedure  Responsible person maintains a schedule of appropriate calibration and maintenance intervals for all instruments listed in table X.9 of the MP

 Responsible person checks weekly which QM activities are required within the next 4 weeks according to the schedule. As appropriate, they reserve resources required for these tasks in the weekly meetings with the plant manager.

 Responsible person orders in external experts (calibration institutes) when required.

 Responsible person ensures that QM tasks are carried out on the agreed dates.

 Responsible person keeps records of the above QM activities.

 Responsible person reports back to plant manager on corrective action required.

 Corrective action is handled under procedure QM 28-ETS.

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Item according to Article 12(2) Possible content (examples)

Location of relevant records and information

Hardcopy: Office HS3/27, shelf 3, Folder identified “QM 27-ETS -nnnn”. (nnnn=year)

Electronically: “Z:\ETS_MRV\QM\calibr_log.pst”

Name of the computerised system used, where applicable

XYZ Asset Management Tool, also used for storing documents as attachments chronologically

List of EN standards or other standards applied, where relevant

In the instrument list (document ETS- Instr-A1.xls) the applicable standards are listed. This document is made available to the CA and verifier upon request.

6.7 Data flow and control system

Monitoring of emissions data is more than just reading instruments or carrying

out chemical analyses. It is of utmost importance to ensure that data are

produced, collected, processed and stored in a controlled way. Therefore the

regulated entity must define instructions for “who takes data from where and does

what with that data”. These “data flow activities” (Article 58) form part of the MP

(or are laid down in written procedures, where appropriate (see section 6.6). A

data flow diagram is often a useful tool for analysing and/or setting up data flow

procedures. Examples of data flow activities include reading from instruments,

taking and sending samples to the laboratory and receiving the results, converting

and aggregating data, calculating the emissions using various parameters, and

storing all relevant information for later use.

As human beings (and often different information technology systems) are

involved, mistakes in these activities can be expected. The MRR therefore

requires the regulated entity to establish an effective control system (Article 59).

This consists of two elements:

 A risk assessment, and

 Control activities for mitigating the risks identified.

“Risk” is a parameter which takes into account both, the probability of an incident

and its impact. In terms of emission monitoring, the risk refers to the probability

of a misstatement (omission, misrepresentation or error) being made, and its

impact in terms of the final annual emissions figure.

When the regulated entity carries out a risk assessment, it analyses for each point

in the regulated entity’s emission monitoring data flow, whether there would be a

risk of misstatements. Usually this risk is expressed by qualitative parameters

(low, medium, high) rather than by trying to assign exact figures. It also assesses

potential reasons for misstatements (such as paper copies being transported

from one department to another, where delays may occur, or copy & paste errors

may be introduced), and identifies which measures might reduce the identified

risks, e.g. sending data electronically and storing a paper copy in the first

department; search for duplicates or data gaps in spreadsheets, validation or

control check by an independent person (“four eyes principle”)…

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Measures identified to reduce risks are implemented. The risk assessment is then

re-evaluated with the new (reduced) risks, until the regulated entity considers that

the remaining risks are sufficiently low so as to be able to produce an annual

emissions report which is free from material misstatement(s)87.

The control activities are laid down in written procedures and referenced in the

MP. The results of the risk assessment (taking into account the control activities)

are submitted as supporting documentation to the competent authority when

approval of the monitoring plan is requested by the regulated entity (Article

75b(2)).

Regulated entities are required to establish and maintain written procedures

related to control activities for at least (Article 59(3)):

(a) quality assurance of the measurement equipment;

(b) quality assurance of the information technology system used for data flow

activities, including process control computer technology;

(c) segregation of duties in the data flow activities and control activities and

management of necessary competencies;

(d) internal reviews and validation of data;

(e) corrections and corrective action;

(f) control of out-sourced processes;

(g) keeping records and documentation including the management of document

versions.

Regulated entities with low emissions: Article 75n(2) exempts entities with low

emissions ( section 6.3.2 and chapter 7) from submitting a risk assessment

when sending the monitoring plan for approval by the competent authority.

However, it will still be useful to carry out a risk assessment for their own

purposes. It has the advantage of reducing the risk of under-reporting, under-

surrender of allowances and consequential penalties, and also over-reporting

and over-surrender. It will also facilitate demonstrating to the verifier that the

regulated entity has proper internal control over its emissions monitoring system.

Note that dedicated documents88 containing more detailed information on the

data flow activities and control system (including risk assessment) have been

published (GD No. 6 and 6a, tool for operators’ risk assessment; for reference

see section 1.3).

6.8 Keeping the monitoring plan up to date

The MP must always correspond to the current nature and functioning of the

regulated entity. Where the practical situation at the regulated entity is modified,

87 The regulated entity should strive to produce “error-free” emission reports (Article 7: Regulated

entities “shall exercise due diligence to ensure that the calculation and measurement of emissions exhibit the highest achievable accuracy”). However, verification cannot produce 100% assurance. Instead, verification aims at providing a reasonable level of assurance that the report is free from material misstatements. For further information see the relevant guidance document on the A&V Regulation (see section 1.3).

88 Written for ETS1 installations, but concepts are equally applicable to regulated entities.

72

e.g. because technologies, processes, fuels, means through which the fuels are

released for consumption, methods for the scope factor, measuring equipment,

IT systems or organisation structures (i.e. staff assignments) etc are changed

(where these are relevant to the monitoring of emissions), the monitoring

methodology must be updated (Article 14)89. Depending on the nature of the

changes, one of the following situations can occur:

 If an element of the MP itself needs updating, one of the following situations

can apply:

 The change to the MP is a significant one. This situation is discussed in

section 6.8.1. In case of doubt, the regulated entity has to assume that the

change is significant.

 The change to the MP is not significant. The procedure described in section

6.8.2 applies.

 An element of a written procedure is to be updated. If this does not affect the

description of the procedure in the MP, the regulated entity can carry out the

update under its own responsibility without notification to the competent

authority.

The same situations may occur as a consequence of the requirement to

continuously improve the monitoring methodology (see section 6.9).

The MRR in Article 16(3) also defines requirements for record keeping about any

MP updates, such that a complete history of MP updates is maintained, which

allows a fully transparent audit trail, including for the purposes of the verifier.

For this purpose it is considered best practice for the regulated entity to make use

of a “logbook”, in which all non-significant changes to the MP and to procedures

are recorded, as well as all versions of submitted and approved MPs. This must

be supplemented with a written procedure for regular assessment of whether the

MP is up to date (Article 14(1) and point 1(c) of section 1 of Annex I).

Note: A simplification90 introduced in Article 75e(2) and (3) helps to avoid a

potentially large number of MP updates. In principle, every time a regulated

89 Article 75b(3) lists a minimum of situations in which a monitoring plan update is mandatory:

(a) changes to the category of the regulated entity where such changes require a change in the monitoring methodology or lead to a change of the applicable materiality level pursuant to Article 23 of Implementing Regulation (EU) 2018/2067;

(b) notwithstanding Article 75n, changes regarding whether the regulated entity is considered a “regulated entity with low emissions”;

(c) a change in the tier applied;

(d) the introduction of new fuel streams;

(e) a change in the categorisation of fuel streams – between major or de-minimis fuel streams where such a change requires a change to the monitoring methodology;

(f) a change to the default value for a calculation factor, where the value is to be laid down in the monitoring plan;

(g) a change in the default value for the scope factor;

(h) the introduction of new methods or changes to existing methods related to sampling, analysis or calibration, where this has a direct impact on the accuracy of emissions data.

90 The simplification for entity classification is found in the 3rd subparagraph of Article 75e(2): „ By way of derogation from Article 14(2), the competent authority may allow the regulated entity not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of the regulated entity referred to in the first subparagraph is exceeded, but the regulated entity demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the previous five reporting periods and will not be exceeded again in subsequent reporting periods.” Similar wording is found in Article 75e(3) for fuel streams.

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entity’s emissions exceed the threshold for its categorisation (Category A, or

regulated entity with low emissions), the regulated entity would have to evaluate

if all tiers applied still conform with the requirement (see section 6.2). The same

would apply to individual fuel streams, if their emissions exceed the relevant

threshold for their classification. The simplification clauses in Article 75e allow the

regulated entity to avoid such reclassification of the regulated entity, or fuel

stream, if it provides evidence to the competent authority that the relevant

threshold was not exceeded during the 5 years before the exceedance, and is

unlikely to be exceeded again.

6.8.1 Significant modifications

Whenever a significant modification to the MP is necessary, the regulated entity

shall notify the update to the competent authority without undue delay. The

competent authority then has to assess whether the change is indeed a

significant one. Article 75b(3) contains a (non-exhaustive) list of MP updates

which are considered significant91. If the change is not significant, the procedure

described under 6.8.2 applies. For significant changes, the competent authority

thereafter carries out its normal process of approving MPs92.

The approval process may sometimes need longer than when the physical

change of the regulated entity is due to happen (e.g. where new fuel streams are

introduced for monitoring). Furthermore, the competent authority may find the

regulated entity’s MP update incomplete or inappropriate and may require

additional amendments to the MP. Thus, monitoring according to the old MP may

be incomplete or lead to inaccurate results, while the regulated entity is not sure

whether the new MP will be approved as requested. The MRR provides for a

pragmatic approach here:

According to Article 16(1), the regulated entity shall immediately apply the new

MP where it can reasonably assume that the updated MP will be approved as

proposed. This may apply e.g. when an additional means through which the fuel

released for consumption is introduced, which will be monitored using the same

91 Article 75b(3):

3. In accordance with Article 15, significant modifications to the monitoring plan of a regulated entity include:

(a) changes to the category of the regulated entity where such changes require a change in the monitoring methodology or lead to a change of the applicable materiality level pursuant to Article 23 of Implementing Regulation (EU) 2018/2067;

(b) notwithstanding Article 75n, changes regarding whether the regulated entity is considered a “regulated entity with low emissions”;

(c) a change in the tier applied;

(d) the introduction of new fuel streams;

(e) a change in the categorisation of fuel streams – between major or de-minimis fuel streams where such a change requires a change to the monitoring methodology;

(f) a change to the default value for a calculation factor, where the value is to be laid down in the monitoring plan;

(g) a change in the default value for the scope factor;

(h) the introduction of new methods or changes to existing methods related to sampling, analysis or calibration, where this has a direct impact on the accuracy of emissions data.

92 This process may differ between Member States. The usual procedure will include a completeness check for the information provided, a check for the appropriateness of the new monitoring plan in regard of the changed situation of the installation, and a check for compliance with the MRR. The competent authority may also reject the new monitoring plan or require further improvements. The competent authority may also come to the conclusion that the proposed changes are not significant ones.

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tiers as comparable fuels in that regulated entity. Where the new MP is not yet

applicable, because the situation in the regulated entity will change only after the

approval of the MP by the competent authority, monitoring is to be carried out in

accordance with the old MP until the new one is approved.

Where the regulated entity is unsure whether the CA will approve the changes, it

shall carry out monitoring in parallel using both the new and the old MP (Article

16(1)). Upon receiving the approval of the competent authority, the regulated

entity shall use only the data obtained in accordance with the new MP as

approved (Article 16(2)).

6.8.2 Non-significant modifications of the monitoring plan

While significant updates to the MP are to be notified without undue delay, the

competent authority may allow the regulated entity to delay notification of non-

significant updates in order to simplify the administrative process (Article 75b(1)).

Where this is the case and the regulated entity can reasonably assume that

changes to the MP are non-significant, they may be collected and submitted to

the CA once a year (by 31 December), if the competent authority allows this

approach.

The final decision on whether a change to the MP is significant is the

responsibility of the competent authority. However, a regulated entity can

reasonably anticipate that decision in many cases:

 Where a change is comparable to one of the cases listed in Article 75b(3), the

change is significant;

 Where the impact of the proposed MP change on the overall monitoring

methodology or on the risk of error is small, it may be non-significant;

 In case of doubt assume it is a significant change and follow section 6.8.1.

Non-significant changes do not need the approval of the competent authority.

However, in order to provide for legal certainty, the competent authority must

inform the regulated entity without undue delay of its decision to consider

changes non-significant where the regulated entity has notified them as

significant.

6.9 The improvement principle

While the previous section has dealt with MP updates which are mandated as

consequence of factual changes at the regulated entity, the MRR also requires

the regulated entity to explore possibilities to improve the monitoring

methodology when the regulated entity itself is unchanged. For implementing this

“improvement principle”, there are two requirements:

 Regulated entities must take account of the recommendations included in the

verification reports (Articles 9 and 75q(4)), and

 Regulated entities must check regularly on their own initiative, whether the

monitoring methodology can be improved (Article 14(1) and Article 75q(1)-(3)).

Regulated entities must react to those findings on possible improvements by

 Sending an improvement report to the competent authority for approval,

75

 Updating the MP as appropriate (using the procedures outlined in sections

6.8.1 and 6.8.2), and

 Implementing the improvements, if relevant according to the time table

proposed in the approved improvement report.

“Improvement report” has two different legal bases and deadlines. However, both

reports may be combined if possible:

For the improvement report pursuant to Article 75q(1) on the regulated

entity’s own initiative (which may be combined with the one on verifier’s findings

– see next paragraph) the deadline is the 31 July. It has to be delivered:

 every 3 years for category B installations;

 every 5 years for category A installations;

 for any regulated entity that is using the default scope factor as referred to in

Article 75l(3) and (4), by 31 July 2026.

The deadline of 31 July may be extended by the competent authority up to

30 September of the same year.

Where the regulated entity can demonstrate that the reasons for unreasonable

costs or for improvement measures being technically not feasible will remain valid

for a longer period of time, the competent authority may extend the periods above

to a maximum of 4 or 5 years for category B or A installations, respectively.

For the improvement report responding to a verifier’s recommendations

(Article 75q(4)), the deadline is 31 July (or as late as 30 September, if the CA

sets such later deadline) of the year in which the verification report is issued,

irrespective whether an improvement report under Article 75q(1) is also due in

the same year. However, if the regulated entity has already submitted an updated

MP for approval, which addresses all the issues reported by the verifier, the

improvement report pursuant to Article 75q(4) may be omitted (see Article

75q(5)).

The improvement reports pursuant to Article 75q(1) have to contain in particular

the following information:

 Improvements for achieving higher tiers, if the “required” tiers are not yet

applied. “Required” here means “those tiers which are applicable if no

unreasonable costs occur and if the tier is technically feasible”.

 The report should contain, for each possible improvement, either a description

of the improvement and the related timetable, or evidence regarding technical

non-feasibility or unreasonable costs, if applicable ( section 6.4).

Note: The Commission will provide harmonised templates for improvement

reports.

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7 REGULATED ENTITIES WITH LOW EMISSIONS

For the definition of regulated entities with low emissions, see section 6.3.2. For

those entities, several simplifications are found in Article 75n of the MRR. These

are:

 They may apply as a minimum tier 1 for released fuel amounts and calculation

factors for all fuel streams, unless higher accuracy is achievable without

additional effort for the regulated entity (i.e. no justifications regarding

unreasonable costs are required).

 They are not required to submit a risk assessment as part of the control system

when submitting a monitoring plan for approval (but are stull required to

complete one).

 They may determine the released fuel amounts by using available and

documented purchasing records and estimated stock changes, without

providing an uncertainty assessment.

 Where they use analyses from a non-accredited laboratory, simplified

evidence regarding the competence of the laboratory93 is needed.

All other requirements for regulated entities are to be respected. However,

because an entity with low emissions may apply lower tiers, the overall monitoring

requirements are usually relatively easy to meet.

93 The regulated entity may use “any laboratory that is technically competent and able to generate

technically valid results using the relevant analytical procedures, and provides evidence for quality assurance measures as referred to in Article 34(3)”. See section 5.5.2 for further details.

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8 IDENTIFYING THE ETS2 REGULATED ENTITIES

This chapter is addressed to Member States to support them with identifying

ETS2 regulated entities. The information in this section may however also be

helpful for regulated entities, despite them not being the main target audience

of the guidance provided here.

The approach for Member States to designate ETS2 regulated entities is set out

in Article 3(ae)94 which defines the ETS2 regulated entities as:

 The authorised keeper of a tax warehouse (relevant for liquid fuels, in

particular transport fuels) pursuant to Article 3(11) of the ED, who is liable to

pay the excise duty pursuant to Article 7 of the ED.

 If the above is not applicable, any other person liable to pay the excise

duty pursuant to Article 7 of the ED, Article 21(5) first and fourth subparagraph

ETD (mostly relevant for natural gas and solid fuels, where the concept of a

tax warehouse either does not exist or is only used in a few Member States),

including any person exempt from paying the excise duty. The latter must be

registered by the CA for the ETS purposes, which may particularly be relevant

for coal, coke and lignite used in households which are exempt from the excise

duty in several Member States, but suppliers of those fuels would still have to

be registered by national authorities.

 If the above are not applicable, which might e.g. be or if several persons are

jointly and severally liable for payment of the same excise duty, Member States

may designate any other person.

Therefore, while the EU ETS Directive gives clear preference to putting the

reporting obligation on the same entities as under the ETD/ED regime, where

applicable, it also provides for Member States to deviate from this principle, where

considered more appropriate to make the ETS2 implementation applicable.

Situations where this could be more appropriate, would include e.g. coal, coke

and lignite depending on the situation in the Member State or putting the reporting

obligation further downstream on suppliers that have more robust information on

the end consumers’ sectors. In order to illustrate the implications such a decision,

94 Article 3(ae): ‘regulated entity’ for the purposes of Chapter IVa means any natural or legal person,

except for any final consumer of the fuels, that engages in the activity referred to in Annex III and that falls within one of the following categories:

(i) where the fuel passes through a tax warehouse as defined in Article 3, point (11), of Council Directive (EU) 2020/262, the authorised warehousekeeper as defined in Article 3, point (1), of that Directive, liable to pay the excise duty which has become chargeable pursuant to Article 7 of that Directive;

(ii) if point (i) of this point is not applicable, any other person liable to pay the excise duty which has become chargeable pursuant to Article 7 of Directive (EU) 2020/262 or Article 21(5), first subparagraph, of Council Directive 2003/96/EC in respect of the fuels covered by Chapter IVa of this Directive;

(iii) if points (i) and (ii) of this point are not applicable, any other person that has to be registered by the relevant competent authorities of the Member State for the purpose of being liable to pay the excise duty, including any person exempt from paying the excise duty, as referred to in Article 21(5), fourth subparagraph, of Directive 2003/96/EC;

(iv) if points (i), (ii) and (iii) are not applicable, or if several persons are jointly and severally liable for payment of the same excise duty, any other person designated by a Member State;

78

Figure 8 provides a generic supply structure to show how this could be

implemented.

Figure 8 (A), the default approach: the market participants 1, 2 and 3 could be

traders of e.g. fuel oil, which all have their own tax warehouse and sell the fuel to

fuel suppliers (4, 5 and 6), but not directly to any end consumers. Among the fuel

suppliers selling to end consumers (4, 5 and 6), only supplier 5 has its own tax

warehouse as well. Participant 2 trades fuel only entirely under duty suspension

arrangements and does not release any fuel for consumption. As a consequence,

participants 1, 3 and 5 have obligations under ETD/ED regimes and are, as a first

step, the default ETS2 regulated entities.

A

B

4

1

2

3

5

6

Fuel supply side Demand side

(fuel consumption) Fuel supplier

(final seller) Fuel importers,

traders, etc.

Covered by the scope of Annex III

Outside the scope of Annex III

Reporting obligation under ETD/ED

Reporting obligation under ETS2

SELF-

DECLARATION

Pass up through

supply chain

Covered by the scope of Annex III

Outside the scope of Annex III

Reporting bligation under ETD/ED

Reporting obligation under ETS2

4

1

2

3

5

6

Fuel supply side Demand side

(fuel consumption) Fuel supplier

(final seller) Fuel importers,

traders, etc.

Covered by the scope of Annex III

Outside the scope of Annex III

Reporting obligation under ETD/ED

Reporting obligation under ETS2

SELF-

DECLARATION

Pass up through

supply chain Pass up through

supply chain

79

Figure 8: Illustrative example of designating ETS2 regulated entities. A: default

approach in Article 3(ae) of the EU ETS Directive; B: alternative approach

Without pre-empting the detailed guidance on the ‘scope factor’ ( section 5.4),

in order to illustrate the implication let’s assume that the information on the end

consumers is based on a ‘chain-of-custody’ method established by the MS. This

would start e.g. with a self-declaration from end consumers with respect to their

sectoral coverage which needs to be passed on up through the fuel supply chain

to the regulated entity. While for participant 5, who is directly connected to the

end users, this passing of information is easy, the situation is more difficult for 1

and 3, as they depend on 4 and 6 passing onto them the information concerning

the amounts of fuels supplied to exempted consumers..

Figure 8 (B), alternative: The default position outlined above could lead to

consideration of an alternative for designating ETS2 regulated entities. In order

to avoid having intermediary parties being involved in this process, Member

States may decide to invoke point iv) of Article 3(ae) and put the reporting

obligation on fuel suppliers 4, 5 and 6 who are connected directly to the end

consumers. This would ensure that all reporting entities are directly connected to

end consumers. However, this approach would likely lead to a much higher

number of reporting entities which also cannot build on the existing ETD/ED

reporting infrastructure. Furthermore, this example highlights the possible further

difficulties in the case of more complex supply structures. For example, if the

obligation were only shifted from 1 to 4, corresponding amounts trading between

those two would need be deducted from 1’s annual emissions report (they would

still need to report amounts supplied to 6). This additional administrative burden

for keeping track of all these additional fuel flows and intermediates could easily

outweigh all efficiency gains from putting the obligation further downstream. Point

iv) of Article 3(ae) may therefore only present an attractive alternative where there

is either a direct supply chain without many branches, or to move the obligation

for all traders of this certain type of fuel downstream (e.g. designate fuel suppliers

to end consumers). But the latter would also increase the administrative burden

for ensuring that no regulated entity is missed.

80

9 ANNEX II

9.1 Acronyms

AER ............ Annual Emissions Report

AVR ............ Accreditation and Verification Regulation (A&V Regulation)

CA .............. Competent Authority

EF ............... Emission factor

EU ETS ....... EU Emission Trading System (including ETS 1 and ETS 2)

ETS1 ........... ETS for stationary installations, aviation and maritime transport

ETS2 ........... ETS for buildings, road transport and additional sectors

MP .............. Monitoring Plan

MPE ............ Maximum Permissible Error (term usually used in national legal

metrological control)

MRR ............ Monitoring and Reporting Regulation (M&R Regulation)

MRV ............ Monitoring, Reporting and VerificationMS Member State(s)

NCV ............ Net calorific value

Permit ......... GHG emissions permit

UCF ............ Unit conversion factor

81

9.2 Legislative texts

EU ETS Directive: 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 Community and amending Council Directive

96/61/EC, amended several times. Download of the consolidated version:

https://eur-lex.europa.eu/legal-

content/EN/TXT/?uri=CELEX%3A02003L0087-20230605

MRR: 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. Download under:

https://eur-lex.europa.eu/eli/reg_impl/2018/2066/oj and latest amendment

under:

https://eur-lex.europa.eu/eli/reg_impl/2023/2122/oj, consolidated version:

http://data.europa.eu/eli/reg_impl/2018/2066/2022-01-01

AVR: Commission Implementing Regulation (EU) 2018/2067 on the verification

of data and on the accreditation of verifiers pursuant to Directive 2003/87/EC of

the European Parliament and of the Council. Download of consolidated version:

https://eur-lex.europa.eu/eli/reg_impl/2018/2067/2021-01-01

RED II: 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 (recast). Download under:

https://eur-lex.europa.eu/eli/dir/2018/2001/2022-06-07

Uus kasvuhoonegaaside lubatud heitkoguse ühikutega kauplemise süsteem (HKS2) hoonetele, maanteetranspordile ja muudele sektoritele

Kliimaministeerium Kliimaosakond

Eesmärk

• Uue süsteemi eesmärk on luua turul ausam konkurentsieelis taastuvkütustele ning seekaudu motiveerida olemasoleva HKS-ga katmata sektorites vähendama CO2-heitkoguseid.

Kohaldamisala • Kõik vedelad, tahked ja gaasilised kütused, mida pakutakse müüa või

mida kasutatakse mootorikütuse või kütteainena järgmistel tegevusaladel: • elektri, soojuse ja jahutuse tootmine või jaotamine äri- ja avalikele

hoonetele, korterelamutele ja eramutele otse või kaugküttevõrkude kaudu,

• soojuse tootmine äri- ja avalikes hoonetes, korterelamutes ja eramutes,

• maanteetransport, v.a. traktorid ja liikurmasinad • energeetika ja tööstus, v.a. HKS1-s juba hõlmatud käitised.

Kohaldamisala • Kauplemissüsteem ei kohaldu: • ohtlikele või olmejäätmetele, mida põletatakse kütusena, • kütustele, mille heitekoefitsient on null (säästlikkuse

kriteeriumitele vastavad biokütused), • kütustele, mida kasutatakse põllumajanduses,

metsanduses, kalanduses, raudteedel, militaarsektoris, laevanduses ja lennunduses.

Kohustuslased • Kohustuse kutsub esile kütuse tarbimisse lubamine, kuid riikidele

on jäetud kohustuslaste täpse määramise juures paindlikkus. • Kohustuslased on (eelistatud järjekorras) • aktsiisilaopidajad, • kes iganes muu, kes peab tasuma aktsiisi või on sellest

ajutiselt vabastatud, • kes iganes muu kütuse tarneahelas, v.a. lõpptarbija.

Kohustuslased Kliimaministeeriumi esialgne ettepanek:

1) vedelkütuse tarnijad, 2) maagaasi võrguettevõtjad, 3) võrguvälise maagaasi müüjad, 4) tahkekütusest soojuse tootjad.

Milles kohustus seisneb? • Kohustuslased peavad tarbimisse lubatud kütuse CO2-

heidet seirama, raporteerima ja lubatud heitkoguse ühikud (LHÜ) tagastama (1 ühik = 1 t CO2).

• Kohustuslased peavad taotlema kauplemissüsteemi luba, koostama ja esitama CO2-heite seirekava ja iga-aastase aruande.

Kogu tarbimisse lubatud kütuse kogus aastas (t)

Fossiilkütuse osakaal (%)

Kütuse heitekoefitsient

(t CO2/TJ)

Kohaldamisalasse kuuluva kütuse

osakaal (%)

Tarbimisse lubatud kütuse kogus

aastas (t)

Kohustuslase CO2 -heide aastas

Kütuse heitekoefitsient

(t CO2 /TJ) ×

× ×

Olemasolevad meetodid HKS2 kohaldamisalasse kuuluva kütuse osakaalu tuvastamiseks:

• aktsiisivabastuslubade järgi, • füüsilise kütusevoo järgi, • kütuse keemilise koostise järgi, • erimärgistusaine järgi, • HKS1 kuuluva käitaja tõendatud aastaheite aruande järgi, • muude kaudsete meetodite (näiteks sektoripõhiste tarbimis-

profiilide või eri tarbijate kütusetarbimise taseme tüüpiliste mahuvahemike) alusel.

Võimalikud lisameetodid HKS2 kohaldamisalasse kuuluva kütuse osakaalu tuvastamiseks:

• ostu-müügilepingute ja arvete alusel kütuse kasutusvaldkonna kohta andmete esitamine tarneahela ulatuses alates lõpptarbijast kuni HKS2 kuuluva ettevõtteni,

• standardväärtuse 1 (=100%) kasutamine juhul, kui loetletud meetodite kasutamine ei ole tehniliselt teostatav või tekitaks põhjendamatuid kulusid.

• Seirekavade esitamine, lubade taotlemine ja väljastamine

2024

• Seire ja aruandluse käivitamine

2025 • Seire ja

aruandluse arendamine

2026–2027

• Ühikutega kauplemise käivitumine

2028

Mõju tarbijale • Lõpptarbija ei pea ise LHÜ-sid ostma, kuid võib olla mõjutatud

kütuse hinna tõusu kaudu. • Mõju tarbijahinnale sõltub taastuvkütustele ülemineku kiirusest

ning LHÜ hinnast süsteemis. • Mõjuanalüüsi järgi võib soojuse hinna kasv (läbi maagaasi

hinna kasvu) aastal 2030 olla kuni 17% ja transpordikütuste hinna kasv kuni 10%.

Leevendusmeetmed • LHÜ-de müük enampakkumisel algab 2027. aastal mahus,

mis vastab 130 %-le 2027. aasta LHÜ-de mahule. • Kauplemissüsteemi käivitamine lükatakse aasta võrra edasi,

kui 2026. aasta esimese kuue kuu keskmine gaasi hind on kõrgem kui 2022. aasta veebruari ja märtsi keskmine.

• Turule tuuakse turustabiilsusreservist LHÜ-sid juurde, kui LHÜ hind süsteemis ületab 45 €.

Tuluallikad riigile ja võimalikud toetusvahendid

• Luuakse kliimameetmete sotsiaalfond mahuga 248 mln € ja eesmärgiga toetada haavatavaid ühiskonnagruppe.

• Suurendatakse moderniseerimisfondi ja innovatsioonifondi mahtu. • Kauplemissüsteemis on võimalik müüa LHÜ-sid ning tulu peab riik

kasutama rohelisteks investeeringuteks. • Riigi tulude muutuse prognoos on positiivne, sest LHÜ-dest tekkiva

tulu kasv on suurem kui maksulaekumiste ja ostujõu langus.

EUROPEAN COMMISSION DIRECTORATE-GENERAL CLIMATE ACTION Directorate B – Carbon Markets & Clean Mobility Unit B.2 – ETS (II): Implementation, Policy Support & ETS Registry

1

1

1

Guidance Document 2

The Monitoring and Reporting Regulation – 3

General guidance for ETS2 regulated 4

entities 5

6

MRR Guidance document for ETS2, 7

1st Draft for discussion, 7 December 2023 8

9

10

This document is part of a series of documents provided by the Commission 11

services for supporting the implementation of the “Monitoring and Reporting 12

Regulation (the “MRR”), i.e. Commission Implementing Regulation (EU) 13

2023/2122 of 17 October 2023 in its current version1. 14

The guidance represents the views of the Commission services at the time of 15

publication. It is not legally binding. 16

This guidance document takes into account the discussions within the meetings 17

of the Commission expert group on climate change policy (CCEG) ETS2 18

implementation formation and the informal Technical Working Group on MRVA 19

(Monitoring, Reporting, Verification and Accreditation) under the Working Group 20

III (WGIII) of the Climate Change Committee (CCC), as well as written comments 21

received from stakeholders and experts from Member States2. 22

All guidance documents and templates can be downloaded from the 23

documentation section of the Commission’s website at the following address:24

25

https://ec.europa.eu/clima/eu-action/eu-emissions-trading-system-eu-26

ets/monitoring-reporting-and-verification-eu-ets-emissions_en . 27

28

29

1 Updated by Commission Implementing Regulation (EU) 2023/2122 of 17 October 2023 amending

Implementing Regulation (EU) 2018/2066 as regards updating the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council; the consolidated MRR can be found here: http://data.europa.eu/eli/reg_impl/2018/2066/2022-01-01

2 “Member States” in this document means all countries that apply the EU ETS, i.e. the 27 EU Member States plus the EFTA countries Norway, Iceland and Liechtenstein.

2

TABLE OF CONTENTS 1

1 INTRODUCTION ........................................................................ 5 2

1.1 About this document ............................................................................ 5 3

1.2 How to use this document ................................................................... 5 4