EU Emissions Trading Scheme
Guidance to Operators on the requirements for
installations to achieve the highest applicable
monitoring tiers (as defined within Commission
Decision 2004/156/EC - Monitoring and Reporting
Guidelines)
Guidance to Operators of Offshore Installations
(Incorporating Frequently Asked Questions)
February 2007
Version 2 – Feb 2007
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CONTENTS
1
INTRODUCTION
3
1.1
1.2
3
3
PURPOSE
BACKGROUND
2
Monitoring Tiers
4
3
Demonstration of Cost-benefits
5
Appendix 1 Offshore Sector Combustion Activities
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1
INTRODUCTION
1.1
PURPOSE
The purpose of this guidance is to assist Operators with interpretation of the requirements of the EU
Emissions Trading Scheme (EU ETS) with regard to achieving the highest standard of monitoring for carbon
dioxide emissions, as prescribed in the EU Monitoring and Reporting Guidelines1 (the ‘M&R Guidelines’).
It should be noted that this guidance relates specifically to the M&R Guidelines as published in Commission
Decision 2004/156/EC, and will only apply to Phase I of the EU ETS. A revision of the M&R Guidelines has
been published for Phase II of the EU ETS.
This guidance identifies the requirements for determining each variable during Phase I of the EU ETS.
This guidance also incorporates a revised draft of the “Frequently Asked Questions” prepared by the DTI for
Phase I Monitoring, Reporting and Verification for Offshore Facilities.
1.2
BACKGROUND
Activity specific guidelines are set out in Annexes II to XI of the M&R Guidelines, and include specific
methodologies for determining the variables - activity data, emission factors, oxidation or conversion factors.
For each methodology, there are one or more approaches to determining these variables. These different
approaches are referred to as ‘tiers’. The increasing numbering of the tiers, from Tier 1 upwards, reflects
increasing levels of accuracy, with the highest numbered tier being the preferred tier. Equivalent tiers are
referred to using the same tier number and a specific alphabetic character (e.g. Tiers 2a and 2b). For those
activities where alternative calculation methods are provided, an operator can only change from one method
to the other if it can be demonstrated to the satisfaction of the Competent Authority that such a change will
lead to a more accurate monitoring and reporting of the emissions.
Section 4.2.2.1.4 of the M&R Guidelines requires that the highest tier approach shall be used by all
operators to determine all variables for all sources within an installation for monitoring and reporting
purposes. However, if it can be demonstrated to the satisfaction of the Competent Authority that the highest
tier approach is technically not feasible, or will lead to unreasonably high costs, then operators may use the
next lower tier for that variable.
The selected tier will therefore reflect the highest level of accuracy that is technically feasible and does not
lead to unreasonably high costs. The operator may apply different approved tiers to determine the variables
- activity data, emission factors, oxidation or conversion factors - used within a single calculation. The
appropriate tier for each variable will be subject to approval by the Competent Authority.
1
Commission Decision of 29 January 2004 establishing guidelines for the monitoring and reporting of
greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council
(2004/156/EC)
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2
Monitoring Tiers
A table presenting the highest tier requirements to be achieved for the monitoring of all major fuels and
materials (see Box 1), together with indicative timescales for achievement of the relevant tier, is appended at
Appendix 1.
Box 1
‘Major sources, including major streams of fuels and materials are those which, if ranked in order of their
decreasing magnitude, cumulatively contribute at least 95% to the total annual emissions of the installation.
Minor sources are those emitting 2.5 ktonnes or less per year, or those that contribute 5% or less to the total
annual emissions of an installation, whichever is the highest in terms of absolute emissions. For those minor
sources jointly emitting 0.5 ktonnes or less per year, or those that contribute less than 1% of total annual
emissions of an installation, whichever is the highest in terms of absolute emissions, the operator of an
installation may apply a de minimis approach for monitoring and reporting, using his own no-tier estimation
method, subject to the approval of the competent authority.’
(Source: Section 4.2.2.1.4 of the M&R Guidelines)
For minor or de minimis sources, an operator should still aim to apply the highest tier practicable, i.e. if an
operator uses a metering device to meet the highest tiers identified for a major source, then the Competent
Authority would normally also expect this to be applied for minor and de minimis sources.
The guidance provided within the table is without prejudice to an operator’s justification that to apply the
highest tiers identified would not be technically feasible or would lead to unreasonably high costs. Some
guidance on how an operator might assess whether the cost of a potential improvement is either reasonable
or unreasonable, by evaluating the costs and benefits of an improvement, is provided in Section 3.
An operator may also determine carbon dioxide emissions using continuous emission measurement systems
(CEMS) for each source, using standardised or accepted methods approved by the Competent Authority,
providing that using CEMS achieves greater accuracy than the calculation of emissions using the highest
tiers identified. Details of the requirements for CEMS can be found in Annex I, Sections 4.2.3, 4.3.2, and 7.2
of the M&R Guidelines). Operators should note that, in accordance with Annex I, Section 4.2.3.1 of the M&R
Guidelines, emissions determined using CEMS must be corroborated by a supporting calculation of
emissions applying the highest tiers identified.
Monitoring of emissions using CEMS is not discussed further within this guidance.
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3
Demonstration of Cost-benefits
In order to demonstrate how reasonable or unreasonable the costs of implementing a measure(s) to meet
the highest tiers identified would be, an operator should evaluate the costs of implementing measures to
improve metering, sampling and/or analytical accuracy against the benefits obtained. Such analysis is often
referred to as a cost-benefit analysis.
Section 4.2.2.1.4 of the M&R Guidelines states that:
‘The highest tier approach shall be used by all operators to determine all variables for all sources within an
installation for monitoring and reporting purposes. Only if it is shown to the satisfaction of the competent
authority that the highest tier approach is technically not feasible or will lead to unreasonably high costs, may
a next lower tier be used for that variable within a monitoring methodology.’
Accordingly, for all major fuel or material streams, the highest tier approach must be used in all
circumstances unless this can be demonstrated to be technically not feasible or will lead to unreasonably
high costs. (For minor and de minimis sources, lower tiers may be applied subject to approval from the
Competent Authority). Demonstration of how reasonable the costs of implementing improvement measures
are should be set out in a cost-benefit analysis similar to the general approach outlined in Figure 1.
Stage 1
Quantify the costs
of meeting the tier
requirement
Stage 2
Quantify the
benefits of meeting
the tier requirement
Stage 3
Compare the costs and
benefits
Figure 1 Key stages of a cost-benefit analysis
A description of each of these stages is provided below.
Stage 1
Quantify the costs of meeting the required monitoring tier
The costs should include the capital expenditure (purchase costs) and installation and maintenance costs. If
the proposed equipment (e.g. a metering device) is a replacement for an existing device (e.g. a less accurate
metering device), then the maintenance costs of the new equipment must be off-set against the cost of
maintaining and calibrating the current equipment.
Where there is more than one technical option, the operator may select the most cost-effective measures for
evaluation, i.e. those options that meet the operator’s requirements at the lowest overall cost.
Stage 2
Quantify the benefits of achieving an increased accuracy
The benefits should be monetised, by assessing the value of carbon dioxide allowances involved in
achieving greater accuracy.
For example, following an evaluation of suppliers and equipment, an operator has selected a new meter to
replace his current fuel gas oil flow meter. The new meter has a manufacturer guaranteed accuracy of
±0.5% fsd, whereas the existing meter has an accuracy of ±4% fsd. Installation of the new meter would
enable the operator to move from activity data Tier 2b to Tier 4b. The cost of the replacement meter is
£1500 including purchase and installation costs. The marginal costs of maintaining and calibrating the new
meter are considered to be £0, as these costs should be similar to those for the current meter.
The current meter and its replacement are for measuring gas oil use in a boiler house that is expected to
give rise to around 5000 tonnes of carbon dioxide per annum.
Accordingly the amount of CO2 associated with the improvement in accuracy is given by:
(4 – 0.5)/100 x 5000 = 175 tonnes
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The value of this carbon dioxide will vary with trading volumes and market demand for allowances.
However, a low price could be expected to be around Є10/tonne, or about £7/tonne, of CO 2. A high price
could be considered to be around Є40/tonne, or about £27/tonne, which is the mandatory penalty that must
be paid by an operator if there are insufficient allowances in a trading account to cover the amount of carbon
dioxide emitted and reported for a given year during Phase I. Accordingly the value of the carbon dioxide
allowances potentially affected in a single year can be considered and calculated as a range given by:
(175 x £7) to (175 x £27)
i.e. £1225 to £4725
Stage 3
Compare the costs and the benefits (taking account of uncertainties)
In this stage the cost of implementing the measure is compared with the monetised benefits. Accordingly,
from the example above:
The cost of moving from Tier 2b to Tier 4b is £1500
The monetised benefits range from a low estimate of £1225 to a high estimate of £4725. This range reflects
the uncertainty in the assessment of the benefits.
Accordingly, in this example, as the implementation cost is only marginally greater than the lowest estimate
of the value of the allowances, and only about a third of the highest estimate, the cost of achieving the higher
tier would be considered to be reasonable, particularly if the benefits are multiplied over the expected lifetime
of the new meter.
It should be noted that this is a very simplistic example, and is provided for guidance only. An operator may
wish to consider other factors in the analysis, such as the remaining life of the existing meter and its residual
asset value, and the anticipate life of the installation. For example, if a meter was shortly due for
replacement, because it was close to the end of its useful life, then only the marginal cost of replacement
should be considered i.e. the difference in the purchase and installation costs for an identical meter and the
more accurate meter. However, if the existing meter was fairly new, then its remaining asset value could
also be added to the replacement costs, unless the meter could be sold or usefully used elsewhere within
the installation.
It is not the purpose of this guidance to identify the specific point within a range of monetised benefits at
which an improvement cost might be considered to be reasonable. It is for the operator to provide his/her
recommendation, together with a justification. The Competent Authority will then assess each case on its
merits, taking account of any wider circumstances relating to the operator’s proposal, for example the
standards that are already applied at similar installations, and the verifier comments and recommendations.
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Appendix 1
Offshore Sector Combustion Activities: Tier Requirements
See also Annex II of M&R Guidelines
Combustion Activities
Variable
Highest tier
Requirement
Expectations
Activity data
Tier 4b or 3b
Liquid fuels
Liquid fuels
Generally, Tier 4b applies to the use of most liquid fuels in
combustion activities.

For the offshore sector:
Where liquid fuel constitutes a major source, Tier 4b should be
achieved unless it would not be technically feasible or would lead 
to unreasonably high costs. Tier 4b requires that fuel purchase
is metered, applying metering devices with a maximum
permissible uncertainty of less than ± 1.0% for the metering
process. Fuel consumption is calculated using a mass balance
approach based on the quantity of fuel purchased and the
difference in the quantity of stock held over a period of time.
Compliance can be achieved by measuring fuel purchase and/or
consumption using appropriate metering devices with an
accuracy of better than ±1%, and by accurate determination of
fuel stocks.
Full implementation of
requirements for offshore
installations in 2006,
unless otherwise agreed
with DTI.
Implementation of any
necessary improvements
by 01/01/2007, or a date
notified to and agreed
with the DTI.
Where liquid fuel constitutes a minor source, Tier 3b should be
achieved. Tier 3b requires that fuel purchase is metered,
applying metering devices with a maximum permissible
uncertainty of less than ± 2.0% for the metering process. Fuel
consumption is calculated using a mass balance approach
based on the quantity of fuel purchased and the difference in the
quantity of stock held over a period of time. Compliance can be
achieved through the use of appropriate metering equipment on
the supplying vessel and the maintenance of accurate supply
and stock records and the determination and recording of all
non-fuel use (e.g. diesel used in wells).
As the metering equipment on the supplying vessel is used for
fiscal and costing purposes, it can be assumed that the
maximum permissible uncertainty is less than ± 1.0% for the
metering process.
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Combustion Activities
Variable
Highest tier
Requirement
Expectations
Activity
Data
Tier 4a or 3a
Gaseous fuels
Gaseous fuels
Generally, Tier 4a or 3a applies to the use of most gaseous fuels
in combustion activities.

For the offshore sector:
For large volume users of gaseous fuels (CO2 emissions of
greater than 500,000 tonnes per annum), Tier 4a should be

achieved unless it would not be technically feasible or would lead
to unreasonably high costs. Tier 4a requires that fuel
consumption is metered without intermediate storage before
combustion in the installation, applying metering devices
resulting in a maximum permissible uncertainty of less than
±1.5% for the metering process. Fiscal gas meters can be
supplied and installed to statutory standards, and calibrated to
an accuracy of around ±1%
Full implementation of
requirements for offshore
installations in 2006,
unless otherwise agreed
with DTI.
Implementation of any
necessary improvements
by 01/01/2007, or a date
notified to and agreed
with the DTI.
For lower volume users of gaseous fuels, Tier 3a should be
achieved. Tier 3a requires that fuel consumption is metered
without intermediate storage before combustion in the
installation, applying metering devices resulting in a maximum
permissible uncertainty of less than ± 2.5% for the metering
process. Compliance can be achieved through the use of
appropriate metering equipment, the implementation of
appropriate service and calibration schedules for metering
equipment and the accurate determination and recording of all
non-fuel use (e.g. flare pilot and purge).
It is recognised that, in most cases, it will be difficult to justify the
costs and disruption that would be imposed by upgrading meters
from Tier 3a to 4a, compared to the marginal increase in
metering accuracy. In this context, it should also be noted that
any sub-meters installed, for example to quantify gas take-off for
flare, would have to be taken into consideration during any
upgrade. Depending on the proportion of gas being metered,
technical feasibility and reasonable cost, the Competent
Authority would normally expect sub-meters to meet the
specified accuracy for the identified tier.
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Combustion Activities
Variable
Emission
Factor and
Net
Calorific
Value
(NCV)
Highest tier
Requirement
Expectations
Tier 3
Liquid fuels
Liquid fuels
Tier 3 applies to the use of liquid fuels in combustion activities.
For the offshore sector:
Tier 3 should be achieved unless it would not be technically
feasible or would lead to unreasonably high costs. Tier 3
requires that the net calorific value representative of each batch
of fuel used on an installation is measured by the operator, a
contracted laboratory or the fuel supplier, in accordance with
relevant CEN standards, ISO standards or National standards.
Where no applicable standards exist, procedures should be
carried out in accordance with any relevant draft standards or
industry best practice guidelines. Tier 3 also requires that there
should be representative sampling of the fuel, and subsequent
analysis by a laboratory certified to ISO17025 for the
determination of calorific values and carbon content.

Operators should use the
UKOOA emission factor,
and the NCV detailed in
the DEFRA emission
factor spreadsheet.
It is recognised that, for the vast majority of offshore installations,
Tier 3 would entail unreasonably high costs. Tier 2 is therefore
considered to be appropriate, and this can be achieved by using
the UKOOA emission factor (3.2tonnes CO2/per tonne diesel).
The NCV should be recorded as detailed in the DEFRA emission
factor spreadsheet (43.32GJ/tonne).
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Combustion Activities
Variable
Emission
Factor and
Net
Calorific
Value
(NCV)
Highest tier
Tier 3
Requirement
Expectations
Gaseous fuels
Gaseous fuels
Tier 3 applies to the use of gaseous fuels in combustion
activities.
For the offshore sector:

Full implementation of
requirements for offshore
installations in 2006,
unless otherwise agreed
with DTI.
For all users of gaseous fuels, Tier 3 should be achieved unless it
would not be technically feasible or would lead to unreasonably high
costs. Tier 3 requires that the net calorific value representative of
each batch of fuel used on an installation is measured by the
operator, a contracted laboratory or the fuel supplier, in accordance
with relevant CEN standards, ISO standards or National standards.
Where no applicable standards exist, procedures should be carried
out in accordance with any relevant draft standards or industry best
practice guidelines. Tier 3 also requires that there should be
representative sampling of the fuel, and subsequent analysis by a
laboratory certified to ISO17025 for the determination of calorific
values and carbon content.
For the offshore sector to achieve Tier 3, it is recommended that the
minimum sampling frequency for installations with a homogeneous
gas supply (i.e. there is documented evidence of stable composition)
should be once per quarter, and that the minimum sampling
frequency for installations with a heterogeneous gas supply (i.e.
there is documented evidence of fluctuating composition, for
example if the installation serves a number of fields and the
composition varies with production from each field) should be once
per month. It is further recommended that a representative number
of samples should be analysed on each sampling occasion, and that
the analyses should be undertaken using an appropriate measuring
device (e.g. gas chromatograph), with calibration and maintenance
underpinned by an organisation accredited to ISO 17025 to provide
such a service. This organisation may be an external third party or
an internal service provider. Additional sampling should be
undertaken if there is a change in fuel type (e.g. a new field is
brought on stream, significantly change the fuel gas composition),
prior to recommencing the appropriate minimum sampling
frequency.
Non-accredited in-house analyses are considered to be acceptable
for the routine analyses, but wherever possible they should be
backed-up by less frequent calibration analyses undertaken by an
ISO17025 accredited laboratory. The minimum frequency of such
analyses should be once per year, although it may be necessary to
undertake more frequent analyses if there is a heterogeneous gas
supply or there are significant discrepancies between the in-house
and calibration analyses. Where there is good agreement between
the in-house and calibration analyses, the results of the in-house
analyses may be used in the calculation of the NCV and emission
factor. Where there is poor agreement, the minimum frequency of
the calibration analyses should be once per quarter, and the results
of the calibration analyses should be used in the calculation of the
NCV and emission factor.
In all cases, the operator will need to develop a robust sampling and
analysis programme, to provide evidence that the samples taken are
representative of the “batch” of fuel burned and that the sample
handling and storage procedures for calibration analyses do not lead
to sample degradation. The operator will also need to provide
details of the comparison between the in-house and calibration
analyses, and the quality checks required under Section 7.3 of the
M&R Guidelines.
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Combustion Activities
Variable
Highest tier
Oxidation
factors
1
Requirement
Expectations
Liquid and gaseous fuels
Liquid and gaseous fuels
Tier 1 is the only applicable tier for liquid and gaseous fuels

Operators should use an
oxidation factor of 0.995.
For the offshore sector:
Offshore operators should use an oxidation factor of 0.995, as
required by the EU ETS M&R Guidelines.
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