COMMISSION STAFF WORKING DOCUMENT IMPACT ASSESSMENT on the calculation methods and reporting requirements pursuant to Article 7a of Directive 98/70/EC of the European Parliament and of the Council relating to the quality of petrol and diesel fuels Accompanying the document COUNCIL DIRECTIVE ../.../EU laying down calculation methods and reporting requirements pursuant to Directive 98/70/EC of the European Parliament and of the Council relating to the quality of petrol and diesel fuels
Date: 2014-10-06
Institutions: European Commission
Subjects: diesel fuel, environmental standard, petrol, qualitative analysis, quality standard













EUR-Lex - 52014SC0296 - EN











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52014SC0296

COMMISSION STAFF WORKING DOCUMENT IMPACT ASSESSMENT on the calculation methods and reporting requirements pursuant to Article 7a of Directive 98/70/EC of the European Parliament and of the Council relating to the quality of petrol and diesel fuels Accompanying the document COUNCIL DIRECTIVE ../.../EU laying down calculation methods and reporting requirements pursuant to Directive 98/70/EC of the European Parliament and of the Council relating to the quality of petrol and diesel fuels /* SWD/2014/0296 final */









COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT

on the calculation methods and reporting
requirements pursuant to Article 7a of Directive 98/70/EC of the European
Parliament and of the Council relating to the quality of petrol and diesel
fuels
Accompanying the document
COUNCIL DIRECTIVE ../.../EU
laying down calculation methods
and reporting requirements pursuant to Directive 98/70/EC of the European
Parliament and of the Council relating to the quality of petrol and diesel
fuels 
1............ Section: Procedural
issues and consultation of interested parties. 6
1.1......... Background. 6
1.2......... Organisation and timing. 6
1.3......... Stakeholder views. 8
2............ Section: Problem
definition. 10
2.1......... Introduction. 10
2.2......... Scene setter 10
2.3......... Underlying drivers. 14
2.4......... Who is affected by the
implementation of greenhouse gas emissions methodology and reporting
requirements?. 15
2.5......... What policies to
regulate the GHG intensity of road transport fuels are there?. 16
2.6......... Baseline scenario for
the assessment of options. 16
2.7......... The right to act 25
3............ Section: Policy
objectives. 26
3.1......... General objective. 26
3.2......... Specific objective. 26
3.3......... Operational objectives. 26
4............ Section: Policy
options. 28
Option A - No methodology to calculate greenhouse gas
emissions of fossil fuels is established. 28
Option B - Methodology based on the non-disaggregated
average default greenhouse gas intensity values by fuel type based on an EU
(B1) or Member State (B2) fuel mix (“basic reporting approach”). 28
Option C - Methodology based on disaggregated average
default greenhouse gas intensity values by main feed stock types with partial
disaggregation into conventional and non-conventional feed stocks (“2011
proposal”) 29
Option D – Methodology based on the GHG impact of all
feedstocks used in the EU represented with EU average (D1) or conservative (D2)
default greenhouse gas intensity values per fuel types, while allowing all
suppliers to report alternate, actual values (“hybrid approach”) 30
Option E - Methodology based upon separate greenhouse gas
intensities for individual categories of feedstocks ("complete
differentiation") 30
5............ Section: analysis of
impacts. 32
5.1......... Assessment methodology. 32
5.2......... Option B1 - Methodology
based on the average default greenhouse gas intensity values by fuel type based
on an EU fuel mix level (“basic reporting approach”). 36
5.3......... Option C - Methodology
based on the disaggregated average default greenhouse gas intensity values by
main feedstock types (“2011 proposal”) 39
5.4......... Option D - Methodology
based on disaggregated default greenhouse gas intensity, based on average (D1)
or conservative (D2) values, while allowing suppliers to report actual values
(“hybrid approach”) 40
5.5......... Option E - Methodology
based upon separate greenhouse gas intensities for individual categories of
feedstocks ("complete differentiation") 40
6............ Section: comparison of the options. 40
7............ Section: conclusion. 40
8............ Section: monitoring and evaluation. 40
8.1......... Core indicators of
progress. 40
8.2......... Monitoring arrangements. 40
9............ Glossary. 40
10.......... Acronyms. 40
11.......... Annex I : Overview of the oil production
process (Source: Europia) 40
12.......... Annex
II : the EU crude oil supply chain (Source: various) 40
13.......... Annex
III: Low Carbon Fuel Standards outside EU.. 40
14.......... Annex
IV: information on industry sectors related to fuel suppliers. 40
15.......... Annex
V: EU suppliers dataset (Source: ICF) 40
16.......... Annex
VI: EU refinery capacity (Source: Vivid Economics) 40
17.......... Annex VII: Average GHG
intensities by Member State (gCO2/MJ)
(Source: ICF) 40
18.......... Annex
VIII: Estimated GHG emission associated with fossil and biofuels. 40
19.......... Annex
IX: Road Energy demand and related emissions in ILUC sensitivity scenario
(Source: ICF) 40
20.......... Annex
X: Intervention logic. 40
21.......... Annex
XI: Assessment methodology. 40
22.......... Annex
XII: Carbon abatement costs and potential (Source: ICF/Vivid Economics) 40
23.......... Annex
XIII: Monitoring, reporting and verification actions. 40
24.......... Annex
XIV: Screening of competitiveness impacts (Source: Vivid Economics) 40
25.......... Annex XV: Assessment of
competitiveness impacts on EU refineries (Source: Vivid economics) 40
25.1....... Estimation of the marginal
cost curves - exit and sustainable margins. 40
25.2....... Construction of marginal
costs of compliance options. 40
25.3....... Explanation of modelling
method. 40
25.4....... Establish where compliance
costs fall, that is, see whether traders or refiners bear it 40
25.5....... Construct cost curves for
each policy option. 40
26.......... Annex
XVI: Summary of ILUC sensitivity assessment 40
27.......... Annex
XVII: Projected road fuel mix 2020 for each option (non-ILUC scenario) (Source:
Vivid Economics) 40
28.......... Annex
XVIII: General considerations around environmental impacts associated with
fossil fuel production (Source: JRC) 40
28.1....... Environmental impacts:
general considerations. 40
28.2....... Air quality impacts. 40
28.3....... Pressures on biodiversity. 40
28.4....... Efficient use of
resources: water 40
29.......... Annex
XIX: Detailed information on administrative costs (Source: ICF) 40
30.......... Annex
XX: Projected road fuel mix 2020 all options (ILUC scenario) (Source: Vivid
Economics) 40
 Executive Summary Sheet 
 Impact assessment on the calculation methods and reporting requirements pursuant to article 7a of directive 98/70/EC relating to the quality of petrol and diesel fuels as amended by 2009/30/EC 
 A. Need for action 
 Why? What is the problem being addressed? 
 Article 7(a) of Directive 98/70/EC requires the Commission to adopt inter alia an implementing measure establishing a calculation method for the GHG emissions from fuels, other than biofuels, and energy. This is so suppliers can monitor and report the GHG intensity of the fuels and energy they place on the EU market in order to achieve the mandated 6% reduction target. The different impacts associated with the options available for such a methodology for fossil fuels will be assessed 
 What is this initiative expected to achieve? 
 Establish a suitable methodology for fuel suppliers to accurately report the volumes, origin, place of purchase and the life-cycle greenhouse gas emissions of the fuels that they supply. The emissions associated with all relevant stages from extraction or cultivation, land-use changes, transport and distribution, processing and combustion, must be taken into account for the purpose of ensuring that a 6% reduction in GHG intensity of road fuels is achieved. Such a methodology should also result in a sufficiently accurate fossil fuel comparator, be as consistent as possible with that already established in the legislation for biofuels, be simple to verify and not lead to an unacceptable level of administrative burden. 
 What is the value added of action at the EU level? 
 Set into effect the obligations in FQD Art 7a by implementing a methodology to be used by suppliers for calculating and reporting on the lifecycle greenhouse gas intensity of fossil fuels.  The power to adopt this through the regulatory procedure with scrutiny was specifically conferred to the Commission with the adoption of the FQD. 
 B. Solutions 
 What legislative and non-legislative policy options have been considered? Is there a preferred choice or not? Why?   
 The options assessed represent possible levels of disaggregation of information to be reported by fuel suppliers. These are, Option A - No methodology to calculate greenhouse gas emissions of fossil fuels is established Option B – Average default GHG values by fuel type (petrol/diesel) based on an EU (B1) or Member State (B2) fuel mix (“basic reporting approach”). Option C - Disaggregated default GHG values by main feedstock types (“2011 proposal”) Option D - Disaggregated default GHG average (D1) or conservative (D2) values, while allowing suppliers to report actual values (“hybrid approach”) Option E - Separate GHG values for individual categories of feedstocks ("complete differentiation") Options discarded include A (does not meet legal requirements) and B2 (internal market barriers). The remaining options allow for reporting at different levels of disaggregation by fuel type only (B1, D1, D2), by further disaggregation by feedstock type (C) or by even more detailed disaggregation by feedstock source (E), and so lead to trade-offs between the accuracy, environmental and economic impacts. In the hybrid option(s)  D suppliers would need to provide their own actual GHG intensity calculation and so would need to rely on measurement or estimation methods, and while limitations on data availability exist. In conclusion, there would appear to be a series of issues that finely balance the choice between options C, D1, D2 and B1. The option B1 approach is expected to lead to the lowest administrative costs. While option E is attractive as potentially more accurate, it would be difficult to implement this option in the short term . That is why option B1 is preferred  :  Average default GHG values by fuel type (petrol/diesel) based on an EU fuel mix (“basic reporting approach”)     
 Who supports which option?   
 Option B1 is favoured by the sector (including oil majors, independents and traders), certain exporting oil countries and certain Member States. Option C was the option proposed as the implementing measure submitted to the Member States in October 2011. This option is favoured by environmental NGOs and certain Member States. Option D is favoured by environmental NGOs, and stakeholders from the bioenergy and agricultural sectors. Option E is not favoured by any specific stakeholder group, although it is seen by some Member States and certain oil exporting third countries as the fairest approach as it is based on full differentiation of all fuels.  
 C. Impacts of the preferred option 
 What are the benefits of the preferred option (if any, otherwise main ones)? 
 The shortlisted options allow for reporting at different levels of disaggregation by fuel type only (B1, D1, D2) or by feedstock type (C) or feedstock source (E), and so they lead to trade-offs between accuracy, environmental and economic impacts. Options C, D1, D2, and B1 have similar economic impacts. B1 provides for the simplest implementation and verification mechanism given that it does not require any additional data collection. However B1 is the simplest way forward but also entails certain inaccuracies in terms of reporting GHG intensity at supplier level and poses some risks in reporting the EU average, as best available data presents low coverage of the market, does not cover imported products and no market information is collected by suppliers under this option. In addition, it presents a worse environmental performance due to encouraging a greater consumption of unconventional energy sources in the final EU fuel mix. This approach is expected to lead to the lowest administrative costs In contrast, options C, D1 and D2 are similar in terms of providing an accurate methodology and present positive environmental impacts, although D2 is more burdensome. While option E is attractive, it would be difficult to implement this option in the short term.           
 What are the costs of the preferred option (if any, otherwise main ones)? 
 The B1 option is expected to lead to the lowest administrative costs estimated to range between 2 to 3 million euros p.a. . Small differences in administrative and compliance costs have been found between the options, these represent very low overall costs and do not lead to different impacts on pump prices or competitiveness impacts. 
 How will businesses, SMEs and micro-enterprises be affected? 
 No significant impacts on businesses (including refineries) are expected as a result of the implementation of FQD. Expected pump price increases are very small and costs expected to be passed through. Although it has not been possible to categorise EU suppliers according to their size in a comprehensive manner, significantly lower administrative provisions for SMEs  are reflected in the methodology.  
 Will there be significant impacts on national budgets and administrations? 
 No. Very small administrative costs may arise under some of the options as a result of the choice of methodology. The preferred  approach B1 is expected to lead to the lowest administrative costs. 
 Will there be other significant impacts? 
 Observed variations in the fuel mix under the different options are small in the context of overall fuel demand and so should be interpreted with caution when assessing environmental, economic and social impacts. However, those options that provide differentiation at feedstock level (C and E) yield a fuel mix with a lower share of unconventional energy sources compared to option B1. 
 D. Follow up 
 When will the policy be reviewed? 
 The Commission will, monitor developments including based on the data provided by fuel suppliers to Member State authorities, with regards its proposed fossil fuel methodology on a) accuracy and reliability, b) its effectiveness, c) impacts on EU refinery sector and feedstocks, d) functioning and administrative burden, e) data availability and f) appropriateness of default GHG intensity values. 

1.                      
Section: Procedural issues and consultation of
interested parties
1.1.                
Background

The Climate and Energy package adopted by
the Council and Parliament on 22 April 2009 sought to achieve a 20% reduction
in greenhouse gas emissions by 2020. It contained an amendment introducing an
obligation on suppliers[1]
to reduce by 6% the lifecycle greenhouse gas intensity (emissions per unit
energy) of fuel and other (electric) energy supplied in the EU for use in road
vehicles (and in non-road mobile machinery) by 2020, to the Fuel Quality
Directive[2]
(''FQD'')[3].

The FQD target is expected to be met by
substituting fossil fuels with a) lower GHG intensity fuels including
sustainable biofuels[4],
Liquefied Petroleum Gas (LPG) and methane (Compressed Natural Gas, Liquid
Natural Gas and bio-methane), b) with electricity and hydrogen, and c) by
reducing upstream emissions of fossil fuels in and outside of the EU. While the
methodology for calculating the greenhouse gas emissions for biofuels was
included in the FQD at the time of adoption, the methodology to be used by
suppliers for calculating the lifecycle greenhouse gas intensity of fossil fuels
was left to be developed through comitology[5].

In this context, a draft[6] implementing measure harmonising
the method for calculating greenhouse gas emissions from fossil fuels and
electricity in road vehicles was submitted to the Fuel Quality Committee of the
Member States[7]
on 4 October 2011. The proposal was discussed on 25 October and 2 December 2011,
and the Committee vote on the implementing measure held on 23 February 2012
resulted in a "no opinion", given that a number of Member States
claimed to be unable to finalise their position in the absence of an assessment
of the economic impacts of the proposed measures. In accordance with the
relevant comitology procedure, the Commission is now required to submit a
proposal to the Council. This impact assessment supports such a proposal to be
presented to the Council. 

1.2.                
Organisation and timing

The draft implementing measure, discussed
with the Committee, had been prepared following input from stakeholders and
Member States. This included a public consultation[8] launched in
July 2009 which focussed on the issues to be addressed in the draft
implementing measure; a follow up stakeholder meeting comprising the fossil and
biofuel industries, Member States and NGOs in January 2010; and discussions on
a concept paper with the Member States in March 2010. Moreover, the proposal
presented in 2011 relies on a number of analytical studies including the work
of the JEC and its "well to wheels" study[9], the Brandt
study on natural bitumen[10],
and the Brandt study on oil shale[11].
The work of Dr Brandt was subjected to an external peer-review process whose
findings were discussed with stakeholders at a public meeting on 27 May 2011[12].
In addition,
in order to evaluate the different options for a methodology, a study of their
effectiveness in terms of achieving accurate and real greenhouse gas emission
reductions in transport fuels consumed in the EU was commissioned in 2012 and
interim findings were discussed with stakeholders at public meetings on 20
December 2012 and 15 April 2013. In additions, a number of stakeholders i.e.
the governments of Alberta and Canada, Europia, Transport and Environment, and
the Government of Estonia, accepted the offer from the Commission to present
their views on the options under consideration including any relevant analysis
that they had conducted[13].
An inter-service working group[14]
focusing on the preparation of the impact assessment report was established in
early 2012, with meetings of this Impact Assessment Steering Committee taking
place on 25 April 2012, 3 December 2012, 25 January 2013, 27 February 2013, 25
April 2013 and 3 June 2013. 
The present Impact Assessment takes into account the
recommendations formulated by the Impact Assessment Board on 3 July and 30
August 2013[15]. They requested that a number of aspects of the Impact Assessment
should be improved i.e. clarify the main drivers for the high greenhouse gas
intensity of transport fuels and baseline scenario, including the role of high
carbon conventional and unconventional oil sources; clarify the objectives of
the intervention and related monitoring arrangements; improve the assessment
and comparison of the options, including Member State specific impacts and
impacts on relations with trade partners; and better integrate stakeholder
views and explain how their concerns have been addressed.
These comments
were taken into account in the resubmitted Impact Assessment as follows,

 A new section describing stakeholder views in detail has been
     introduced and these have been integrated throughout the report;


 The problem definition section has been shortened and the
     description of the baseline has been improved in a number of aspects (i.e.
     environmental impacts, detailed description of assumptions on biofuels and
     electricity, detailed description of fuel suppliers baseline, etc.);


 More information has been provided with regards to the role of conventional
     and unconventional oil sources;


 The policy objectives have been revised to include
     considerations around simplicity of implementation and verification
     arrangements of the different options, which are now included in the
     assessment of impacts chapter. 


 Description of the policy options has been improved to include
     associated data requirements. 


 Better description of Member State specific impacts have been
     included where appropriate, as well as impacts on trade relations and WTO
     compatibility issues;


 Effectiveness of the options with regards to needed accuracy
     has been developed to highlight the strengths and weaknesses of each
     approach.


 The monitoring and evaluation section has been developed to
     provide further detail on evaluation criteria and detailed monitoring
     arrangements. 


 The executive summary, executive summary sheet, the comparison
     of the options and conclusions sections have been modified accordingly to
     reflect key changes.

 

1.3.                
Stakeholder views

The Commission is aware of the views of the main
stakeholder on the possible options for the implementation of the FQD through
the different consultation exercises conducted over the last three years.
In this context, the governments of Alberta and Canada have expressed strong concerns against any implementing measure that would assign a
higher carbon intensity to Canadian natural bitumen crude and derived products
compared to conventional oil sources, which in their view would be incompatible
with WTO rules. Although they recognise that natural bitumen inherently
presents a higher carbon intensity than most conventional crudes consumed in Europe because of the more energy intense extraction and production methods, any measure
that creates a separate category for natural bitumen would in their view
unfairly discriminate natural bitumen oil against the utmost polluting types of
conventional oil sources[16]. For this reason Canada has indicated that it
would submit any such proposal to the WTO for review.
The Estonian Government has also expressed concerns about
the potentially large economic impacts derived from any measure that would
assign a differentiated higher carbon intensity value to Estonian oil shale and
derived products given the important contribution of oil shale exploitation to
the Estonian economy[17]. In addition, the results from a study from the
Tallinn University of Technology suggesting that the typical carbon intensity
value of Estonian oil shale production is lower than that included in the 2011
implementing measure were presented to stakeholders at the meeting of 15 April
2013.   
The EU and US oil industry sector (including oil majors, independents and traders) oppose any measures
that would require the development and implementation of a chain of custody for
crude oil and derived products, given the complexity of the global fuel supply
chain as well as concerns over quality of data available and risk of fraud.
They have also expressed concerns about the impacts on competitiveness among
crude producers and refiners related to the disclosure of commercially
sensitive information under such system. In this context, a study commissioned
by Europia[18] suggests
that any methodology based on crude differentiation would lead to an increase
in total compliance costs to EU refiners between $1.5 to $7 per oil barrel[19], as well as increasing the emissions associated with fuel
transportation and leading to no global net greenhouse gas emissions savings,
as higher carbon intensity crude oil and derived products would be consumed
outside Europe where no such restrictions exist[20]. 
The bioenergy and
agricultural sectors oppose any different methodological treatment for fossil
fuels from that applied to the calculation of greenhouse gas emissions of
biofuels on the grounds of fair treatment. In this context, biofuel producers
already implement a chain of custody mechanism throughout the supply chain for
each consignment of biofuel feedstock. 
Environmental NGOs favour as disaggregated
a methodology as possible in order to ensure that the carbon intensity of fuel
suppliers is accurately measured and that the correct level of associated
mitigation actions is undertaken. In this context, NGOs specifically favour
assigning different values for unconventional oil sources, which they estimate
could represent between 5.3% and 6.7% of all oil crude and transport fuels in
EU by 2020[21], to reflect their higher carbon intensity. In addition, studies
commissioned by NGOs suggest that a low administrative burden would be
associated to such system being estimated at about 0.8-1.6 eurocents per barrel[22]. Although no assessment of the compliance costs to industry was
included, a separate study from NGOs suggest that when the price of
unconventional oils ranges from 30–90 $/bbl, a price differential ranging
between conventional and unconventional sources of $0.5 to 3 per barrel may
also have an impact on investments in extraction of unconventional oils, which
could result in an additional 19 Mt CO2 savings from discontinuation
or postponement of existing and planned projects[23]. 

2.                      
Section: Problem definition
2.1.                
Introduction

The aim of Article 7a
of the FQD is to reduce the lifecycle GHG associated with the production and
use of fuels and electric energy used in road transport. This includes those
GHG associated with the extraction of feed stocks used for their production[24], processing, subsequent transport and refining as well as their use
in vehicles. Article 7a stipulates that:
–     
Fuel suppliers shall reduce the greenhouse gas
emissions per unit energy of the fuels they supply by 6% by 2020 (Article
7a(2)(a)); and 
–     
Fuel suppliers shall report annually to Member
States on the greenhouse gas intensity of fuel and energy supplied by providing
as a minimum, 
–     
Total volumes of fuel types/energy supplied
indicating its origin and place of purchase (Article 7a(1)(a));
–     
The life cycle greenhouse gas emissions[25] per unit of energy of the fuels supplied (Article 7a(1)(b)).
The
purpose of the reporting mechanism is twofold, it aims to ensure both accuracy
in respect to the greenhouse gas emissions reductions that need to be achieved
(Article 7a(2)(a)) as well as to the actual average GHG intensity of
fossil fuels consumed in the EU (Annex IV, C, 19). 
The
FQD delegates authority to the Commission to establish a robust methodology for
the calculation of life cycle greenhouse gas emissions from fuels other than
biofuels and from energy. The FQD also invites the Commission to establish
guidelines in relation to the information to be reported by fuel suppliers. The
problem to be addressed in this impact assessment is the appropriateness of the
options for developing such a methodology and their associated environmental,
economic and social impacts. In this context, this impact assessment aims to
explore in detail key concerns raised by industry and certain Member States
with regards to administrative burden and compliance costs imposed on fuel
suppliers. 

2.2.                
Scene setter
2.2.1.          
Transport emission reductions in the context of
EU climate goals 

The EU is
committed to achieving, by 2050, an 80% to 95% reduction in greenhouse gas
emissions economy wide compared to 1990 levels. The "A Roadmap for
moving to a competitive low-carbon economy in 2050"[26] foresees that the
transport sector needs to reduce its greenhouse gas emissions by around 60%
compared to 1990 levels by 2050 to ensure a comparable cost-effective
greenhouse gas emissions abatement in that sector. This objective has been
confirmed in the Transport White Paper: "Roadmap to a Single European Transport Area – Towards a competitive
and resource efficient transport system"[27]. 
Transport
emissions can be reduced through measures which affect i) the amount of
transport activity, ii) the energy efficiency with which that transport
is carried out and iii) the greenhouse gas intensity of the energy used
to perform the transport. Moreover, efficiency gains and greenhouse gas
intensity reductions in fuels play a particularly important role in decoupling
the effects of economic growth on emissions. Given the overall transport
greenhouse gas reduction goals, the degree to which one of the three levers to
reduce emissions is not deployed, the more action will be required from the
other two, including through increased fuel efficiency from vehicles. 
Policies aimed at reducing the greenhouse
gas intensity of the energy used in the transport sector[28] will therefore play an
important role in achieving climate goals, particularly as transport sector
activity and the share of unconventional, more-energy intense, fossil fuel
sources are expected to increase to 2050[29].
While the Commission prefers a more streamlined approach over the continuation
of specific targets in the transport sector in its vision for the 2030 climate
and energy framework[30],
there is a need to establish a mechanism for reporting the greenhouse gas
emissions of road fuels in order to improve data collection and monitoring of
such emissions. Therefore, in establishing a solid regulatory framework for
reporting of such emissions through the FQD, the EU is not only ensuring a
contribution towards the 2020 emission reduction objectives, but also
developing a system to assess the upstream emissions from oil production that
is appropriate in the context of the long term commitment to decarbonisation of
the transport sector.  

2.2.2.          
EU trade in crude oil 

Crude oil is a
worldwide commodity, although logistics, product quality and geopolitical
reasons heavily influence supply sources. In total, it is estimated that around
611 million tonnes of oil[31],
around 15% of total global consumption, were consumed in the EU in 2012.
Although some domestic production of North Sea oil is available, the crude oil
consumed in the EU is mostly imported from the Former Soviet Union (FSU) and Norway, followed by the Middle East, and North Africa[32].
Figure 1: Major trade movements 2012 (million
tonnes). Source: BP Statistical review 2013
Total EU
consumption of crude oil has been decreasing slowly since 2005 and it is
expected to continue decreasing to 2020, in part due to the increased share of
renewable energy and implementation of energy efficiency measures. In the
context of sourcing, North Sea production is expected to decline, leading to
increased imports, even under such scenarios of reduced consumption. By
contrast, global crude oil consumption is expected to increase during the same
period of time. 

2.2.3.          
EU trade in petroleum products[33],[34] 

The EU is the
second largest producer of petroleum products in the world after the United States. The two key trade petroleum products in the EU in terms of volume are petrol
and middle distillates such as diesel and gasoil (including jet fuel and
heating oil). A growth in demand for middle distillates (such as diesel, jet
fuel and gasoil) between 1990 and 2008 resulted in a supply/demand imbalance in
the EU with regard to such products which has led it to be dependent on trade
in order to balance out demand and supply. If net imports of kerosene and jet
fuels are taken into account, the EU shortfall in middle distillates amounts to
upwards of 35 million tonnes of net imports per year, imports of kerosene and
jet fuel coming mainly from several Middle Eastern countries.
More
specifically, demand for petrol in the EU in 2011 was 89 million Tonnes (Mt)
whilst exports to North America, Africa and Asia comprised 18, 10 and 8 Mt
respectively which made the EU a net exporter of petrol (representing c.a. 30%
of domestic EU production). However, the EU is net importer of diesel/gasoil
with 15 Mt, 12 Mt and 8 Mt being imported from Russia, the USA and Asia respectively to help meet a demand of 279 Mt[35].
For road transport,
the EU is also a net importer of intermediate products such as processed oil
(e.g. straight run fuel oil or vacuum gas oil) and naphtha (feedstock destined
for either the petrochemical industry “ethylene manufacture” or aromatics
production). Historically, significant volumes of fuel oil and vacuum gas oil
have been imported from the FSU and processed in the EU to supplement high
quality road diesel demand that could not have been supplied by less
technologically advanced Russian refineries, which are currently being upgraded
and so trade on final products will increase. With regards to naphtha, little
is thought to be used for diesel production as it is unlikely to comply with
legally binding lower limits of aromatics permitted in diesel.

2.2.4.          
Conventional and unconventional petroleum
sources and associated greenhouse gas emissions 

The GHG
intensity of fossil fuels is normally expressed as the sum of the upstream
emissions associated with extraction and downstream emissions associated with
transport, refining and combustion in the vehicle's engine. The average
greenhouse gas intensity of transport fuels consumed in the EU currently is
approximately 88.3g CO2/MJ[36].
The largest contributor to this figure (c.a 85%) are the tail-pipe emissions
whilst upstream emissions and downstream emissions contribute approximately 5
and 10% respectively.
However,
upstream emissions can be much higher and vary according to the source, type of
feedstock and production method. Recent modelling suggests that upstream
emissions could range between 0-50 g CO2/MJ with the overwhelming
majority of EU conventional crude sources ranging between 0 and 10 g CO2/MJ.
In most simple
terms, the greenhouse gas intensity of extracting and preparing any
petrol/diesel feedstock for further refining is, inter alia, directly linked to
the energy needed for extraction. Consequently, the greenhouse gas intensity of
such activities is related to how immobile the feedstock is, as found
in-ground, prior to extraction. Natural bitumen[37] feedstocks are generally
more dense and viscous and do not flow freely under natural conditions[38]. The further
differentiation of natural bitumen feedstock from conventional crude oil is
linked to the extraction methods employed[39],[40],[41]. This also stems
from its viscosity and density. Natural bitumen is extracted through mining or
thermally enhanced gravity drainage where the fossil fuel deposit is heated
with steam so as to lower its viscosity and where the thermal energy is mainly
derived from sources other than the feedstock source itself[42]. 
It is important
to note that the presence of natural bitumen is not unique to any one location.
United States Geological Survey (USGS) reports the presence of natural bitumen
in North and South America, Europe, Asia and Africa[43].
 
Figure 2: Typical GHG emission ranges for
conventional crude oil and oil sands. Source: Brandt [44] 
It is clear
from the Brandt study on oil sands that some of the worst performing conventional
crude feedstocks (i.e. high flaring emissions associated with certain Nigerian
oil fields) and the best performing natural bitumen feedstocks (i.e. using
natural gas for their extraction) present a similar level of greenhouse gas
emissions, as shown in Figure 2. It is important to note that this overlap does
not normally stem from the naturally occurring differences in physical
properties of the respective feedstock sources but is mostly, for example, due
to the flaring and venting emissions occurring during the extraction of oil and
which result from the inappropriate management of the simultaneous extraction
of two separate fossil fuels, crude oil and natural gas. In this context it is
worth noting that while the amount of unconventional oil sources is expected to
rapidly rise in the future as the exploitation of such feedstocks increases
globally[45],
greenhouse gas emissions associated with flaring and venting of conventional
crude show a downward trend worldwide[46]. 


2.2.5.          
 Information about petroleum feedstocks
affecting their greenhouse gas intensity

There is
currently a significant amount of information that is collected by economic
operators along the oil supply chain because it is either required for
production purposes (i.e. the chemical composition of crude oil is needed for
efficient refining) or for compliance with specific legislation. This is
particularly comprehensive for imported and exported goods as information about
their origin, tariff classification (i.e. including differentiation between conventional
and unconventional sources)[47],
mass/volume and physical characteristics has to be recorded and reported to the
competent authorities for compliance with customs legislation[48]. Nevertheless, there
are gaps in the transfer of information for "finished" and
"intermediate" products such as petrochemicals in need of further
refining, which represent however only around a quarter of total EU oil
consumption. 
With regards to
the reporting of the associated greenhouse gas emissions, conventional and
unconventional feedstocks are already treated differently in the legislation.
For example, the greenhouse gas emissions of natural bitumen (i.e. oil sands
and tar sands) and oil shales are differentiated in Commission Regulation No 601/2012 on the monitoring and reporting of
greenhouse gas emissions under the European Emissions
Trading System (i.e. a higher CO2 emission factor for "oil
shale and tar sands" than for conventional crude oil is stated on the
basis of their energy and carbon content)[49].
Furthermore, many companies in the oil sector already voluntarily report on
their greenhouse gas emissions, although no common methodology is being used. 
Further
detailed information on what information is currently available and where the
key gaps and difficulties remain can be found in Annex
II : the EU crude oil supply chain.  

2.3.                
Underlying drivers

In the context
of establishing a suitable methodology for the calculation of the lifecycle GHG
emissions of fossil fuels, there are a number of underlying drivers that need
to be considered. This is because the chosen method for obligated parties to
calculate and report emissions of fuels derived from different crude sources,
and the degree of differentiation applied to those, would play an important
role in influencing the final mix and associated mitigation actions for the
energy consumed in the EU. 

2.3.1.          
Increasing production of unconventional oil
sources and need for greater differentiation between feedstocks

Vast
unconventional oil reserves are concentrated in Canada, Venezuela and a few other countries. In Europe, exploitation of unconventional sources is mainly
limited to Estonian oil shale production for export (80%) and represents a
significant contribution to the Estonian employment and GDP[50]. However, although
only a small fraction is used domestically in heat production in Estonia, plans for the production of transport fuels from 2016 onwards exist.  
Whilst there
are high costs associated with their production, exploitation remains economic
with oil prices of around $65 to $75 per barrel[51]. As such, whilst
unconventional oil feedstocks such as oil sands and oil shale do not currently
represent a significant share of Europe's supply, their share is expected to
increase in the future with some studies predicting that over 10% of global
supply is expected to come from these sources by 2020, rising up to 15% in 2035[52]. In certain Member
States where significant investments are being made by refineries to be able to
process heavier crudes, the share of unconventional oil could increase very
rapidly. For example, Spanish oil industry estimate that unconventional oil
could represent 23% of the Spanish crude mix by 2020[53]. Nevertheless,
replacement crudes of similar quality and a lower GHG footprint are available
to offset this supply.      
Although there
is an overlap between the greenhouse gas emissions of some of the worst
performing conventional and the best performing unconventional crudes, there is a significant deviation between the average greenhouse gas
emissions associated with conventional oil and the average greenhouse gas
emissions of unconventional oil sources. In this context, it is also important
to note that while there is significant uncertainty inherent to measurements
regarding flaring and venting[54]
emissions released to the atmosphere, emissions
associated with unconventional sources are related to their production methods
and therefore more easily recorded. 
The average
production of unconventional oil generally emits more greenhouse gases per
barrel than that of most types of conventional oil. In the absence of any
mitigation being conducted, the foreseen amount of unconventional oil could
result in significant upstream emissions amounting to around 2.8 billion metric
tonnes of CO2 per year globally[55].
In addition, there are also some differences in the greenhouse gas intensity of
similar feedstocks within the conventional category because of the differences
in the way these feedstocks are produced (e.g. because of excessive flaring and
venting). 
As such, as
much as possible differentiation between feedstocks is desirable in order to
ensure that their emissions are accurately reported and monitored, and that
appropriate mitigation measures are conducted. Possible mitigation measures are
also applicable to reduce the emissions from unconventional oil production
include more efficient extraction technologies and carbon capture and storage
(CCS). For example, reducing the input of external heat to extract oil sands is
possible from a technical point of view but is not widely practiced because
revenues from selling the feedstock yields higher profit than optimising
efficiencies[56].  


2.4.                
Who is affected by the implementation of
greenhouse gas emissions methodology and reporting requirements?

Regulations to
estimate, report and monitor the greenhouse gas intensity of fossil fuels used
in the transport sector may affect fuel suppliers, Member States, third
countries exporting fuel to the EU, associated industries (i.e. biofuels) and
consumers (i.e. through price impacts) in different ways according to the
methodology being implemented. These impacts will be evaluated in more detail
in chapter 5 in the context of the shortlisted options for implementing such
methodologies. In particular, EU refiners are exposed to extra-EU competitive
pressures and intra-EU greenhouse gas and environmental regulations that differ
from those in the rest of the world (ROW). This is particularly important as EU
refiners, to a larger extent maintain and invest in EU assets, unlike
independent fuel traders who mainly import and trade petroleum products in
order to balance marginal, aggregate and distribute refinery products, and are
not affected by minor shifts in product movement. 

2.5.                
What policies to regulate the GHG intensity of
road transport fuels are there?

Similarly to
the FQD's principles, a number of Low Carbon Fuel Standards (LCFS)[57] have been put in place
or are being developed by different jurisdictions in North America. A short
description of these regimes, as well as of their methodological choices, is
included in Annex III: Low Carbon Fuel Standards outside EU. 

2.6.                
Baseline scenario for the assessment of options 
2.6.1.          
Overview of related industries

There are a number of industry sectors in
the EU that are directly or indirectly associated with the production and
consumption of road fuels. The  industry sector most directly affected by the
FQD are EU fuel suppliers, whether EU producers, who process crude oil into
petroleum products or those that do not have EU based refining capacity but
trade finished products, and as such are the main focus of the quantitative
economic impacts in chapter 5. Information on other sectors closely related to
the refinery sector such as the petrochemical industry and those directly
involved in the production of renewable alternatives in road transport such as
biofuel producers is included in Annex
IV: information on industry sectors related to fuel suppliers. 
              2.6.1.1.          EU
fuel suppliers 
The FQD defines a supplier as “the
entity responsible for passing fuel or energy through an excise duty point or,
if no excise is due, any other relevant entity designated by a Member State”[58]. Accordingly, this is the entity regulated by Article 7a and
therefore the entity responsible for applying the required reporting/greenhouse
gas emissions calculation methodology.
There are two main types of
suppliers in the EU: producers who process feedstocks from within the EU or outside
EU to produce fuels for the EU market, and fuel traders that do not have EU
based refining capacity but trade finished products. 
As there is no data at EU level
on the number fuel suppliers, the Commission approached Member States in 2010 and fuel suppliers in 2012 with a questionnaire to collect key information on
the sector[59]. Extrapolation of the answers received from 12 Member States was
conducted to provide a representative baseline for Member States. Further
detail on the approached followed for extrapolating fuel suppliers and the
results are presented in the Annex
V: EU suppliers dataset (Source: ICF)[60].
Given the limited number of
responses received from Member States and the gaps in the information supplied,
it was not possible to categorise EU suppliers according to their size in a
comprehensive manner. In addition, subsequent attempts from the Commission to Member States and industry associations such as UPEI have failed to yield any useful
information that could be used in providing a more disaggregated analysis of
competitiveness impacts by company size accurately.   
              2.6.1.2.          Current
production and turnover of EU refining sector
The EU's crude
refining capacity currently represents 778 million tonnes per year (or 15
million barrels per day), equivalent to 17% of total global capacity. The
European refining industry consists of 101 refineries spread across 22 Member
States. Turnover in 2012 was estimated to be around €419 billion with around
€30 billion value added[61]. EU demand for refined products peaked in 2006, decreasing every
subsequent year[62]. 
Italy, Germany, France and the UK have the largest refining capacity in
the EU, accounting for around half of the total refining capacity. The
refineries of Poland, Belgium and the Netherlands are the largest, whilst those
in Romania and Sweden are the smallest. ANNEX VI: EU REFINERY CAPACITY, shows in more detail the refining sector across the different
Member States. The average refinery utilisation rate in OECD Europe in 2011
amounted to 77%, compared to 85% in 2008[63].
In terms of the
evolution of the petroleum product demand mix in the EU, the share of jet fuel
and kerosene has increased between 1990 and 2008 from representing 5.5% to
9.4%; the share of diesel and gasoil together from 17.7% to 31%. Meanwhile, the
share of petrol has decreased from 22.7% to 16.1% and the share of heavy fuel
oil from 16.3% to 6.4%. It is estimated that of the refined products produced
in EU refineries, 63% are used in transport, 22% are used in industry and 15%
are used for heating and power. 
There are an estimated
190,000 people employed in refineries in the EU[64]. Around €240 billion/year is collected in the EU through duties and
taxes on oil fuels. The EU refinery industry invests on average €5 billion/year
in refining, R&D, transport and distribution.
              2.6.1.3.          Outlook
on EU refining sector
There are 101
refineries operating in all Member States with the exception of Cyprus, Estonia, Latvia, Luxembourg and Malta. These are typically located at sites with landing
terminals for oil tankers, around key infrastructures such as major ports or
pipelines, with around half of the total being situated in North West Europe
(49), the largest of which is the Amsterdam-Rotterdam-Antwerp (ARA) market[65]. Additional capacity is allocated in the Mediterranean region (37)
and Central and Eastern Europe (17). 
The traditional
ownership structure is changing. "Oil majors" have divested towards
Indian, Chinese and Russian conglomerates or smaller independent refiners or
have separated refining activity from upstream exploration and production.
Overall
refining capacity in the EU has been relatively stable over the last twenty
years (see figure 3 below), although there have been changes in ownership. The
top six refinery players in the EU account for around 50% of capacity. The main
players differ between the regions. Whereas the international oil companies
(e.g. Shell, Total, BP, ExxonMobil) have a strong presence in the North West
Europe market, they are less prominent in the Central, Eastern and Mediterranean markets. Here national oil companies, such as Repsol and ENI, are the major
players. Across the EU, there is a large number of smaller refining companies,
such as Orlen, Petrom, Cepsa, Eni, Galp, MOL, Omv, Lukoil, Neste and Statoil
that operate entirely on the European market. 
Figure 3: Global refinery production
1970-2012. Source (IEA)
Another
difference between regions is in the type of refining capacity they have –
simple or complex. Complex refining, while more capital intensive and more
expensive enables higher yields of more valuable and marketable products – such
as diesel. North West Europe has a higher proportion of simple refining
capacity than either the Mediterranean or Central and Eastern Europe. In the
longer term, possible reliance on heavier crudes and a continuing shift in
demand towards higher value products such as diesel and away from petrol may
require additional investment to increase the capacity of complex refining units.
In this context, Spanish refineries report investments of 6 billion euro over
the last few years to prepare the process units to adjust to a fuel mix with a
greater share of unconventional oil[66].   
Refinery
economics are determined by two global commodity markets namely that for crude
and refined products market. The margin between these two determines the
potential profitability of the refinery once operating costs are taken into
account. Refiners therefore try to optimise the costs of the crude oil they buy
in light of relevant constraints such as the technological
configuration/complexity of the refinery and physical supply constraints such
as access to sea ports and pipelines. Changes to the cost of particular crude
supplies may adversely affect refinery profitability in the EU because of the
operational dependence on particular crude sources. For example, most of the
oil consumed in Latvia, Lithuania and Estonia is imported from Russia via pipelines, as these countries are important transit points for exports of
Russian oil.
Overall, the commercial
environment facing the EU refining industry is difficult, primarily as demand
in Europe is expected to be lower in the future. This is because of:
- the on-going shift from petrol
to diesel[67] has led to an excess petrol production capacity in the EU. The
excess petrol production is currently being exported to the US market but this trend is not expected to continue beyond 2020 given expected market developments;
- in addition, demand for petrol
in Europe is also being reduced through the increasing use of bioethanol and
energy efficiency measures in the transport sector, while the demand for middle
distillates such as jet fuel, road and marine diesel is growing;
- at global level, refiners in
Asia and Middle East are developing additional capacity and entering the EU
market. 
Due to excess capacity
and low economic margins associated with production of petrol, some EU refiners
will struggle to maintain their operations unless new export markets are found
to absorb increasing EU petrol surplus. This may translate into a reduction in
petrol production through restructuring or by shutting down entire refineries.
The IEA reports that capacity equivalent to 1.5 million barrels a day have shut
down or have been scheduled to shut down since 2008[68] Such recent developments have yielded a return to improved margins
not seen since 2006 reflecting the resilience of the refinery industry to the
EU-wide economic recession[69]. To 2020, work conducted for the Commission estimates that a number
of additional refinery closures, ranging between 18 and 23 depending on the
total biofuel consumption, will be needed to achieve sustainable utilisation
rates regardless of the chosen FQD methodology[70]. 

2.6.2.          
Overview of road fuel consumption out to 2020

Table 2 below shows the 2010 fuel consumption levels in road transport in the
EU-27, as well as 2020 projections. In this context, it is expected that the
on-going downward trend in consumption will continue to 2020, with an overall
decrease of approximately 1841 PJ, being more pronounced for petrol than diesel
as trends on increasing dieselisation of the car fleet are expected to continue
to 2020. This is driven by a combination of increased energy efficiency
measures and an increased consumption of renewables (i.e. biofuels and
electricity). 
 Fuel || 2010 consumption (PJ) || 2020 consumption (PJ) ||
 Petrol || 4002 || 2958 ||
 Diesel || 8532 || 7590 ||
 Electricity || n/a || 87 ||
 Hydrogen || 0 || 0 ||
 LPG || 219 || 208 ||
 CNG || n/a || 44 ||
 LNG || 0 || 0 ||
 TOTAL || 12753 || 10886 ||
Table
2: EU-27 Fuel mix consumption (PJ). Source: ICF from EUROSTAT 2010 and WEO Scaled
Projections for 2020
Although exact
amounts are not being reported, only very limited quantities of petrol and
diesel currently consumed in the EU in 2010 are believed to come from
unconventional oil sources such as oil sands[71]. These quantities mostly relate to imports of refined products, as
with the exception of small volumes of Estonian oil shale used outside the
transport sector, no other feedstocks from unconventional sources are currently
being extracted or produced in the EU. In addition, all the crude imported from
  Nigeria, some of which may come from high flaring oil fields, represents a
small part of total crude being consumed in the EU (4.1%)[72]. 
The amount of
renewable electricity in transport and biofuels consumed in 2020, as reported
by the Member States in their National Renewable Energy Action Plans[73] and adjusted to forecast total fuel consumption, is included in the
table above (overall numbers for petrol and diesel include total biofuel volumes).
In order to provide a more disaggregated biofuel
baseline into the specific feedstocks, the 2020 biofuel mix in the EU as
estimated for the preparation of a different impact assessment by the
International Food Policy Research Institute (IFPRI) was used and is presented
in table 3 below[74]. 
 Biofuel Feedstock || Baseline 2020 (PJ) 
 Corn (maize) || 29 
 Sugar beet || 40 
 Sugar cane || 103 
 Wheat Process fuel not specified || 15 
 Wheat Natural gas as process fuel in CHP plant || 15 
 Wheat Straw as process fuel in CHP plant || 15 
 2G ethanol - land using || 10 
 2G ethanol - non-land using || 10 
 2G biodiesel - land using || 15 
 2G biodiesel - non-land using || 15 
 Waste 1st. Gen. diesel || 31 
 Palm oil || 82 
 Palm oil with methane capture || 82 
 Rapeseed || 385 
 Soybean || 105 
 Sunflower || 40 
 TOTAL || 991 
Table
3: EU-27 2020 biofuel consumption (PJ) [75]. Source: EC calculations based on IFPRI feedstock projections

2.6.3.          
Baseline disaggregated fuel consumption 2020,
associated GHG and wider impacts

To better
understand the different fossil fuel feedstocks that may be consumed in the EU
in 2020 before the FQD is applied, the overall estimated demand detailed above
was modelled using the WORLD linear program, through combining this information
with bottom up detail in a number of areas[76],[77]. Subsequently, the greenhouse gas
emissions associated with the consumption of these fuels in the baseline were
calculated by applying the GHG intensity values used in the 2011 proposal for
the Article 7a fossil fuels' methodology[78]. With regards to biofuels, the estimated GHG intensity values
presented here take into account their expected
improvements in greenhouse gas emissions performance towards 2020, based on
estimates from COWI[79]. However, those values do not take into account more recent
developments (such as the ETS proposals for ammonia and nitric acid plants in
EU), and do not cover improvements for all biofuel feedstocks. As such, these
have been adjusted by JRC to allow for comparison across all biofuels[80]. The results of this analysis are shown in table 4 below[81]. Further information on the assumptions is included in Annex
VIII: Estimated GHG emission associated with fossil and biofuels.
The carbon
intensity for electricity is assumed to be 130gCO2e/MJ for 2010 as calculated
by the JRC[82], and reduced by 13% based for 2020 taking into account an increase
in the production of renewable energy[83]. Adjustments to account for the increased efficiency of the
powertrain by a factor of 0.4 were also made[84].
A number of key
conclusions can be drawn from these results. Overall, that the FQD 6%
greenhouse gas emission reduction target, requiring the average greenhouse gas
intensity of all fuels to be reduced to 83gCO2/MJ, would not be
achieved through the increased deployment of biofuels and electric vehicles
driven by the Renewable Energy Directive targets as reported by the Member
States (i.e. corresponding to a 83.8gCO2/MJ), but would need an
additional 0.8 percentage point reduction (i.e. corresponding to a reduction of
7.8 Mt over a total of 913.8 Mt emissions) to come from other technologies such
as reductions in upstream emissions. 
With regards to
the final fossil fuel mix, most of the diesel and petrol consumed in the EU in
2020 in energy terms is expected to be produced from conventional sources. All
Nigerian crude, some of which may come from high
flaring oil fields, continues to represent a small part of the total crude
being consumed in the EU (7%)[85]. In addition, small amounts of fuel being produced from high GHG
intensity unconventional crudes such as Canadian and Venezuelan natural
bitumen. In this context, most of the unconventional sources will come in the
form of Venezuelan natural bitumen to be refined in the EU into petrol and
diesel, followed by diesel from Canadian natural bitumen refined in the United States, where most of the excess capacity for supplying and processing these types
of crude exists. It also appears that small amounts of other high greenhouse
gas unconventional products (e.g. oil shale, gas-to-liquid, coal-to-liquid) will
also enter the market in 2020. In total, it is estimated that 345PJ, or 3% of
all the energy used, would come from unconventional sources. 
It is worth
noting that although the energy share of high GHG intensity unconventional oil
remains comparatively low at 3%, their associated greenhouse gas emissions at
3.48 gCO2e/MJ are significant in terms of the 6% reduction target as they alone
represent 4% of the 2010 fossil
fuel GHG intensity levels and thus equivalent to more than half of the desired
reduction in GHG intensity of the fuels used in the EU in 2020[86]. 
In addition to the GHG impacts, the
production of fuels can have a negative impact on the environment as a result
of the sum of upstream activities (extraction, including exploration and
production, followed by transportation by tanker or pipeline); mid-stream
activities (refining), and downstream activities (transportation by tanker,
pipeline or rail to marketing terminals and bulk plants and eventually service
stations and commercial accounts). These activities can lead to negative air
quality impacts, biodiversity impacts and the consumption of large amounts of
resources (i.e. land use, water, energy input, etc…). 
These impacts are much greater when they
involve the production of unconventional energy sources such as natural
bitumen, as the impacts on air quality, biodiversity and land use change,
energy and water requirements are greater. This is of particular importance
when its production leads to significant surface disturbance that could lead to
significant impacts on primary forests and wildlife, or when aquifers are
affected through mining affecting downstream water supply. 

2.6.4.          
Sensitivity analysis of fuel mix consumed in the
baseline                                                 

In the context
of mitigating against the indirect land use change impacts of biofuels, the
Commission has recently proposed to limit the contribution of conventional crop
based biofuels towards the Renewable Energy Directive targets to 5%[87]. 
It is not clear at this stage what would be
the final measure adopted, but any of the options under consideration is likely
to impact on the final fuel mix for 2020 presented in this impact assessment.
In order to better understand the possible impacts of a reduced contribution
from conventional biofuels to the FQD target, a sensitivity scenario, where the
estimated indirect land use change emission factors are taken into account in
the sustainability criteria for biofuels is included here. This is because this
option would lead to the largest reduction in the consumption of conventional
biofuels, and almost double that expected to result from the Commission’s
proposal, and as such the final outcome will be somewhere between the business
as usual scenario and this extreme sensitivity case. 
Under such a scenario, it is assumed that
suppliers would no longer blend those biofuel feedstocks that do not provide at
least a 50% GHG reduction benefit compared to petrol or diesel, once the
estimated indirect land use change emissions[88] have been taken into account. This leads to the elimination of the
least efficient wheat bioethanol pathways and all biodiesel pathways from
conventional oil crops (i.e. biodiesel from rapeseed, sunflower, soy and palm
oil), with the gap in demand (724PJ) being met with fossil petrol and diesel at
87.5 gCO2/MJ and 89.1 gCO2/MJ[89]. The revised emissions for the fuel forecast out to 2020 after
displacing the selected biodiesel pathways are shown in Annex
IX: Road Energy demand and related emissions in ILUC sensitivity scenario
(Source: ICF)
A number of key
conclusions can be drawn from these results. Overall, that the FQD 6%
greenhouse gas emission reduction target, requiring the average greenhouse gas
intensity of all fuels to be reduced to 83gCO2/MJ, would not be
achieved in the baseline scenario, needing an additional 4.5 percentage point
reduction (i.e. a total 951.7 Mt of emissions translate into 87.2gCO2/MJ) to
come from other available tools such as reductions in upstream emissions and
advanced biofuels[90]. 
 Fuel || Feedstock || GHG Emissions || Energy Consumption 
 (MMT)  (PJ) 
 Petrol || Conventional crude || 232.3 || 2652 
 Natural bitumen (Venezuela to EU) || 7.2 || 68 
 Oil shale || 0.2 || 2 
 Subtotal || 239.7 || 2722 
 Diesel || Conventional crude || 586.2 || 6559 
 Natural bitumen (Venezuela to EU) || 18.4 || 170 
 Natural bitumen (Canada to USGC) || 2.3 || 21 
 Oil shale || 0.6 || 4 
 CTL || 3.2 || 19 
 GTL || 6.0 || 62 
 Subtotal || 616.7 || 6835 
 LPG ||   || 15.3 || 208 
 CNG ||   || 3.4 || 44 
 Electricity || EU-average || 3.9 || 87 
 Ethanol || Corn (maize) || 0.9 || 29 
 Sugar beet || 1.1 || 40 
 Sugar cane || 2.1 || 103 
 Wheat Process fuel not specified || 0.7 || 15 
 Wheat Natural gas as process fuel in CHP plant || 0.7 || 15 
 Wheat Straw as process fuel in CHP plant || 0.4 || 15 
 2G ethanol - land using || 0.2 || 10 
 2G ethanol - non-land using || 0.1 || 10 
 Subtotal || 6.1 || 236 
 Biodiesel || 2G biodiesel - land using || 0.1 || 15 
 2G biodiesel - non-land using || 0.1 || 15 
 Waste 1st. Gen. Diesel || 0.3 || 31 
 Palm oil || 4.2 || 82 
 Palm oil with methane capture || 2.4 || 82 
 Rapeseed || 15.4 || 385 
 Soybean || 4.9 || 105 
 Sunflower || 1.3 || 40 
 Subtotal || 28.7 || 756 
 Total || 913.8 || 10886 
Table 4: EU-27 2020 fuel consumption (PJ) and associated GHG emissions[91]. Source: ICF

2.7.                
The right to act 

Following the
adoption of the amendment to the FQD in April 2009, an obligation on suppliers
to reduce by 6% the lifecycle greenhouse gas intensity (emissions per unit
energy) of fuel and other (electric) energy supplied for use in road vehicles
(and in non-road mobile machinery) by 2020 was introduced. In this context, the
power to adopt a methodology to be used by suppliers for calculating the
lifecycle greenhouse gas intensity of fossil fuels through the
regulatory procedure with scrutiny was specifically conferred to the Commission[92]. Establishing this methodology through an
implementing act is essential in order to make the 6% target effective.
Furthermore, due to the inconclusive deliberations in the Fuel Quality
Committee in February 2012, according to the provisions of the comitology
decision, the Commission has now an obligation to submit a proposal to the
Council.  

3.                      
Section: Policy objectives

The Commission is
evaluating a number of different options for a fossil fuel calculation
methodology. To enable the assessment of the options, it is necessary to
establish the general, specific and operational objectives. The relevant FQD provisions under which such methodology
should be developed are described under section 2.1.

3.1.                
General objective

Following from the above, the general
objective reflecting the importance of establishing a methodology to ensure
that the FQD aims are met is, 

 To ensure that the greenhouse gas intensity of
     road transport fuels is accurately measured and reduced by at least 6%
     compared to 2010. 
3.2.                
Specific objective

In line with
the specific goals of the policy intervention, the general objective can be
translated into the following specific objective: 

 To establish a suitable methodology for fuel
     suppliers to accurately estimate and report the volumes, origin, place of
     purchase and the life-cycle greenhouse gas emissions of the fuels that
     they supply. 
3.3.                
Operational objectives 

The desired
characteristics of a methodology can be captured in a number of operational
objectives. Primarily, the methodology needs to be as accurate as
possible to allow fuel suppliers to enact their reporting obligations and for
the Commission to maintain the fossil fuel comparator up to date. 

 To establish a methodology for fuel suppliers
     to report as accurately as possible[93]
     the life-cycle greenhouse gas emissions, covering all relevant stages
     including extraction, land-use changes, transport and distribution,
     processing and combustion, irrespective of where those emissions occur, of
     the fuel and energy other than biofuels that they supply. 
 To ensure that the methodology results in as
     accurate as possible fossil fuel comparator.

Given that the methodology for biofuels is
already included the legislation, the design of the fossil fuel methodology
should be as consistent as possible with that for biofuels, 

 To ensure that the reporting methodology is
     as consistent as possible with that already
     established in the legislation for biofuels. 

Once the operational objectives above have
been satisfied, the methodology should be kept as simple as possible as
to avoid any unnecessary additional burden on industry and authorities,

 To ensure that such methodology enables
     Member States to verify compliance by fuel suppliers with their obligation
     in a way which does not lead to an unacceptable level of administrative
     burden for suppliers and competent authorities. 

The
evaluation of the effectiveness of the policy options will focus on how well
these operational objectives are achieved, while considering wider
environmental, economic and social impacts in line with the Commission’s impact
assessment guidelines. In this context, special
attention will be paid to the impacts that these options may have on the
competitiveness of the domestic EU refinery sector and on the administrative
burden that may result on fuel suppliers in terms of the information that they
may be required to collect, store and report. The
intervention logic is described in the pictogram in Annex
X: Intervention logic

4.                      
 Section: Policy options

The Commission wishes to consider the effectiveness of a number of
options for establishing a methodology for the calculation of greenhouse gas
emissions from fuels and energy other than biofuels consumed in the EU, as well
as for the reporting of information regarding their volumes, origin and place
of purchase. In addition to the methodology proposed in the draft implementing
measure submitted to Member States in October 2011[94], a very large number of additional options can be developed
according to the different possible levels of disaggregation (e.g. product or
feedstock), and whether actual calculations of greenhouse gas emissions or
established default values are permitted. This impact assessment focuses on the
key options that have been proposed by stakeholders. These are:

Option A - No methodology to calculate
greenhouse gas emissions of fossil fuels is established 

This option would assume that the Commission
did not propose a methodology to give effect to Article 7a of the FQD. As a
methodology is required for Member States to implement the FQD, this would mean
the Commission failing to act according to its legal obligation. As such, this
option is discarded without any further analysis.

Option B - Methodology based on the
non-disaggregated average default greenhouse gas intensity values by fuel type
based on an EU (B1) or Member State (B2) fuel mix (“basic reporting approach”).

Under this approach, a representative
lifecycle greenhouse gas intensity would be established in grams CO2
per Mega Joule ("average default greenhouse gas intensity") for each
of the four main road fossil fuel types consumed in the EU (i.e. petrol,
diesel/gasoil, liquefied petroleum gas and compressed natural gas). This would
include upstream emissions from the exploitation of feedstocks as well as the
processing, transport and combustion of feedstocks and finished fuels.
Suppliers would need to determine their annual volumes and energy content of
each fuel type produced or imported, information which is already being
collected by suppliers. The lifecycle greenhouse gas emissions attributed to
the production of these fuels would be based on default values derived from
industry data on EU refined crudes[95]. Within this overall approach, the lifecycle greenhouse gas
emissions can be attributed to each fuel type based on the EU (option B1) or Member State (option B2) crude mix. The
ability for fuel suppliers to provide actual values is not allowed under any of
these two options[96].
This approach would represent the simplest
methodology as it involves the least possible level of disaggregation, i.e. it
does not differentiate between conventional and unconventional fossil fuel
sources in the reporting of their specific carbon intensities towards achieving
the 6% FQD reductions, as these are instead integrated in the EU or MS average
for the respective fuel types, and it does not require suppliers to report the
greenhouse gas emissions specific to each fuel consignment. Therefore, no
difference between fossil fuel suppliers according to the feedstocks that are
included in their fuel mix would be reported[97].
However, there are
significant concerns specific to the potential distortions in the correct
functioning of the internal market that may arise as result of the
implementation of option B2. This is because the introduction of different
default values at Member State level under this option would effectively impose
different requirements to fuel suppliers depending on which Member State the fuel is supplied to and so it may lead to barriers to internal market trade.
In this context, it is worth noting that the fundamental objective of the FQD
was to establish harmonised fuel quality rules to reduce environmental impacts
from vehicles and to ensure vehicles operate correctly everywhere in the EU. As
the implementation of option B2 is counterproductive to the aim of the FQD,
this option has been discarded and only option B1 has been further assessed in
chapter 5.   
Option B1 is favoured by the oil industry
sector (including oil majors, independents and traders), certain exporting oil
countries and certain Member States. 

Option C - Methodology based on
disaggregated average default greenhouse gas intensity values by main feed
stock types with partial disaggregation into conventional and non-conventional
feed stocks (“2011 proposal”)

This option was proposed as part of the
implementing measure submitted to the Member States in October 2011. The methodology
would separate non-conventional feed stocks and conventional feed stocks so
that the greenhouse gas intensity of petrol and diesel made from oil
(comprising a range of different crudes), natural bitumen, oil shale, coal to
liquid, gaseous fuels and electric energy, etc. would be distinguished.
However, petrol and diesel made from different conventional petroleum feed
stocks would not be treated separately i.e. all conventional petroleum feed
stocks would be treated identically with a single default greenhouse gas
intensity value. The lifecycle greenhouse gas emissions attributed to the
production of these fuels would be based on default values derived from public
data[98]. 
This option would require fuel suppliers to
report information on the feedstocks that are included in their fuel mix. This
methodology would require fuel suppliers to collect information beyond their
existing data collection mechanisms (i.e. suppliers already report volumes of
products, and refiners' internal monitoring systems already track the crudes
that are being used). Additional requirements would be needed for the refiners'
tracking system to comply with this methodology and for the data on the
feedstock split associated with each batch of product trade to be passed on.
The ability for fuel suppliers to provide actual values is not allowed under
this option [99]
This option is favoured by environmental
NGOs and certain Member States. 

Option D – Methodology based on the GHG
impact of all feedstocks used in the EU represented with EU average (D1) or
conservative (D2) default greenhouse gas intensity values per fuel types, while
allowing all suppliers to report alternate, actual values (“hybrid approach”)

As per option B1, under
this option, suppliers’ compliance would be based on the GHG impact of all
feedstocks used in the EU (e.g., petrol and diesel/gasoil from oil, natural
bitumen, oil shale, coal to liquid, gaseous fuel and electric energy, etc.).
Suppliers would report default values based on average (option D1) or
conservative, higher than average, GHG intensity values (D2).[100]. The latter one being the same approach as the one laid down in the
Directive for biofuels. 
These options would
require suppliers to report information on the feedstocks that are included in
their fuel mix. However, this information will not influence suppliers’
compliance with the reduction target. Alternatively, suppliers may wish to provide
actual values. This methodology implies the same data collection and
traceability requirements as option C, the compliance effort of option B1, and
additional efforts for those suppliers choosing to report actual values. But it
is expected that only suppliers whose fuel mix yield a lower greenhouse gas
intensity than the default value would opt to provide actual values[101] and hence, this
option would lead to a significant inaccuracy or under estimation.
This option is favoured
by environmental NGOs, and stakeholders from the bioenergy and agricultural
sectors who asked for a coherent approach with the methodology applied to
biofuels. 

Option E - Methodology based upon
separate greenhouse gas intensities for individual categories of feedstocks
("complete differentiation") 

This option would require upstream
greenhouse gas emissions estimates for individual categories of feedstocks
within those types described under option C to be calculated and reported (e.g.
field level, trade name, Marketable Crude Oil Name, etc.) by suppliers. In
addition, similar information would need to be available in respect of
intermediates and refined products which are purchased by refiners and or fuel
suppliers. 
As such, this option should provide the
most accurate reporting of the GHG intensity of fuels consumed in the EU. This
is because it would provide differentiation not only between the main feedstock
categories (i.e. petrol and diesel/gasoil from oil, natural bitumen, oil shale,
coal to liquid, gaseous fuels and electric energy, etc.), but also within these
categories (i.e. oil based fuel with higher and lower upstream emissions). This
is the option with the most complex reporting system[102].     
In practice, suppliers would need to
provide their own actual GHG intensity calculation and so would need to rely on
measurement or estimation methods, while limitations on data availability
exist. With regards to feedstock characterisation, data availability is high
for EU and North American feedstocks and refineries but more challenging for
other regions. In contrast, suppliers that need to draw on data from other
companies, little data is publically available and so there may be difficulties
in providing such information due to commercial sensitivity reasons. With
regards to estimating the associated GHG intensity, lifecycle emission models
with default data already exist but these would need to be tailored, either
unilaterally, or by each supplier, in order to reflect EU specifics. In this
context, the level of disaggregation required would be critical[103].
This option is not favoured by any specific
stakeholder group, although it is seen by some Member States and certain oil
exporting third countries as the fairest approach as it is based on full
differentiation of all fuels.   

5.                      
 Section: analysis of impacts 
5.1       Assessment
methodology
5.1.1.   Introduction

The baseline estimated
2020 fuel mix, and its associated greenhouse gas emissions, are outlined in
chapter 2. In the context of the evaluation of the effectiveness of the
different policy options, the assessment will focus on how the accuracy of the
supplier and EU level greenhouse gas intensity and the final fuel mix in 2020
may be influenced by the choice of methodology, as well as looking at potential
scenarios on the mix of technologies and tools required to achieve the FQD 6%
greenhouse gas emissions reduction. Any wider environmental, economic and social
impacts in the categories listed below associated with that technology and tool
mix will also be explored. 
In so far as possible,
the economic impacts that the different options may have on the competitiveness
of the domestic EU refinery sector, the additional administrative burden
associated with the implementation of the respected methodologies, and the
overall compliance costs with the FQD reduction target, will be quantified. For
the remaining cases and categories where this has not been possible, the
assessment of the impacts is of a qualitative nature. Further detail can be
found in Annex XI: Assessment methodology.
5.1.2.   Development
of scenarios
The options provide for different possible
levels of disaggregation of information to be provided by fuel suppliers when
reporting on the GHG intensity of the fuels under the FQD. These range from
option B1 which relies on suppliers using a single EU GHG intensity average for
each product, to option E under which suppliers can develop their own specific
carbon intensities. The choice of methodology will influence for each fuel
supplier,
·        
the complexity of the reporting requirements and
associated administrative burden (i.e. less data intensive options require more
easily available aggregated data) ; and
·        
the range of attractive abatement options to
reduce greenhouse gas intensity of fuels supplied (and compliance costs) and
their reported GHG intensity ; 
 Policy option || Additional biofuel blending || Upstream emission reductions || Crude switching || Product switching 
 EU refinery switch feedstock types || EU refinery switch among any crude feedstock || Import products refined from other feedstock types || Import products refined from any crude feedstock 
 Option B1 || ü || ü ||   ||   ||   ||   
 Option C || ü || ü || ü ||   || ü ||   
 Option || D1 || ü || ü ||   || ü ||   || ü 
 D2 || ü || ü ||   || ü ||   || ü 
 Option E || ü || ü || ü || ü || ü || ü 
Table 6: Abatement choices for suppliers
per option included in the assessment
In addition, the number of abatement
choices available is also influenced by the type of methodology, as some tools
(i.e. the possibility to switch to lower carbon fossil fuel feedstocks), would
not be desirable to fuel suppliers under some of the less specific options.
Although electric vehicles as a compliance
measure are available under all policy options, it has not been assessed
further as a realistic option beyond levels in the projected 2020 energy demand
due to the low perceived cost effectiveness compared to alternatives and
associated technological constraints. 
It should also be noted that options related
to switching from one type of road fuel to another (e.g. CNG and LPG over
diesel or petrol) are not considered because the carbon price premium needed to
induce GHG reductions in a given year would not bring about such switching
which generally responds to longer-term changes to vehicle fleets and/or
taxation regimes. 
The role of switching from low to high GHG
savings biofuels may also be a way to help suppliers to comply with the FQD.
Given that this would also be strongly influenced by other variables outside
the scope of this study such as trade tariffs, the proximity of biofuel
production facilities and technical compatibility issues, this option has not
been included in the assessment. In addition, for those policy options in which
the supplier is reporting actual supplier specific intensities[104], any measure that
reduces the GHG intensity of that supplier’s product would be available to the
supplier. This could include for example refinery optimisation or changes to
transport/distribution efficiencies. Such measures are not considered further
here because the measures listed in the table above are considered those likely
to be most attractive to suppliers, and further that refinery emissions
intensity reduction is already covered within the scope of the EU ETS and that
transport/distribution emission reduction projects are likely to affect total
lifecycle intensities only marginally. The emission intensities assumed for
supplier specific emissions methods do not assume any specific refinery emission
savings.

5.1.3.     Assessment of effectiveness

The main measure of
effectiveness of each policy option is the accuracy of the resulting greenhouse
gas intensity estimate for each supplier’s fuel mix and of the overall average
EU emissions of fossil fuels. Upon revisiting the descriptions of the proposed
options in Chapter 4, it is self-evident that options are most accurate when
the greenhouse gas values (default or actual) used in the calculation reflect
as closely as possible, the supplier’s fuel mix. 
In the interest of
measuring the accuracy of each methodology, a comparison was made between the
2020 projected GHG intensity reported for each fuel supplier under each option
against their actual emissions as calculated under option E which is expected
to produce the most accurate results. The second measure of effectiveness
pertains to the accuracy of the policy options to estimate actual average EU
emissions from the aggregated, supplier reported values compared to that based
on EU default values. In both cases, the respective per cent error was
calculated and reported under each option (positive and negative per cent
errors indicates overestimation and underestimation of emissions respectively).
5.1.4.   Assessment of compliance costs
In order to conduct the
assessment of the options described in chapter 4, the estimated available
potential and corresponding pre-tax costs associated with each of the carbon
abatement options have been developed for the Commission[105]. Assuming
that fuel suppliers will be mainly driven by seeking lowest cost in their
choice of abatement option[106],
the estimated changes in fuel mix, the range of options and associated costs
compared to the baseline fuel mix have been calculated and are reported under
each policy option as compliance costs. Moreover, the total size of the CO2
abatement market will determine the ultimate market costs, defined as the
required CO2 abatement at the highest marginal cost. These are also
reported under each option. Further information on the availability and
marginal abatement costs associated with each technology can be found in Annex
XII: Carbon abatement costs and potential (Source: ICF/Vivid Economics). 
In this context, it is noted that the
baseline fuel mix already includes the levels of renewable energy (i.e.
biofuels and electricity) required to achieve the Renewable Energy Directive
targets as reported by the Member States. As such, it is only the additional
carbon abatement effort required above those levels that is being considered in
this impact assessment[107].


5.1.5.     Assessment of administrative costs

The FQD creates new
reporting requirements for fuel suppliers in the European market. The
methodological options described in chapter 4 present different levels of
complexity depending on the level of data disaggregation that is required by
fuel suppliers in reporting the GHG intensity of the fuels they supply on an
annual basis to the relevant public authorities.
In order to evaluate
these costs, the contractors have identified and analysed the potential costs
associated with the monitoring, reporting and verification incurred by the
different policy options. Given that a certain level of reporting requirements
already exist, only the additional actions needed to fill any data gaps
specific to the FQD and the associated costs are reported here. Further
information on the methodology used can be found in Annex
XIII: Monitoring, reporting and verification actions.

5.1.6.     Assessment of competitiveness impacts

The contractors conducted the
competitiveness analysis in accordance with guidance set out by the Commission[108]. In this context, a
number of sectors have been identified as possibly being affected (i.e.
refining industry, fuel traders, biofuel producers, vehicle manufacturers,
public transport and the petrochemical sector) by the FQD and qualitatively
screened accordingly. Following from the results of this screening[109], only the
competitiveness impacts on the refining industry have been further analysed as
impacts on other sectors are not expected to be significant enough to warrant
further investigation.   
With regards to the refining industry, the
analysis of the competitiveness proofing of the policy options under consideration
has been conducted focusing on a number of key aspects and potential resulting
impacts such as,
–    
the ability for
refineries to choose lower over higher intensity crudes and products as a way
to comply with the FQD reductions,
–    
the potential changes
in the mixture of sources of finished and semi-finished diesel and gasoline
imported into Europe
–    
the ability of industry
to pass on any resulting increase of fuel prices, and estimation of impacts on
pump prices (pre-tax), taking into account cost pass-through; 
–    
closure of refineries
to maintain margins in response to expected reductions in demand in Europe;
The question relevant to this impact
assessment is to what extent any additional burden arising from compliance with
article 7a of the FQD may impact the petroleum industry sector, and in
particular EU refineries. In this context, it seems reasonable to assume that
producers will be able to pass through most of the costs to consumers. Based on
a literature review, it seems reasonable to assume a pass through cost rate of
around 90-100% so long as they possess some degree of market power[110].
Moreover, it is worth noting that the implementation of the FQD does not lead
to significant reductions in total fuel consumption from the baseline scenario[111].   
As explained in section 2.6.1.1, given the
limitations on EU supplier data availability despite requests to Member States
and relevant industry associations such as UPEI, it has not been possible to
categorise EU suppliers according to their size in a comprehensive manner,
although some of those classified as fuel traders[112] in the baseline would
be expected to fall under the SME definition. As such, it has not been possible
to determine what proportion of the fuel suppliers in the baseline would fall
under the SME category and whether they would be significant differences in
terms of SME specific impacts by any of the options being considered in this
impact assessment. 
Nevertheless, modelling results indicate
that trade volumes are only marginally impacted as reductions in trade of
fossil fuel are partially offset by an increase in trade of biofuel volumes. In
addition, net decreases in total fuel volumes are broadly equal for refiners
and traders because these are linked to the overall reduction in demand. Since
these effects are too small to produce changes in market structure and since
cost is expected to be passed through almost completely, no significant
differences in the cost of capital (associated with changes in margin
volatility), employment (associated with plant closure or large changes in
output), value added (associated with changes in margins or wages) and capacity
to innovate (associated with profitability) between traders and producers are
expected regardless of the implementation option considered. However, uniform
government reporting requirements tend to have an over-proportionally large
cost burden on smaller players[113].

5.1.7.     ILUC sensitivity scenario 

As explained in
section 2.6.4, on-going discussions on a legislative proposal for mitigating
against indirect land use change emissions may lead to a reduction in the
consumption of biofuels in 2020 which could have significant impacts on the
assessment of the options. To better understand these impacts under the most
extreme option (i.e. the inclusion of the ILUC estimated emissions in the
greenhouse gas emissions performance of biofuels), further analysis has been
conducted and is presented in Annex
XVI: Summary of ILUC sensitivity assessment. 

5.2       Option B1 - Methodology based
on the average default greenhouse gas intensity values by fuel type based on an
EU fuel mix level (“basic reporting approach”).

Option B1 is the option with the simplest
methodology as it only involves disaggregation between the main four fuel types
consumed in the EU (i.e. petrol, diesel/gasoil, liquefied petroleum gas and
compressed natural gas), for which an average default value would be developed.
The lifecycle greenhouse gas emissions attributed to these fuels would be based
on the EU feedstock mix. 
With regards to the abatement options
available to fuel suppliers for complying with the FQD objective, it is worth
noting that this is the only approach that does not allow for switching to
lower GHG intensity fuel feedstocks, or improving the GHG intensity of the
fuels supplied through actions other than upstream emission reductions. 
The modelled fuel mix to 2020 under this
approach and corresponding abatement measures are shown in Annex
XVII: Projected road fuel mix 2020 for each option (non-ILUC scenario) (Source:
Vivid Economics). The key changes compared to the
baseline should be interpreted with caution as these are very small in the
context of the overall energy demand. These are,
- a negligible increase in the consumption
of petrol (~5PJ, 0.05%) against fossil diesel, given that it has a better
greenhouse gas emissions performance than fossil diesel. 
- in addition, a small amount of fossil
diesel (~32PJ, 0.29%) is replaced by biodiesel from waste (i.e. used cooking
oil or animal fats), which provides a small contribution towards the required
greenhouse gas emissions reductions (2.5Mt CO2). 
- there are no changes in the feedstock mix
with consumption of unconventional fuels being unaffected.  
- the bulk of the abatement measures come
in the form of reductions in upstream emissions (7.8Mt CO2).
- a negligible reduction in total transport
fuel demand (<0.1%).

5.2.1.     Effectiveness in achieving policy objective

This approach will
provide for the least degree of accuracy in its reporting of the
greenhouse gas intensity associated with the fuels being supplied. This is
because given the simplicity of the methodology (i.e. 4 broad fuel categories),
neither the variations in GHG intensity between (i.e. conventional vs.
unconventional) or within (i.e. higher intensity conventional vs. lower
intensity conventional) broad feedstock categories would be captured[114]. In addition, no
opportunity for suppliers to report the actual values of the fuels supplied would
be allowed[115].
This yields a percentage error ranging between -1.6 to 0.7 percentage points of
the FQD target in the reporting of the GHG intensity of the fuel put in the
market by suppliers compared to their actual values, a significant share in the
context of the overall 6% target (a potential underestimation of emissions up
to 27%)[116].
In this context, it is worth noting that the actual GHG intensity of fuels
supplied in the Eastern and Northern European countries, that are expected to
be lower than the EU average, would be overestimated, and that of those in the
Southern European countries underestimated. 
Figure 4: Assessment of option B1’s
reporting accuracy at fuel supplier level 
Despite the significant inaccuracies in the
reporting of the GHG intensity at fuel supplier level, the reported average EU
emissions may not be affected as long as the average default values used are
based on robust data and capture variations in the feedstock mix in a timely
manner. However, the fact that this option does not lead to the collection of
real detailed market information by suppliers neither for reporting purposes
nor for checking of compliance in 2020, poses a risk with regards to the
accuracy of the reported average EU emissions as well as for the accuracy of
the development of the fossil fuel comparator values. This is because, the best
available data at EU level[117]
is based on voluntary provided data by members of the industry organization Oil
and Gas Producers (OGP). Historically, the data reflected approximately a
limited 30% of the crude oil refined in the EU. However, this system provides
no information on imported products, which are expected to increase. In
addition, the bulk of unconventional sources entering the European market are
expected to be refined outside the EU and so this method will provide poor
coverage, unless the reporting mechanism is significantly strengthened. 
This approach is also
the least consistent with the biofuels methodology, under which those
suppliers blending biofuels can make use of conservative default greenhouse gas
emission values disaggregated by feedstock and technological pathway, and best
performing producers are given the opportunity to provide actual values over
all steps of the value chain. Moreover, this option would not require fuel
suppliers to put together any type of chain of custody mechanism, unlike for
biofuel producers, as the GHG intensity of the fuels supplied would be based on
the EU average fuel mix and not specific to the fuel consignment. 
These issues around accuracy in option B1
are balanced by the fact that this methodology is least cost and would enable
Member States to verify compliance by fuel suppliers with their obligation in
the simplest possible way. This is because this methodology only relies
on one piece of data from suppliers, quantities of product supplied, which is
the most straightforward to verify. Validation of correctly applied factors
(i.e. default unit GHG intensities) could also be undertaken but is
straightforward and would not entail excessive administrative burden. The risk
of fraud is therefore considered to be low.

5.2.2.     Environmental impacts 

In so far as this
approach would lead to reductions in the consumption of fossil fuels[118], increased waste
biodiesel and increased reductions in the emissions associated from flaring and
venting as outlined above, it will lead to positive environmental impacts
compared to the baseline scenario. In addition, as the level of mitigation
effort required to achieve the 6% target is directly related to the accuracy of
each methodology, there is a risk that this approach could lead to less
mitigation actions being undertaken, given its lack of real monitoring of
market information and that the share of imported products and unconventional
sources is projected to increase[119].

On the other hand, the
lack of differentiation between fossil fuel feedstocks neither discourages the
consumption of more resource intense and more polluting unconventional sources,
nor rewards those suppliers that have invested in lowering the carbon footprint
associated with the production of their fuels as they would not be allowed to
use actual calculations. The lack of such an incentive runs counter to the
achievement of the key general objective of the Directive, i.e. the achievement
of the 6% reduction target by fuel suppliers.    

5.2.3.     Economic impacts

With regards to
additional costs for suppliers to comply with the FQD, the additional
reductions required in upstream emissions and waste biodiesel result in
compliance costs of 6 million euros. Given the simplicity of the methodology,
and particularly the lack of a traceability mechanism needing to be
implemented, this approach is expected to lead to the lowest administrative
costs estimated to range between 2 to 3 million euros[120]. While these costs
reflect total administrative costs to suppliers and national authorities, the
estimated burden on national authorities is negligible. 
In determining the
overall impacts on pump prices, it is important to consider that the market costs
will be higher than those reported as compliance costs above. This is because
in reality, the actual market impact will be closer to that of the marginal
abatement cost under each option being applied to the whole of amount of CO2
needed to be abated[121].
In this context, option B1 is reported to lead to increased market costs of 79
million euros, or estimated pump price increases up to 0.03 cents per litre
(0.04%)[122].
These costs are considered to be too small to lead to any significant changes
in market structure, value added, capacity to innovate or competitiveness of EU
refiners vis a vis international competitors.    
Trade in crude oil and
petroleum products would be largely unaffected compared to the baseline, with
only a very small decrease of refined products being imported from the Former
Soviet Union (~11PJ, 0.10%). The small increased amount of biofuel used may
also lead to a decrease in the amount of products being refined in the EU
(~32PJ, 0.29%)[123].
As a result, impacts on security of supply are also expected to be small,
although it is worth noting that the share of imports in the final mix may
increase under this option[124].
As the ability for fuel suppliers to switch from higher to lower carbon
intensity fossil fuel feedstocks is not a compliance option available to fuel
suppliers, this option does not lead to any changes in the consumption or trade
of unconventional fossil fuels in the EU. As such, the risk of a WTO challenge
is low.    

5.2.4.     Social impacts

The market costs
outlined above are considered to be too small to lead to any significant
changes in market structure. As they are assumed to be passed almost in full to
consumers, no significant differences in employment are expected[125]. 
In so far as this
approach would lead to reductions in the consumption of fossil fuels, and
increased reductions in the emissions associated from flaring and venting as
outlined above, it will lead to positive air quality impacts compared to the
baseline scenario, due to reduced emissions of particulate matter and methane),
and thus positive effects on public health.

5.3       Option C - Methodology based on
the disaggregated average default greenhouse gas intensity values by main
feedstock types (“2011 proposal”)

Option C is the option
described in the proposal submitted to the Member States in 2011. Under this
option, the GHG intensity of all feedstocks used in the EU would be reported
separately (i.e. petrol and diesel/gasoil from oil, natural bitumen, oil shale,
coal to liquid, gaseous fuels and electricity, etc.) based on default values
derived from public data. 
This option would
require differentiated reporting by fossil fuel suppliers of the specific
fossil fuel feedstocks they supply. Therefore, differences between suppliers
according to the feedstocks that are included in their fuel mix would be
reported. 
The modelled fuel mix to 2020 under this
approach and corresponding abatement measures are shown in Annex
XVII: Projected road fuel mix 2020 for each option (non-ILUC scenario) (Source:
Vivid Economics). The key changes compared to the
baseline should be interpreted with caution as these are very small in the
context of the overall energy demand. These are,
- a negligible increase in the consumption
of petrol (~7PJ, 0.06%) against fossil diesel, given that it has a better
greenhouse gas emissions performance than fossil diesel. 
- in addition, a small amount of fossil
diesel (~32PJ, 0.29%) is replaced by biodiesel from waste (i.e. used cooking
oil or animal fats), which provides a small contribution towards the required
greenhouse gas emissions reductions (2.5Mt CO2). 
- the bulk of the reduction in consumption
of fossil diesel comes from unconventional fuel categories, mainly from natural
bitumen, but also from gas to liquid and oil shale (total of~38PJ, 0.35%).  
- the bulk of the abatement measures come
in the form of reductions in upstream emissions (7.8Mt CO2). 
- the role of crude and product switching
is limited, given the technical constraints in refineries driven by fuel
specifications and relatively higher carbon abatement costs compared to the
other technologies available (i.e. biofuels and upstream emission reductions).
As such, they only provide a small contribution (0.5 Mt CO2). 
- a negligible reduction in total transport
fuel demand (<0.1%).

5.3.1.     Effectiveness in achieving policy objectives

This approach provides
for a high degree of accuracy in its reporting of the greenhouse gas
intensity associated with the fuels being supplied. This is because the variations
in GHG intensity between feedstock categories (i.e. conventional versus
unconventional; and between unconventional feedstocks) would be captured. In
addition, the opportunity for suppliers of high intensity unconventional fuels
to report on actual values would enhance the accuracy of this option and would
provide for an incentive to improve production processes so as to reduce their
greenhouse gas intensity. However, no differentiation within the average GHG
intensity crude categories (i.e. conventional diesel high intensity and
conventional diesel low intensity) would be reflected. This yields a small
percentage error ranging between -0.1 to 0.2 percentage points of the FQD
target with regards to reporting the GHG intensity of fuel suppliers[126]. In addition, the
collection of real detailed market information at feedstock level by suppliers
for reporting purposes and for checking of compliance in 2020, helps ensuring
that the reported average EU emissions as well as the fossil fuel comparator
values remain accurate compared to the actual emissions.   
This approach is partly
consistent with the biofuels methodology, in so far that suppliers can make
use of default greenhouse gas emission values disaggregated by fossil feedstock
types and technological pathways, which, as is the case for biofuels now, is
expected to become further disaggregated over time, although not all suppliers
are given the opportunity to provide actual values if they wish to. Moreover,
this option requires fuel suppliers to put together a type of traceability
mechanism, likely that in place for biofuel producers, to report on the GHG
intensity of the fuel consignments being supplied.  
Figure 5:
Assessment of option's C reporting accuracy at fuel supplier level
This methodology would require
additional data collection efforts. This is because suppliers would need to
split their fuels across feedstocks using feedstock mix data from the
refineries of the origin of the products. In addition, refineries generally
already track and report most of the required data (refineries inside[127] and outside the EU),
but do not currently apportion products in this fashion. Also, the
categorisation of feedstocks in this manner is not currently undertaken, and
feedstock origin details are not normally retained along supply chains of fuel
market traders.
As such, Member States verification of
compliance by fuel suppliers with their obligation would be of a medium
complexity. The method relies on two types of data from suppliers: (i)
quantities (MJ) per product, and (ii) those quantities split according to
categories of feedstock. Since the quantities of products supplied also form
entries in the excise duty systems of Member States, this part is already
verifiable and presents a low risk of fraud. The data concerning the split of
refinery feedstock categories is not readily available data: refineries know
their own crudes that they are using as this information is fundamental to
refinery operations, but data on the feedstock origins of products once traded
are not readily available to suppliers. Therefore the current reporting
practices would need bolstering in order to ensure scrutiny and verification so
as to avoid fraud. Validation of correctly applied factors (default unit GHG
intensities) could also be undertaken and would be straightforward.

5.3.2.     Environmental impacts 

Through reductions in
the consumption of fossil fuels, increased waste biodiesel and increased
reductions in the emissions associated from flaring and venting as outlined
above, this option will lead to positive environmental impacts compared to the
baseline scenario. 
In addition, positive
environmental impacts are enhanced by the differentiation between fossil fuel
feedstocks also leading to a reduction in the consumption in the EU of more
resource intense and more polluting unconventional sources, such as natural
bitumen and oil shale[128].
Suppliers of unconventional sources that have invested in lowering the carbon
footprint associated with the production of their fuels could also be rewarded
by being allowed to use actual calculations.     

5.3.3.     Economic impacts

The measures needed to
be put in place by suppliers to comply with the FQD under this option, i.e. the
additional reductions required in upstream emissions, waste biodiesel and product
and crude switching would result in costs of around 8 million euros. In
addition, the requirement for disaggregation of fuel mix into feedstock types
and the need for a traceability mechanism under this approach, gives rise to
moderate total additional costs to suppliers and national authorities ranging
between 15 and 16 million euros annually[129].
While these costs reflect total administrative costs to suppliers and national
authorities, the estimated burden on national authorities is negligible. With
regards to the impacts on pump prices, this option is reported to lead to
increased market costs of 79 million euros, or pump price increases of around
0.03 cents per litre (0.04%)[130].
These costs are considered to be too small to lead to any significant changes
in market structure, value added, capacity to innovate or competitiveness of EU
refiners vs international competitors.   
Trade in crude oil and
petroleum products would not be impacted significantly compared to the
baseline, although a small decrease in the level of imports of refined products
from natural bitumen from North America (~22PJ, 0.20%), gas to liquid from
Africa (~8PJ, 0.07%), oil shale (~6PJ, 0.06%) and conventional crude oil from
Former Soviet Union (~6PJ, 0.06%) would be expected. The increased amount of
biofuel used partially contributes to a small decrease in the amount of
products being refined in the EU (~4PJ, 0.04%)[131]. 
It is worth noting that
since the consumption of unconventional sources is discouraged under this
approach and the refining capacity for processing these is currently outside
the EU, the overall decrease in diesel consumption has a larger impact on
imports of refined products than on EU refineries[132]. As such, overall
security of supply may be slightly improved under this option. However, such
measures may impact investments in certain EU countries, such as Estonia and Spain, where actions plans for upgrading refineries to be able to process unconventional
sources are planned or underway. It should be noted that investments made to
facilitate processing oil sands may not be impacted as oil sands are
interchangeable with other heavy crudes.
In addition, Canada has raised concerns about the potential compatibility of this approach with WTO
rules with regards to a discriminatory treatment of unconventional oil sources
and so this methodology may be challenged at the WTO. In this context, legal
analysis conducted by the Commission's legal services in 2011 provided
reassurance that the methodology under this option, as regards natural bitumen
feedstocks, may be defended in case of a challenge before the WTO adjudicatory
bodies.        

5.3.4.     Social impacts

The market costs
outlined above are considered to be too small to lead to any significant
changes in market structure. As they are assumed to be passed almost in full to
consumers, no significant differences in employment are expected. 
In so far as this
approach would lead to reductions in the consumption of fossil fuels, and
increased reductions in the emissions associated from flaring and venting as
outlined above, it will lead to positive air quality impacts compared to the
baseline scenario. These are enhanced by the reduction in the consumption of
more polluting unconventional sources, such as natural bitumen and oil shale.

5.4       Option D - Methodology based on
disaggregated default greenhouse gas intensity, based on average (D1) or
conservative (D2) values, while allowing suppliers to report actual values
(“hybrid approach”)

Under this option,
suppliers’ compliance would be based on the GHG impact of all feedstocks used
in the EU (e.g., petrol and diesel/gasoil from oil, natural bitumen, oil shale,
coal to liquid, gaseous fuel and electric energy, etc.). Suppliers would report
default values based on average (option D1) or conservative, higher than
average, GHG intensity values (D2). These options would require reporting of
the origin of fossil fuel feedstocks. However, this information will not
influence suppliers’ compliance with the reduction target. Alternatively, suppliers
may wish to provide actual values. This methodology implies the same data
collection and traceability requirements as option C, by default the compliance
effort of option B1, and additional efforts for those suppliers choosing to
report actual values. 
The projected fuel mix to 2020 has only
been modelled for option D1, given that the impacts of option D2 would be
determined by the level of conservatism under which the default values would be
set and the amount of suppliers actually opting to report actual values.
Although this is unknown, the impacts of option D2 are expected to be close to
option D1. In any case, the quantification of impacts for option E, where all
suppliers are required to report actual values, should be seen as a very
extreme case of option D2. 
Any option where a supplier may choose the
lowest value between a provided default value and a self-calculated actual
value inherently leads to an underestimate of the EU average greenhouse gas
intensity and skewed results. Hence it is only certain that the resulting
impacts will fall somewhere between those presented for option C and option E.
More details are shown in Annex
XVII: Projected road fuel mix 2020 for each option (non-ILUC scenario) (Source:
Vivid Economics). 
The key changes compared to the baseline
should be interpreted with caution as these are very small in the context of
the overall energy demand. These are,
- a negligible increase in the consumption
of petrol (~5PJ, 0.05%) against fossil diesel, given that it has a better
greenhouse gas emissions performance than fossil diesel. 
- in addition, a small amount of fossil
diesel (~18PJ, 0.2%) is replaced by biodiesel from waste (i.e. used cooking oil
or animal fats), which provides a small contribution towards the required
greenhouse gas emissions reductions (1.6Mt CO2). 
- the bulk of the reduction in consumption
of fossil diesel comes from unconventional fuel categories including natural
bitumen, gas to liquid and oil shale (~30PJ, 0.3%).  
- the bulk of the abatement measures come
in the form of reductions in upstream emissions (7.8Mt CO2). 
- the role of crude and product switching
is limited, given the technical constraints in refineries driven by fuel
specifications and relatively higher carbon abatement costs compared to the
other technologies available (i.e. biofuels and upstream emission reductions).
As such, they only provide a small contribution (0.5 Mt CO2). 
- a negligible reduction in total transport
fuel demand (<0.1%).

5.4.1.     Effectiveness in achieving policy objectives

This approach provides
for a modest degree of accuracy in its reporting of the greenhouse gas
intensity associated with the fuels being supplied at supplier level. This is
because the variations in GHG intensity between feedstock categories (i.e.
conventional vs unconventional; and between unconventional feedstocks) would
not be captured. On the one hand, the opportunity for all suppliers to report
actual values would enhance the accuracy of this option as it will encourage
differentiation within the average GHG intensity crude categories (i.e.
conventional diesel high intensity and conventional diesel low intensity). On
the other hand, those suppliers whose fuel intensity is above such a default
value would effectively be given a lower value, which poses a risk that the EU
average values are underestimated unless these values are regularly updated[133]. In this context,
option D2 would be expected to provide a more accurate representation than
option D1 as the amount of suppliers opting out of the use of those default
values and instead using actual values should be higher.  
Figure 6: Assessment of option D1
reporting accuracy at fuel supplier level
This yields a
percentage error ranging between 0 to -1.6 percentage points of the FQD target
with regards to reporting the GHG intensity of fuel suppliers[134]. However, the
reported average EU emissions could be underestimated by an error of around -1%
in the case of D1[135]
as those suppliers with higher carbon intensities are expected to use average
default values as these underestimate real emissions. This effect could be
partially mitigated by either providing more frequent updates of such default
values according to the actual data being reported or using conservative default
values under D2. With regards to providing useful data for the purposes of the
fossil fuel comparator, this option has some positive effects in so far as it
increases collection of real detailed market information at feedstock level and
in certain cases of actual values by suppliers. On the other hand, D1 and to a
lesser extent D2 may lead to underestimation of the EU average value as
explained above.   
This approach is broadly
consistent with the biofuels methodology in so far that suppliers can make
use of default greenhouse gas emission values or provide actual values if they
wish to. This is particularly relevant for option D2, which in line with the
biofuel methodology as it includes conservative default values in order to
incentivise more suppliers to report actual emissions. Moreover, this option
requires fuel suppliers to put together a type of traceability mechanism, like
that in place for biofuel producers, to report on the GHG intensity of the fuel
consignments being supplied.  
This methodology would require reporting of
the origin of fossil fuel feed stocks. However, this information will not
influence suppliers’ compliance with the reduction target. This methodology
implies the same data collection and traceability requirements as option C and the
compliance effort of option B1.
As such, Member States verification of compliance by
fuel suppliers with their obligation would be of a medium complexity for those
suppliers choosing to use default values. 
For suppliers that choose to provide
their own actual values, verification by the Member States would be more
complex. This is because verification processes
would be necessary for any measured data or life cycle estimates generated by
suppliers, and the level of rigour required by verification processes of these
suppliers would need to be higher than that for those choosing to use default
values due to the additional complexity of the calculations. The additional
risk of fraud would therefore be higher.

5.4.2.     Environmental impacts 

Through reductions in
the consumption of fossil fuels, increased waste biodiesel and increased
reductions in the emissions associated from flaring and venting as outlined
above, option D1, and to a greater extent option D2, would be expected to lead
to positive environmental impacts compared to the baseline scenario. In
addition, differentiation between fossil fuel feedstocks also leads to enhanced
benefits as a result in reductions in EU consumption of more resource intense
and more polluting unconventional sources, such as natural bitumen and oil
shale[136].

In addition, the
ability to provide actual values would be expected to lead to suppliers of both
conventional and unconventional sources that have invested in lowering the
carbon footprint associated with the production of their fuels to be rewarded
by being allowed to use actual calculations. Option D2 is likely to incentivise
this type of behaviour to a greater level than option D1 since more suppliers
would have a lower GHG intensity than that of the default value that would be
provided.     

5.4.3.     Economic impacts

The measures needed to
be put in place by suppliers to comply with the FQD under this option, i.e. the
additional reductions required in upstream emissions, waste biodiesel and
product and crude switching would result in costs of around 1 million euros for
option D1, and from 1 to 8 million euros[137]
for option D2. In addition, the requirement for disaggregation of fuel mix into
feedstock types, the need for a traceability mechanism under this approach, and
the increasing number of suppliers expected to report actual emission values,
gives rise to moderate total additional costs ranging from 18 to 28 million
euros under D1 and up to 31 million euros under option D2[138]. While these costs
reflect total administrative costs to suppliers and national authorities, the
estimated burden on national authorities is negligible.
With regards to the
impacts on pump prices, this option is reported to lead to increased market
costs between 59[139]
to 79 million euros, or pump price increases of 0.02-0.03 euro cents per litre
(0.04%)[140].
These costs are considered to be too small to lead to any significant changes
in market structure, value added, capacity to innovate or competitiveness of EU
refiners versus international competitors.   
For option D1, trade in
crude oil and petroleum products would not be impacted significantly compared
to the baseline, although a decrease in the level of imports of refined
products from natural bitumen from North America (~18PJ, 0.16%), gas to liquid
from Africa (~6PJ, 0.06%) and oil shale (~4PJ, 0.04%) would be expected. The
increased amount of biofuel used partially contributes to a very small decrease
in the amount of crude oil being refined in the EU (~1PJ, 0.01%)[141]. It is worth noting
that since the consumption of unconventional sources is discouraged under this
approach and the refining capacity for processing these is currently outside
the EU, the overall decrease in diesel consumption has a larger impact on
imports of refined products than EU refineries. Impacts for option D2 would be
somewhere between these described here and that under option E. As such,
security of supply may be slightly improved under this option. However, such
measures may impacts investments in certain EU countries, and raise the same
issues in relation to WTO rules as referred for option C (see 5.3.2.).       

5.4.4.     Social impacts

The market costs
outlined above are considered to be too small to lead to any significant
changes in market structure. As they are assumed to be passed almost in full to
consumers, no significant differences in employment are expected. 
In so far as this
approach would lead to reductions in the consumption of fossil fuels, and
increased reductions in the emissions associated from flaring and venting as
outlined above, it will lead to positive air quality impacts compared to the
baseline scenario. These are enhanced by the reduction in the consumption of
more polluting unconventional sources, such as natural bitumen and oil shale.

5.5       Option E - Methodology based
upon separate greenhouse gas intensities for individual categories of
feedstocks ("complete differentiation") 

This option would require upstream
greenhouse gas emissions estimates for individual categories of feedstocks
within those types described under option C to be calculated and reported (e.g.
field level, trade name, MCON, etc.) by suppliers. As actual disaggregated data
may not necessarily be available for all fuel types and to all suppliers at the
moment, this option may be challenging in its implementation as the option to
use instead default values is not available to suppliers. 
The modelled fuel mix to 2020 under this
approach and corresponding abatement measures are shown in Annex
XVII: Projected road fuel mix 2020 for each option (non-ILUC scenario) (Source:
Vivid Economics). The key changes compared to the
baseline should be interpreted with caution as these are very small in the
context of the overall energy demand. These are,
- a negligible increase in the consumption
of petrol (~6PJ, 0.06%) against fossil diesel, given that it has a better
greenhouse gas emissions performance than fossil diesel. 
- in addition, a small amount of fossil
diesel (~32PJ, 0.29%) is replaced by biodiesel from waste (i.e. used cooking
oil or animal fats), which provides a small contribution towards the required
greenhouse gas emissions reductions (2.5Mt CO2). 
- the bulk of the reduction in consumption
of fossil diesel comes from unconventional fuel categories including natural
bitumen, gas to liquid and oil shale (~35PJ, 0.32%).  
- the bulk of the abatement measures come
in the form of reductions in upstream emissions (7.8Mt CO2). 
- the role of crude and product switching
is limited, given the technical constraints in refineries driven by fuel
specifications and relatively higher carbon abatement costs compared to the
other technologies available (i.e. biofuels and upstream emission reductions).
As such, they only provide a small contribution (0.5 Mt CO2). 
- a negligible reduction in total transport
fuel demand (<0.1%).

5.5.1.     Effectiveness in achieving policy objectives

This approach provides
for the highest degree of accuracy in its reporting of the greenhouse
gas intensity associated with the fuels being supplied as all suppliers are
required to report actual values. Therefore, all differences between and within
fuel feedstock categories would be captured with no error being derived from
the reporting mechanism itself. In addition, the collection of real detailed
market information at fuel consignment level by suppliers makes this option
being the most accurate in the context of updating the fossil fuel comparator
values.   
This approach is inconsistent
with the biofuels methodology and much more burdensome, in so far that
suppliers cannot make use of default greenhouse gas emission values but must
provide actual values at all times. Moreover, this option requires fuel
suppliers to put together a more complex traceability mechanism than that in
place for biofuel producers.  
As suppliers are requested to provide
their own actual values, verification by the Member States would be complex. Verification
of measured data would be necessary and extensive if the data used has not been
verified for other purposes. In this context, while the validation of lifecycle
emission models available to EU suppliers would be possible, it would be
challenging to reliably verify measured data for feedstocks originating from
outside the EU or North America, which represent over three quarters of all
feedstocks consumed in the EU. As such, the implementation of this option may
require an interim period where further disaggregated data can be developed or
gathered to ensure full coverage of all fuels. The potential for fraud with
this option is higher than for other options[142].

5.5.2.     Environmental impacts 

Through reductions in
the consumption of fossil fuels, increased waste biodiesel and increased
reductions in the emissions associated from flaring and venting as outlined
above, it will lead to positive environmental impacts compared to the baseline
scenario. In addition, full differentiation between fossil fuel feedstocks also
leads to a reduction in the consumption of more resource intense and more
polluting unconventional sources, such as natural bitumen. All suppliers would
now be required to report actual values, and so both those supplying high
carbon conventional sources, who may under other options resort to a default
value, and those using unconventional sources, would be very strongly
incentivised to take action.     

5.5.3.     Economic impacts

The measures needed to
be put in place by suppliers to comply with the FQD under this option, i.e. the
additional reductions required in upstream emissions, waste biodiesel and
product and crude switching would result in costs of around 8 million euros. In
addition, the requirement for full disaggregation of fuel mix and the need for
a more complex traceability mechanism under this approach, gives rise to the
highest total administrative costs, with costs ranging between 21 and 42
million euros annually[143].
While these costs reflect total administrative costs to suppliers and national
authorities, the estimated burden on national authorities is much smaller.
With regards to the
impacts on pump prices, this option is reported to lead to increased market
costs of 79 million euros, or pump price increases of 0.04 cents per litre
(0.06%)[144].
These costs are considered to be too small to lead to any significant changes
in market structure, value added, capacity to innovate or competitiveness of EU
refiners versus international competitors.   
Trade in crude oil and
petroleum products would not be impacted significantly compared to the
baseline, although a decrease in the level of imports of refined products from
natural bitumen from North America (~21PJ, 0.19%), gas to liquid from Africa
(~8PJ, 0.07%), oil shale (~4PJ, 0.04%) and conventional crude oil from Former
Soviet Union (~3PJ, 0.03%) would be expected. The increased amount of biofuel
used partially contributes to a small decrease in the amount of conventional
crude oil being refined in the EU (~8PJ, 0.07%)[145]. It is worth noting
that since the consumption of unconventional sources is discouraged under this
approach and the refining capacity for processing these is currently outside
the EU, the overall decrease in diesel consumption has a larger impact on
imports of refined products than EU refineries. As such, security of supply may
be slightly improved under this option. However, such measures may impact
investments in certain EU countries, such as Estonia and Spain, where plans for upgrading refineries to be able to process unconventional sources are planned
or underway.
With regards to WTO rules, this approach is
seen by some Member States and certain oil exporting third countries as the
fairest approach as it is based on full differentiation of all fuels. However,
it may require an interim period where further disaggregated data can be
developed or gathered.  

5.4.4.     Social impacts

The market costs outlined
above are considered to be too small to lead to any significant changes in
market structure. As they are assumed to be passed almost in full to consumers,
no significant differences in employment are expected. 
In so far as this
approach would lead to reductions in the consumption of fossil fuels, and
increased reductions in the emissions associated from flaring and venting as
outlined above, it will lead to positive air quality impacts compared to the
baseline scenario. These are enhanced by the reduction in the consumption of
more polluting unconventional sources, such as natural bitumen and oil shale.

6.                      
 Section: comparison of the
options

The table below summarises the main
issues related to the different options. 
 Option B1 || Effectiveness || Other 
 Least degree of accuracy for reporting GHG intensity of fuel suppliers (-1.6 to 0.7 p.p off FQD target). GHG intensity of fuels supplied in the Eastern and Northern European countries being overestimated while that of Southern European countries is underestimated. Poses risks reported average EU emissions are less accurate as no real market information is collected by suppliers. Least consistent with biofuel methodology. Simplest implementation and verification process by Member States as based on existing reporting requirements. || Lowest annual administrative costs (€2-3 m). Abatement 2020 related market costs (€79m). Negligible pump price increases (0.04% or 0.03 cents per litre). Environmental gains from increased waste biofuel use and upstream emission reductions. Simplest reporting arrangements Lowest level of EU refining and largest share of imports. No significant competitiveness impacts on EU refineries.   
 Option C || High accuracy for reporting GHG intensity of fuel suppliers (-0.1 to 0.2 p.p. of FQD target). Reported average EU emissions accurate. Partly consistent with biofuel methodology. Implementation and verification processes of medium complexity as additional information would need to be collected. || Environmental gains from increased waste biofuel use and upstream emission reductions, and largest reductions of unconventional sources consumption. Annual administrative costs (€15-16m). Abatement 2020 related market costs (€79m). Negligible pump price increases (0.04% or 0.03 cents per litre). No significant competitiveness impacts on EU refineries. It may impact planned or existing investments for upgrading refineries to process unconventional oil. Incentives for downstream emission reductions only to suppliers of products from high intensity crudes. Manageable risk of WTO challenge 
 Option D1-D2 || Modest accuracy for reporting GHG intensity of fuel suppliers (0 to -1.6 p.p. of FQD target). Risk of underestimation of average EU emissions reported from D1 (-1 pp FQD) and to a lesser extent from D2. Southern European countries GHG intensity underestimated. D2, and to a lesser extent D1, fully consistent with biofuel methodology. Implementation and verification processes of is more complex as additional information would need to be collected on methodologies used for actual value reporting . || Environmental gains from increased waste biofuel use and upstream emission reductions, and reductions of unconventional sources consumption. Underestimation of EU average may lead to less abatement tools required (i.e. biofuels), and therefore lowest overall costs for D1. Annual administrative costs (€18-28m). Abatement 2020 related market costs (€59-79m). Negligible pump price increases (0.04% or 0.02-0.03 cents per litre). No significant competitiveness impacts on EU refineries.  It may impact planned or existing investments for upgrading refineries to process unconventional oil. Incentives for downstream emission reductions to all suppliers. Manageable risk of WTO challenge 
 Option E || Most accurate option for reporting of both GHG intensity of fuel suppliers and EU average. Inconsistent with biofuels methodology. Implementation and verification processes of high complexity as significant additional information would need to be collected. High risk of fraud. || Environmental gains from increased waste biofuel use and upstream emission reductions, and reductions of unconventional sources consumption. Annual administrative costs (€21-42m). Abatement 2020 related market costs (€79m). Negligible pump price increases (0.06% or 0.04 cents per litre). No significant competitiveness impacts on EU refineries.  It may impact planned or existing investments for upgrading refineries to process unconventional oil. Incentives for downstream emission reductions to all suppliers. 

7.                      
 Section: conclusion

In conclusion the choice of
methodology is critical in determining the accuracy of the reported carbon
intensity of the fuels being supplied. Some methodologies lead to a
underestimation and/or overestimation of the GHG intensity of fuels at the
supplier level. Options D1 and D2 tend to also underestimate the GHG intensity
of fuels at the EU level. Inaccurate reporting can partly undermine the overall
ambition of the FQD and affect the way the burden is shared amongst fuel
suppliers.
The options that lead to a further
level of disaggregation than simply fuel type (i.e. feedstock and fuel
consignment level) are more effective in encouraging consumption of lower GHG
intensity and less polluting fuels. These yield positive results with regards
to environmental impacts. Indirectly, this tends to lead to small reductions in
imported products as crudes sourced by EU refineries tend to present lower
carbon intensities. 
There is little variation in terms
of economic costs with regards to the different options although some differences
in administrative and compliance costs have been found. As the differences
between the options represent very low overall costs, they are not considered
to be significant in terms of economic or competitiveness impacts for fuel
suppliers, in contrast to industry claims to the contrary. Reductions in
upstream emissions and increased biofuel blending deliver the bulk of the
additional reductions needed to achieve the FQD target under all options. The
possibility for suppliers to replace higher with lower carbon intense fuels
plays a limited role in achieving the mandated greenhouse gas emission
reductions under those options where this abatement option is allowed. 
Where suppliers can choose between
the reporting of their actual GHG intensity values or a default value being
provided there is a risk that suppliers of high intensity crudes could profit
from this flexibility unless such default values are set conservatively. 
Theoretically
it may be desirable to encourage suppliers to report the actual emissions
associated with the production of their fuels as a way to promote innovation
and reward investments in improving their GHG intensity beyond business as
usual. However in practice, despite significant improvements in the development
of data inventories worldwide, it seems that major gaps remain for the
production of fuels in certain regions. As such, the
implementation of option E may require more time so that further disaggregated
data can be developed or gathered to ensure full coverage of all fuels.
B1 leads to the
simplest implementation and verification mechanism given that it does not
require any additional data collection. B1 also comes with the least
administrative costs. However B1 yields certain inaccuracies in terms of
reporting GHG intensity at supplier level and poses some risks in reporting the
EU average, as the best available data presents a low coverage of the market,
does not cover imported products and no real market information is collected by
suppliers under this option. Option B1 yields a relatively worse environmental
performance. In contrast, options C, D1 and D2 are slightly higher in their
administrative costs and are similar in terms of providing a more accurate
methodology and present positive environmental impacts, although D2 is more
burdensome. 
In the hybrid
option(s)  D suppliers would need to provide their own actual GHG intensity
calculation and so would need to rely on measurement or estimation methods, and
while limitations on data availability exist. In conclusion, there would appear
to be a series of issues that finely balance the choice between options C, D1,
D2 and B1. The option B1 approach is expected to lead to the lowest
administrative costs. While option E is attractive as potentially more
accurate, it would be difficult to implement this option in the short term but
possible by 2020. That is why option B1 is preferred: Average default GHG
values by fuel type (petrol/diesel) based on an EU fuel mix (“basic reporting
approach”)     

8.                      
 Section: monitoring and evaluation 
8.1.      Core indicators of progress 

The
core indicators of progress are linked to the evolution of the average road
fuel mix in the EU and associated mitigation actions. They cover data relating
to:
•
fuel supplied in road transport in the EU, including volumes, origin, place of
purchase and life-cycle greenhouse gas emissions;
•
progress made towards achieving the required greenhouse gas emissions reduction
target, and relevant mitigation actions, including shares and types of biofuels
placed on the market, renewable electricity, reductions in upstream emissions
associated with the production of fossil fuels, etc. 

8.2.      Monitoring arrangements

The
Commission will, building on the data to be provided by fuel suppliers to Member State authorities in their annual fuel quality reports and gathering any additional
information as necessary[146], monitor, 
(a)    the accuracy and reliability of the monitoring and reporting of
fossil fuel greenhouse gas intensity;
(b)   the effectiveness of the adopted fossil fuel methodology under
Article 7a of Directive 98/70/EC to incentivise reductions in the greenhouse
gas intensity of road fuels through increased biofuel blending and reductions
in upstream emissions;
(c)    changes in the EU refinery sector and supply of petroleum feedstocks
to the EU 
(d)   the functioning of the reporting requirements associated with the
adopted fossil fuel methodology and associated administrative burden on
industry, including SMEs; 
(e)    developments in the methods and data available to fuel suppliers for
the determination of the greenhouse gas emissions intensity of the fuels they
supply at further levels of disaggregation; 
(f)    the appropriateness of the default greenhouse gas intensity values
in this Directive, and update these in line with the latest technical and scientific
information if necessary.
These
arrangements will be reviewed as foreseen in the resulting legislation.

9.                      
Glossary

Baseline =
projection of fossil fuels consumption in EU in 2020. The associated greenhouse
gas emissions are used as basis to understand the capacity of reaching the
target of 6% reduction of greenhouse gas emission in the transport sector in
2020.
Biodiesel =
oil-based biofuels typically produced from vegetable and animal fats, such as
rapeseed oil and tallow, and used as a diesel additive for its use in motor
vehicles.
Bioethanol =
alcohol-based biofuel typically produced from starch and sugar crops such as
wheat and sugar beet, and used as a petrol additive for its use in motor
vehicles.
Biofuels =
liquid or gaseous fuel used for transport purposes produced from biomass.
GHG intensity = amount of carbon by weight emitted per unit of energy consumed. A
common measure of GHG intensity is weight of carbon (g CO2 eq.) per Mega joule
of energy. 
Conventional Oil = crude and unrefined oil stock extracted from underground
reservoirs using the natural pressure of the wells and pumping or compression
operations.
Feedstock = any
bulk raw material constituting the principal input for the production or
conversion into fuels.
Flaring and Venting = consequences of oil and gas production. Flaring is a controlled
burning of natural gas that cannot be processed or sold and disposes of the gas
while releasing emissions into the atmosphere. Venting consists in the release
of unburned gases in the atmosphere, often aimed at ensuring the safety
conditions in the course of the various processes and treatments. Both flaring
and venting release greenhouse gases, particulate matter, sulphur dioxide (SO2)
and methane into the atmosphere.
Fuel mix = result
of fossil feedstock diet fed to the EU refineries in a determined period of
time.
Indirect land-use change = land-use change occurring indirectly i.e. mostly referred to in
the context of land-use change as a result of displaced demand previously
destined for food/feed/fibre market as a result of biofuel demand.
Lifecycle greenhouse gas emissions = emissions associated with the production and use of transport fuels
and electric energy. This includes emissions produced through the extraction of
feedstocks used for production of transport fuels and electric energy, their
processing, their subsequent transport and refining as well as their use in
vehicles (referred to as their tail pipe emissions). 
Methodology based on a disaggregated
value = a single default GHG intensity value would
be established for each type of feedstocks used to produced fuels 
Methodology based on an average default
value = an average default GHG intensity value
would be established for the main four fuels consumed in Europe (i.e. petrol,
diesel/gasoil, LPG and CNG).
Unconventional Oil = crude oil found in shale formations and sand. It is explored,
developed and produced through unconventional processes. The terms “natural
bitumen”, “tar sands” and “oil sands” are used indifferently throughout this
document.

10.                  
Acronyms

2G BD            Second generation bio diesel 
2G Et              Ethanol
APEC              Asia-Pacific Economic
Cooperation
API                 American Petroleum
Institute
APPEA           Australian Petroleum
Production & Exploration Association
ARA               Amsterdam – Rotterdam – Antwerp 
b/cd                 Barrels per calendar
day
BP                   British Petroleum
CARB                         Californian
Air Resources Board
CARB                         LCFS
Californian Air Resources Board Low Carbon Fuel Standard
CCS                Carbon Capture Storage
CDU               Crude Distillation Unit
CH4                Methane
CHP                Combined heat and power
CIF                  Cost, Insurance and
Freight
CN                  Combined Nomenclature
CNG               Compressed natural gas
CO2                Carbon dioxide
CONCAWE   CONservation of Clean Air and
Water in Europe
CTL                 Coal-to-Liquids
DG AGRI       Directorate General
Agriculture
DG ENER      Directorate General Energy 
DG ENTR       Directorate General
Enterprise and Industry
DG ENV         Directorate General
Environment
DG MOVE     Directorate General for
Mobility and Transport
DG TRADE    Directorate General for Trade
EDD                Energy Duty Directive
EEA                European Environmental
Agency
EMCS                         Excise
Movement and Control System
ENS                Entry Summary
Declaration
EORI              Economic Operation
Registration and Identification
ETD                Energy Taxation
Directive
ETS                 European Emissions
Trading Scheme
EU/EU-27       European Union
EUROPIA      European Petroleum Industry
EUROSTAT   European Statistical System
FQD                Fuel Quality Directive
FSU                 Former Soviet Union
FT                    Fischer-Tropsch
g                      Grams
GHG               Greenhouse gas
GTL                Gas-to-liquids
GWP               Global Warming Potential
H2S                 Hydrogen-sulphide
ICCT               The International
Council on Clean Transportation
IEA                 International Energy
Agency
IEF                  International Energy
Forum
IFPRI              International Food
Policy Research Institute
ILUC              Indirect Land Use Change
IPIECA           International Petroleum
Industry Environmental Conservation Association
IPPC               Integrated Pollution
Prevention and Control
JEC                 Consortium of JRC, EURCAR (the European Council
for Automotive R&D) and CONCAWE (the Oil Companies’ European Organisation
for Environment, Health and Safety)
JODI               Joint Organisation Data
Initiative
JRC                 The Joint Research
Centre of the European Commission
Kg                   Kilograms
LCA                Life Cycle Assessment
LCFS              Low Carbon Fuel Standard
LNG                Liquefied Natural Gas
LP                   Linear Programme
LPG                Liquefied Petroleum Gas
LRTAP           Convention on Long-range
Trans boundary Air Pollution
MACC            Monitoring Atmospheric
Composition and Climate
MCON            Marketable Crude Oil Name
MJ                   Mega joule (106
joules)
MMT               Million Metric Tons
MRV               Monitoring, Reporting and
Verification
MS                  Member States of the
European Union
Mt                   Million tonnes
Mtoe                Million tonnes of oil
equivalent
N2O                Nitrous Oxide
NCTS              New Computerised Transit
System
NGL                Natural Gas Liquids
NGO               Non-governmental
Organisation
NH3                Ammonia
NMVOC         Non-Methane Volatile Organic
Compounds
NOx                product from the
reaction of nitrogen and oxygen
NRC                National Research Centre
NREAPS        National Renewable Energy
Action Plans
OECD                         Organisation
for Economic Co-operation and Development
OGP                International
Association of Oil & Gas Producers
OLADE          Latin American Energy
Organization
OPEC              Organization of the
Petroleum Exporting Countries
PM2.5                         Particulate Matter
PM10              Particulate Matter 
PJ                    Petajoule (1015 joules) 
PVC                Polyvinyl Chloride
RED                Renewable Energy Directive
R&D               Research and Development

RLCFRR        British Columbia Renewable
and Low Carbon Fuel Requirement Regulation 
ROW               Rest of the World
SMEs              Small and Medium
Enterprises
T&E                Transport and Environment
TJ                    Terajoule (1012 joules)
TNK-BP          Russian Oil Company
TTW                Tank-to-Wheel
UER                Upstream  Emissions
Reduction 
UK                  United
Kingdom of Great Britain and Northern Ireland
UNECE          United Nations Economic
Commission for Europe
UNEP-GPA    United
Nations Environment Programme. Global Programme of Action for
the Protection of the Marine Environment from Land-based Activities
UNFCCC        United Nations Framework
Convention for Climate Change
UNSD                         United Nations
Statistics Division
UPEI               Union of European
Petroleum Independents
US                   United States of America
US EPA          United
States Environmental Protection Agency
USGS              United States Geological
Survey 
USLCFS         United States Low Carbon
Fuel Standard
VOCs              Volatile Organic
Compounds
WEO               World Economic Outlook
WTO               World Trade Organisation
WTR               Well-to-Refinery
WTT                Well-to-Tank
WTW              Well-to-Wheel

11.                  
Annex I : Overview of the oil production
process (Source: Europia)

The oil
industry can be divided into two major components summarised in the figure
below.
The upstream
oil sector is a term commonly used to refer to the searching for and the recovery
and production of crude oil and is also known as the exploration and production
(E&P) sector. Exploration involves the search for rock formations
associated with oil deposits, and involves geophysical prospecting and/or
exploratory drilling. Well development occurs after exploration has located an
economically recoverable field, and involves the construction of one or more
wells from the beginning (called spudding) to either abandonment if no
hydrocarbons are found, or to well completion if hydrocarbons are found in
sufficient quantities. Production is the process of extracting the hydrocarbons
and separating the mixture of liquid hydrocarbons, gas, water, and solids,
removing the constituents that are non-saleable, and selling the liquid
hydrocarbons and gas. Production sites often handle crude oil from more than
one well. Oil is nearly always processed at a refinery. 
The downstream
oil sector is a term commonly used to refer to the refining of crude oil and
the selling and distribution of natural gas and products derived from crude
oil. The downstream sector includes oil refineries, petrochemical plants,
petroleum product distribution, retail outlets and natural gas distribution
companies. The downstream industry touches consumers through thousands of
products such as petrol, diesel, jet fuel, heating oil, asphalt, lubricants,
synthetic rubber, plastics, fertilisers, antifreeze, pesticides,
pharmaceuticals, natural gas and propane. 
 Figure 4: Summary of the oil production process. Source: Europia 
Oil refineries
play a particularly important role in the process of providing oil products for
consumers. Refineries break down crude oil into its various components, which
can then be selectively converted into a range of new products. The complexity
of refinery operations varies from one installation to the next, but generally
all refineries perform three basic steps: separation, conversion and
treatment.
Refineries
typically consist of a large number of processing units in which crude oil is
first separated, through distillation, into a number streams of
different boiling range and molecular structure. These streams are then
processed further, predominantly via catalytic conversion that requires
high temperature and high pressure. These conversion processes deliver oil
product streams that after further treatment are suitable for a variety of
applications. Demand for cleaner, high-value products, which can meet stricter
specifications, means modern refineries have to use ever more complex and
energy intensive processes. The refinery process is summarised in the following
diagram.
Figure 5: Overview of the oil refinery
process. Source: Europia
Most refineries
produce a wide range of products. These generally include:

 Gases such as LPG (liquefied
     petroleum gas) which can be used as feedstock for chemical processes, as
     fuel for heating and cooking or as transportation fuel.
 Naphtha, which is mostly
     used as chemical feedstock.
 Petrol, a main source for
     transport fuels.
 Kerosene and jet fuel,
     predominantly used as fuel for commercial aircraft and military transport.
 Middle distillates
     consisting of diesel fuel for transport (road and rail), heating oil for
     domestic and commercial applications and marine diesel mostly for inland
     and coastal shipping
 Heavy Fuel Oil for
     industrial installations (power generation and boilers)
 Bunker Fuels for sea-going
     vessels
 Speciality products
     including lubricants and greases for automotive and industrial
     applications, bitumen, mainly for road and roof surfacing, coke for
     specialty applications like electrodes and hydrocarbon solvents,
     predominantly used in speciality industrial applications.

Following
processing at a refinery, and with the use of pipelines, road tankers and
tankers transported by ship, transport fuel is sent to distribution centres and
from these distribution centres, transport fuel is transported to local service
stations, so that consumers can purchase it for their vehicles.

12.                  
Annex II : the EU crude oil supply chain
(Source: various)

The European
oil industry and oil trade is mainly based on foreign oil exploration and
production with overwhelming dependency on oil imports from Former Soviet
Union, Middle East and North Africa.
In simple terms
the supply chain incorporates transportation, processing, refining and
distribution. Most of the oil that is imported into the EU comes in either as
crude oil which has to be refined into various products or as finalised
products (which have been refined outside the EU) or 'intermediate' products
(petrochemicals or diesel which have been refined outside the EU and may need
to be refined further). EU refineries can be used to process crude oil,
feedstock and intermediates from other refineries and feedstock from chemical
plants. Following processing, oil and oil products can be processed and
distributed throughout the EU or outside of the EU via pipelines, road tankers
and tankers transported by ship. 

 Reporting in the supply chain[147]

There is
currently a significant amount of data transferred along the oil supply chain.
GHG emissions are already being tracked by many major oil companies for the
purposes of voluntary sustainability reporting. This reporting includes data on
the GHG intensity of fuels but does not include details on the origin of
products. 
Refiners need
to know the chemical composition of the crude they are using for efficient
refining, and as such they collect information about its origin. In addition,
there are also several laws and regulations in place which require information
to be reported on imported products placed on the European marketplace,
including origin, tariff classification, mass or volume, and physical
characteristics. The EU requires importers to provide information on their
imported goods for customs purposes. Much of this information is similar to
that required under the FQD. Suppliers should already report the country of
origin, properties of the crude, and its intended purpose at the time of
importation[148].
Overall, given the existing EU legislation and practices in place, economic
operators and importers are required to provide a significant amount of
information upon importation and there are additional obligations to ensure
that this information is transferred through the chain of custody as a product
moves about the EU. 
The following
table summarizes some of the information which is reported on/available (at Member State and EU level) at various stages in the supply chain at the moment and the
drivers for this. 
 Supply Chain || Info || Driver 
 Import || Physical Properties Feedstock source Intended Purpose of the goods || Combined Nomenclature 
 Proof of Origin || Community Customs Code 
 General Information on source of oil || Commodity Code 
 Destination of goods and how the goods are to be transported || Entry Summary Declaration 
 Transport means; country of origin; product details; statistical value; gross and net mass || Single Administrative Document/ NCTS 
 Designation of the crude oil (inc API); quantity in barrels; CIF per barrel; percentage sulphur content || Council Regulation (EC) No.2964/95 
 Movement of Excise goods || Excise Duty Directive 
 Refining || Name of crude Country of Origin, State & Province || Oil Industry / Refinery practices 
 Retail Sale || Details on products being used for transport fuel || Energy Taxation Directive 
 Other Info available || Overall GHG emissions || API/IPIECA GHG Compendium (Voluntary) guidelines for estimating GHG emissions 
   || Information on Products and product Flows || Joint Organisation Data Initiative 
The following
diagram displays the basic supply chain for imported crude oil, intermediate
products and feedstock together with the type of information available at
particular stages[149].
In practice, the supply process may involve more steps than those shown
in the basic diagram below, depending on how complex the supply chain is in
terms of the movement of oil streams. 
 Final products 
 Crude Oil 

 More detail on drivers
     for and information included in current reporting[150]
 Combined
     Nomenclature

The basis of
all reporting is the Combined Nomenclature (CN), which provides tariff
classifications for imported goods. Each year, the Commission publishes an
updated version of its Annex I setting out tariff classifications—called CN
codes—for all imported and exported products. CN-codes help to determine tariff
duties and play an important role in trade negotiations at the WTO level, while
the CN-coding system is also used for statistical purposes as records can be
maintained on the number of products being exported and imported as per the
classifications. The CN codes are thus used to help maintain a record of
foreign trade statistics. The CN codes for petroleum oils differentiate
according to physical properties (density, sulphur content, and distillation
temperature) and feedstock source (such as crude or bituminous materials other
than crude). The CN codes also require importers to disclose the intended
purpose of the imported goods in the European Union. This includes imports for
use as transport fuels and those destined to undergo specified processes at
refineries. A supplier cannot determine the applicable CN code without this
information. 

 Customs Code

Another source
for information is the Customs Code[151],
which lays down rules and procedures applicable to goods brought into or out of
the Community customs territory. 
Any goods
entering the European Union must be accompanied by a customs declaration and
supporting documentation (including information on proof of origin) that is
subject to verification by customs authorities. Goods which were produced in
more than one country "shall be deemed to originate in the country or
territory where they underwent their last substantial transformation.” The term
“substantial transformation” has yet to be defined in the Modernised Customs
Code. Import duties are based on the tariff classifications in the CN but may
also be based on other nomenclature based fully or partly on the CN. The
Customs Code can therefore provide a legal basis for distinguishing between
petroleum oils derived from conventional crudes or synthetic crudes. 

 Commodity code

The commodity
code combines the customs code and CN-code, using Taric and additional codes,
which, with regard to crude oil, can give general information regarding the
source of the oil.

 Entry Summary Declaration

Before the
entry of goods in the European Union an Entry Summary Declaration (ENS) has to
be completed to provide a description of the bulk goods entering the EU as well
as general information about the ship, its travel, load and crew. Where the
first EU country in which a ship arrives is not the same country as that of the
import of goods, it must be clear what the destination of the goods is and how
the goods are to be transported (e.g. by ship, train, pipeline or truck) to the
importing country. This declaration is not needed for goods which enter by
pipelines or for goods from Norway. 

 Single Administrative Document or New Computerised Transit System
     (NCTS)

A Single
Administrative Document has to be filled in or an electronic declaration has to
be made in the New Computerised Transit System (NCTS) for imported goods or
release for free circulation. The declaration is the same in all EU countries
and is standardised in the Community Customs Code. For most oil imports an
electronic declaration will be used. Every importing company has to use its own
EORI (Economic Operation Registration and Identification) number. The type of
data that is required (if appropriate) includes: the means of transport (by a
code); the country of origin of the product (by a code); the product (by a
code); the statistical value (and currency); and the gross and net mass (kg).
Copies of the
(electronic) document are submitted to the national statistical bureau or, in
the case of transport between member states, to both statistical bureaus. The
country of origin is the country where the crude oil is extracted. The customs
organisation also uses the Transit system (the New Computerised Transit System,
NCTS) for exporting and importing excise goods from or to third countries.

 Council Regulation (EC)
     No.2964/95 registration for crude oil imports and deliveries in the EU 

Council
Regulation (EC) No.2964/95 requires any person (economic operator) importing
crude oil from third countries or receiving a crude oil delivery from another Member State to provide information on the delivery/imported product to the Member State in which they are established.  Information, including the designation of the
crude oil, the API gravity, the quantity in barrels, the CIF price (Cost,
Insurance and Freight) paid per barrel and the percentage sulphur content, is
then reported to the Commission by Member States. Results from this reporting
can be found on the DG Energy website market observatory section. This data for
the crude register is collected from the oil importing companies by the
national statistical bureau and confidentiality provisions apply. 

 Excise Duty Directive and
     Energy Taxation Directive
 The Excise Duty Directive
     (EDD) ([152])
     and the Energy Taxation Directive (ETD) ([153]) stipulate
     the rules on the levying of indirect taxes on energy products and can be
     used to track the movement of goods (EDD) and obtain information on the
     taxation of products being used for transport fuels (ETD). The EDD lays
     down general arrangements for levying excise duties on the consumption of excise
     goods such as energy products. In principle the excise duty becomes
     chargeable ‘at the time, and in the Member State, of release for
     consumption’ of the excise goods. For those petroleum products which are
     energy products excise duties become chargeable upon their production
     (including extraction) within the EU unless the production, processing and
     holding take place in a tax warehouse, and in such case the goods are
     placed under a duty suspension arrangement. For imported goods the excise
     duty is normally chargeable at the moment of importation ‘unless the
     excise goods are placed, immediately upon importation, under a duty
     suspension arrangement’. Movement of excise goods under suspension of
     excise duty within the EU is monitored through a computerized system
     (Excise Movement and Control System (EMCS)). The energy products are
     defined with references to the codes of the CN. The EMCS is therefore a
     useful system through which Member States can track intra-EU movement of
     excise goods under suspension of excise goods. ETD lays down the EU
     framework for the taxation of energy products and electricity. In general
     the ETD requires Member States to impose taxation on any product used as a
     motor fuel which includes energy products destined for use as transport
     fuels, and in particular petroleum oils obtained from crudes and
     bituminous materials.Joint Organisation Data Initiative (JODI)

APEC, Eurostat, IEA/OECD, OLADE,
OPEC and the UNSD formed a common data reporting exercise, called Joint
Organisation Data Initiative (JODI), in June 2011. Initially
this involved a questionnaire asking for month-old and two-month-old information
and later became a government reporting obligation for the member countries of
the six organisations, and coordinated by the IEF Secretariat. This resulted in
the development of a worldwide database on monthly oil statistics. For each
country the JODI database provides information on flows (production,
imports/exports etc) and products (crude oil, petrol etc).

 Oil industry and refinery data

Oil source data
is also monitored and tracked in the industry itself. To determine the type of
oil, refineries need detailed data on the oil which they process. This applies
to the crude oil that refineries process. 

 Voluntary reporting of GHG emissions

Many companies
in the oil sector voluntarily report their GHG emissions through the publishing
of sustainability reports which are then verified through external assurance.
The standard tool for this reporting is the API/ IPIECA GHG Compendium (API,
2009), developed by the American Petroleum Institute (API), the International
Petroleum Industry Environmental Conservation Association (IPIECA) and the
International Association of Oil & Gas Producers (OGP). The methodology is
based on a standard for GHG reporting developed by the World Bank and the World
Resources Institute and covers the calculation or estimation of emissions from
the full range of industry operations, including exploration and production.
However
reporting is not consistent between the major companies as some report
emissions on an equity basis while others allocate emissions on an operational
basis. There is therefore no harmonised industry standard. These existing
voluntary reporting GHG activities include the GHG emissions of intermediates
and products for processing under accountability of the suppliers. Reporting is
limited to upstream and overall GHG emissions of the suppliers themselves with
the data covering the whole range of feedstock-fuel chain, from crude oils to
intermediates and imported end products (diesel). Data on the GHG intensity of
crudes and oil products is therefore held by the major oil companies and could
be passed through the supply chain but information on fuel origin is not
necessarily tracked through the supply chain at the moment and to do so would
present an additional burden.
By way of
example, annual reports from BP and Exxon Mobil (Corporate Citizenship Report)
for 2011 contain details of absolute GHG emissions for the companies broken
down by upstream, downstream and chemical. With regard to Exxon Mobil, the net
equity greenhouse gas (GHG) emissions metric includes direct and imported GHG
emissions but excludes emissions from exports, including Hong Kong Power.
ExxonMobil reports GHG emissions on a net equity basis for all its business
operations, reflecting its percentage ownership in an asset. BP reports the
direct GHG emissions for the group on a CO2-equivalent basis, including CO2 and
methane. This reporting represents all consolidated entities and BP’s share of
equity-accounted entities (except TNK-BP). BP also provides further details on
year on year variance broken down into changes due to developments in terms of
acquisitions, divestments, methodology changes, operational changes and
sustainable reductions during the reporting period. BP separately reports on
the indirect CO2 emissions associated with the import of electricity, heat or
steam into its operations and data going back to 1998, including data by
business segment, can be found using on the BP website. BP also provides an
analysis of direct GHGs per unit of production – using a consistent
normalization methodology so that trends in GHG intensity over time can be
seen, across its major business sector (Exploration and Production, Refining
and Petrochemicals).
A number of
major oil companies also contribute to an annual report by OGP on the
environmental performance of the exploration and production industry. The
report provides details at a global and regional level on environmental
indicators such as gaseous emissions, energy consumption, flaring, aqueous
discharges, discharges of non-aqueous drilling fluids on cuttings and spills of
oil and chemicals. The 2011 report contained data in respect of 36 companies
covering around 33% of global production sales although regional coverage is
uneven. Details of the aggregate CO2 and GHG emissions of all of the participating
companies combined, as well as the emissions per unit of production across
different regions are provided, although the report does highlight that since
companies use a variety of estimation techniques, care should be taken when
interpreting data.

 Information where there
     are gaps/difficulties in terms of reporting

In terms of the
current reporting practices and level of information provided at stages in the
supply chain, the main area where there are gaps or difficulties with regard to
the transfer of information is in respect of ‘finished’ and ‘intermediate’
products (such as petrochemicals or diesel which still need further refining
before being sold on the market), which represent 20-25% of EU oil
consumption.  In simple terms[154]:
Crude oil
origin and type are currently not being reported for end products (incl. petrol
and diesel) and intermediates that enter the EU. Only the last country where
the product or intermediate was processed (e.g. refined) is known.
Intermediates
or crude oil derivatives from the chemical industry are also used as feedstock
for refineries. The origin of these products is currently not being reported.
Refineries do
not require suppliers to provide the origin and type of oil used to produce the
intermediates and products that they process.
Data on the
origin of oil is currently not tracked beyond the refineries, i.e. in the
trajectory from refinery to the excise duty point. Supplier feedstock origin is
not included with the other information provided along the chain.
The difficulty
and complexity arises when crude oil or intermediate products are blended and
processed, as it is necessary to determine the contribution of different inputs
prior to transferring ownership of the output. Refineries sometimes use
different crudes at the same time and intermediate products are exchanged
between refineries (both within the EU and between non-EU and EU refineries)
and co-fed to the refinery crude intake at relevant unit feed streams for
further processing. Information on feedstock origin is known to the first
refiner and other qualities of the inputs are tracked, but incomplete
information management practices on feedstock may result in the information not
being transferred. Difficulties arise as blending and processing can occur in
different countries and streams enter the EU at different stages. 
In terms of the
mechanisms in place for obtaining information about imported oil and oil
products there are some issues. For example, under the NCTS, the box for the
region code is not always filled in as in many countries it is not obligatory
to do so. Furthermore, the origin of the crude oil may disappear from the data
after refining if not managed and transferred appropriately. So for refined
products, in the current situation the country of origin may not always be the
same as the country of extraction, as there is no need to ensure this
information remains accessible. With regard to Council Regulation (EC)
No.2964/95, the statistics do not cover imports of intermediates or final
products such as diesel. Nonetheless, even for these types of imports, in a lot
of cases the major oil companies already monitor GHG intensity for their own
sustainability reports and quality controls. 
The
establishment of a synchronised methodology and single reporting system would
enable consistent transfer of data on the GHG intensity and origin of products
being supplied by oil companies.

13.                  
Annex III: Low Carbon Fuel Standards outside EU

The most
developed programme to date is the Californian Air Resources Board (CARB) Low
Carbon Fuel Standard (LCFS), which requires fuel producers and importers to
reduce the GHG intensity of their fuels by an average of 1% per year until 2020
relative to the average GHG intensity of the 2006 California crude mix[155].This means that fuel
providers have to determine the GHG intensity of the fuels they provide,
specific to a set of pathways, and to report that information to CARB, under
the accepted methodologies for suppliers to report improvements in the LCA of
existing fuel pathways or entirely new ones[156].

The CARB LCFS
is a market mechanism where regulated parties may buy credits (when fuel
supplied is higher than GHG intensity target for a full year) or sell them
(when the fuel supplied is lower than the GHG intensity target for a full year).
This way, it creates a price differential for fuels with lower GHG intensity
through recognising differences in terms of their lifecycle greenhouse gas
emissions based on the carbon intensities as calculated by the CARB. As a
result, a price differential has already started to emerge in the Californian
market, with for example corn ethanol with a GHG intensity of about 90 g CO2/MJ
fetching 2 to 3 cents more per gallon in the Californian market than corn
ethanol with GHG intensity of 98 g CO2/MJ. 
Amongst the
other similar Low Carbon Fuel Standards in North America, the only other one in
operation is the British Columbia Renewable and Low Carbon Fuel Requirement
Regulation (RLCFRR). No data on price differentials arising from this
scheme are yet available. Other Low Carbon Fuel Standards at different stages
of development also include programmes in the US for the Northeast and
Mid-Atlantic States[157],
the Midwestern states[158],
 Oregon and Washington. In most cases, the LCFS are proposing reduction
targets of 10% in the greenhouse gas intensity of the fuels that are being
supplied to be achieved over different timelines. Although they follow a
similar approach to the Californian LCFS, there is currently no harmonised
single methodology for calculating the different GHG intensities. 

13.1       Methodological choices for reporting on GHG
emissions of fossil fuels of the different Low Carbon Fuel Standards

The two LCFS in
operation in California and British Columbia utilise different methodological
approaches for the reporting of the GHG emissions associated with fossil fuels[159].
Under the
latest version of the Californian LCFS, the average GHG intensity of the crude
used in California is assessed on a yearly basis according to the GHG intensity
of the petrol and diesel feedstocks consumed in the previous year. The
individual GHG intensity values of these feedstocks are based on estimated
intensities disaggregated by Marketable Crude Oil Name (MCON), and the same
reporting requirements are applicable to domestic fuel suppliers and importers.
As higher intensity values are allocated to unconventional feedstocks, if their
use in the final fuel mix increases, the average value would also increase
accordingly, requiring additional mitigation measures across all fuel suppliers
without distinction to achieve the required greenhouse gas emissions
reductions. 
With regards to
the British Columbia RLCFRR, the current systems allows fuel suppliers to
report either default emission values provided or fuel specific greenhouse gas
emissions calculated using an LCA model[160].
It is worth noting that in contrast to California, the default values provided
do not differentiate between conventional and unconventional sources according
to their GHG intensity and so an increase of unconventional sources in the
final fuel mix would not be captured by the methodology in the reported GHG
intensity.  

14.                  
Annex IV: information on industry sectors
related to fuel suppliers
14.1          Petrochemical
industry

The petrochemical industry
produces key chemicals from raw feedstocks such as naphtha, components of
natural gas such as butane, and some of the by-products of oil refining
processes, such as ethane and propane following the refining process. These
chemicals are the building blocks for common products such as PVC, textile
fibres, rubber and plastic manufacturing, paint, etc… Petrochemical producers
depend on the refined products provided to them by the refineries ( many times
petrochemical producers are even co-located with refineries; of the 58 steam
crackers in existence in the EU, 41 are directly integrated refinery/steam
crackers), and so they may be impacted by any changes to the composition and
price of the crude delivered to Europe.

14.2          Alternative
transport fuel industries 

Biofuels are
liquid or gaseous fuels used for transport purposes produced from biomass[161]. Most biofuels
currently consumed in the EU are typically 'first
generation' or ‘conventional biofuels’, typically being produced from crops
such as cereals and sugars to make bioethanol (i.e. for petrol substitution),
and oil crops, waste oils and animal fats to make biodiesel (i.e. for diesel
substitution) via well-developed technological processes. 
In 2010, 13.3 Mtoe of biofuels were
consumed in the EU, mainly biodiesel due to the larger share of diesel cars in
fleet, which represented 4.5% of all fuels consumed in road transport[162]. Imported biofuels
represented 20% of the market[163],
despite existing overcapacity in the EU (total EU
installed capacity stands at 25Mtoe). Other
related industries include those involved in the processing of the feedstocks,
particularly oil crops into vegetable oils before they are chemically treated
to produce the final biodiesel product[164],
and those involved in cultivation of feedstocks[165]. 
In this context, the most important feedstock for biodiesel
was EU rapeseed (40%) followed by imported soy and palm (40%). In addition, it
is estimated that used cooking oil may make up to 10% of total consumption
during the same period. For bioethanol, about 80% originated from EU sugar beet,
wheat and maize. 
In contrast,
the production of advanced biofuel technologies, typically produced from
non-food/feed feedstocks such as wastes and residues like straw, non-food crops
like grasses and miscanthus, and algae, with the exception of a small
commercial scale advanced bioethanol plant in Italy, remain largely at pilot or
planning scale due to financial and technological barriers. 
Estimated 2020 consumption figures for biofuels based on the National
Renewable Energy Action Plans (NREAPS)[166]
and assuming an increase to over 29 Mtoe are also the basis for the baseline
established in this Impact Assessment. In this context, there is some
uncertainty regarding how much biofuel can be blended with petrol and diesel,
while maintaining associated warranties from car manufacturers. Based on the
biofuel volumes estimated by Member States for 2020, it seems that, in volume
terms, blends beyond 10% for diesel (currently at 7%) and around 15% for petrol
(currently at 10%) will be needed to achieve the Renewable Energy targets
EU-wide[167].
This is an important issue due to the long lead-times both in changing
specification of car engines, the slow turnover of cars, and the long lead-time
needed for changing fuel specifications, and so biofuel volumes reported in the
NREAPs for 2020 may be seen close to maximum achievable blends given
technological constraints. 
Due to concerns around the global land use
change impacts associated with increased agricultural demand for biofuel
feedstocks, the Commission has recently proposed a 5% limit to the amount of
conventional biofuels which may be counted towards the Renewable Energy targets[168]. As this may have
significant impacts on current biofuel projections to 2020 if adopted, it is
further explored in the sensitivity section of this impact assessment. 
The use of electricity in road transport
remains low, with Eurostat figures reporting consumption of 0.006Mtoe of
renewable electricity in road transport in 2010[169], or
approximately 70,000 electric cars. In this context, the estimated increase in
consumption to 2020 at 2.1Mtoe (i.e. 0.7Mtoe of renewable electricity) as
reported in the NREAPs[170]
seems challenging.      

15.                  
Annex V: EU suppliers dataset (Source: ICF)

Following a request from the Commission,
partial information on the volumes of petrol and diesel supplied by a list of
anonymised suppliers, 51 producers and 404 traders, was provided by 12 Member
States. In order to extrapolate these data for the EU27, the following steps
were taken,

 For the twelve
     Member States, the number of refineries, based on data published by
     European Commission (2010), was mapped and matched to the number of
     producers, and from this an average ratio of producers/refineries was
     derived. This ratio was used to extrapolate the number of producers per Member State      for the unknown Member States by using the same published data on the
     number of refineries.


 The supply of
     petrol and diesel by producers reported by Member States was assessed
     against the refinery capacity data published by the European Commission
     (2010) and used to extrapolate estimates for the petrol and diesel
     supplied by producers in the unknown Member States.


 The ratio of
     the reported supply of fuels by producers to the supply of fuels by
     traders was used to extrapolate the fuels supplied by traders in the
     unknown Member States. For those Member States without producers (i.e.
     without refineries), the volumes supplied by traders was instead assumed
     to be the average of fuels supplied by traders in the Member States.


 Volumes (on an
     energy basis) of all fuels across producers and traders were normalised
     with the baseline fuel projections to ensure consistency.


 For the
     producers, if more than one was identified for the Member State, the supplied volumes of fuel were split across the size categories using the information
     obtained. The (rounded) number of producers within each size category
     within each Member State was estimated from the supplied volumes of fuel
     per size category per Member State together with the supplier. This
     enabled also the quantities of fuel supplied by each producer to be
     estimated (if there was more than one producer in the Member State).


 For the
     traders, the quantity (MJ) of each fuel at Member State level was
     estimated to be split among size categories of suppliers within each
     unknown Member State. The (rounded) number of traders within each size
     category within each Member State was estimated from the quantity of fuel
     per size category per Member State together with the average size of
     supplier. This enabled also the quantities of fuel supplied by each trader
     to be estimated. 


 The above
     steps resulting in an estimated EU27-wide dataset of suppliers with
     estimates for total volumes supplied per petrol and diesel which vary in
     the ratios between the fuel types. This consists of 90 suppliers that are
     producers (i.e. which are refiners operating one or more refineries) and
     775 traders. Table below summarises the extrapolated EU dataset on
     suppliers which is subsequently used (at granular supplier level) to
     undertake the policy options analysis.

 Member State || Number of suppliers 
   || Producers || Traders || Total 
 Austria || 1 || 26 || 27 
 Belgium || 3 || 24 || 27 
 Bulgaria || 1 || 6 || 7 
 Cyprus || 0 || 6 || 6 
 Czech Republic || 3 || 18 || 21 
 Germany || 11 || 139 || 150 
 Denmark || 2 || 4 || 6 
 Estonia ||   || 6 || 6 
 Greece || 3 || 19 || 22 
 Spain || 8 || 100 || 108 
 Finland || 1 || 20 || 21 
 France || 5 || 32 || 37 
 Hungary || 8 || 20 || 28 
 Ireland || 1 || 16 || 17 
 Italy || 14 || 61 || 75 
 Lithuania || 1 || 49 || 50 
 Luxembourg || 0 || 11 || 11 
 Latvia || 0 || 25 || 25 
 Malta || 0 || 6 || 6 
 Netherlands || 5 || 28 || 33 
 Poland || 2 || 56 || 58 
 Portugal || 2 || 18 || 20 
 Romania || 5 || 5 || 10 
 Sweden || 4 || 11 || 15 
 Slovenia || 0 || 10 || 10 
 Slovakia || 1 || 6 || 7 
 United Kingdom || 9 || 53 || 62 
 EU27 total || 90 || 775 || 865 

16.                  
Annex VI: EU refinery capacity
(Source: Vivid Economics)
  
 Country || Average CDU capacity (b/cd) || Average complexity (index) || Number of refineries || Total CDU capacity (kb/cd) 
 Austria || 208600 || 6.5 || 1 || 209 
 Belgium || 239607 || 6.0 || 3 || 719 
 Bulgaria || 115240 || 6.1 || 1 || 115 
 Czech Republic || 61000 || 6.5 || 3 || 183 
 Denmark || 87200 || 4.5 || 2 || 174 
 Finland || 130288 || 10.9 || 2 || 261 
 France || 156255 || 7.8 || 11 || 1719 
 Germany || 185936 || 8.9 || 13 || 2417 
 Greece || 105750 || 8.3 || 4 || 423 
 Hungary || 161000 || 11.4 || 1 || 161 
 Ireland || 71000 || 5.4 || 1 || 71 
 Italy || 144014 || 8.4 || 16 || 2304 
 Lithuania || 190000 || 9.5 || 1 || 190 
 Netherlands || 199429 || 8.9 || 6 || 1197 
 Poland || 246475 || 10.8 || 2 || 493 
 Portugal || 152086 || 7.4 || 2 || 304 
 Romania || 72167 || 7.6 || 6 || 433 
 Slovakia || 115000 || 12.7 || 1 || 115 
 Slovenia || 13500 || 1.0 || 1 || 14 
 Spain || 141278 || 8.3 || 9 || 1272 
 Sweden || 87400 || 6.1 || 5 || 437 
 UK || 176717 || 8.8 || 10 || 1767 
                                                             

17.                  
Annex
VII: Average GHG intensities by Member
 State (gCO2/MJ) (Source:
ICF)
  
 Member State || Upstream || Transport, refining, distribution and combustion || Total lifecycle 
   || Petrol || Diesel || Petrol || Diesel || Petrol || Diesel 
 Austria || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Belgium || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Bulgaria || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Cyprus || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Czech Republic || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Germany || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Denmark || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Estonia || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Greece || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Spain || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Finland || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 France || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Hungary || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Ireland || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Italy || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Lithuania || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Luxembourg || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Latvia || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Malta || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Netherlands || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Poland || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Portugal || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Romania || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 Sweden || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 
 Slovenia || 7.2 || 6.9 || 82.4 || 84.1 || 89.6 || 91.0 
 Slovakia || 5.4 || 5.5 || 82.4 || 84.1 || 87.8 || 89.6 
 United Kingdom || 5.2 || 6.2 || 82.4 || 83.8 || 87.6 || 90.0 

18.                  
Annex VIII: Estimated GHG emission associated
with fossil and biofuels 

Figure 2: Default GHG intensity of fossil fuel
feedstocks (Source: EC proposal 2011) 
Figure 3: GHG intensity values for biofuels (Source:
EC)

19.                  
Annex IX: Road Energy demand and related
emissions in ILUC sensitivity scenario (Source: ICF)
  
 Fuel || Feedstock || GHG Emissions || Energy Demand 
 (MMT)  PJ 
 Petrol || Conventional crude || 234.9 || 2682 
 Natural bitumen (Venezuela to EU) || 7.2 || 68 
 Oil shale || 0.2 || 2 
 Diesel || Conventional crude || 648.3 || 7253 
 Natural bitumen (Venezuela to EU) || 18.4 || 170 
 Natural bitumen (Canada to USGC) || 2.3 || 21 
 Oil shale || 0.6 || 4 
 CTL || 3.2 || 19 
 GTL || 6.0 || 62 
 LPG || n/a || 15.3 || 208 
 CNG || n/a || 3.4 || 44 
 Electricity || EU-average || 3.9 || 87 
 Ethanol   || Corn (maize) || 1.2 || 29 
 Sugar beet || 1.4 || 40 
 Sugar cane || 3.6 || 103 
 Wheat (Process fuel not specified) || n/a || n/a 
 Wheat (NG as process fuel, w/ CHP) || n/a || n/a 
 Wheat (Straw as process fuel, w/ CHP) || 0.6 || 15 
 2G ethanol - land using || 0.3 || 10 
 2G ethanol - non-land using || 0.1 || 10 
 sub-total || 7.2 || 206 
 Biodiesel  || 2G biodiesel - land using || 0.3 || 15 
 2G biodiesel - non-land using || 0.1 || 15 
 Waste 1st. Gen Diesel (2G) || 0.3 || 31 
 Palm oil || n/a || n/a 
 Palm oil with methane capture || n/a || n/a 
 Rapeseed || n/a || n/a 
 Soybean || n/a || n/a 
 Sunflower || n/a || n/a 
 sub-total || 0.7 || 61 
 TOTAL || 951.7 || 10886 

20.                  
Annex X: Intervention logic


21.                  
Annex XI: Assessment methodology

The assessment of the policy options
described in section 4 can give raise to a range of environmental, economic, social
and wider impacts. The most relevant impacts are listed in the table below. 
 Effectiveness || Accuracy of the methodology with regards to reporting of GHG intensity of fuels consumed in the EU at supplier and EU average level (quantified).  Coherence with biofuel methodology. Simplicity of reporting and verification arrangements for fuel suppliers and MS. 
 Environmental impacts || Air quality impacts 
 Biodiversity 
 Efficient use of resources (i.e. land use, water, energy input) 
 Sustainable consumption (i.e. including consumption of alternative fuels) 
 Economic impacts   || Administrative burden on industry and public authorities (quantified) 
 Compliance costs (quantified) 
 Market costs, pump prices and competitiveness impacts (quantified) 
 Impacts on trade, trade relations and WTO compatibility 
 Security of supply and supplier prices 
 Social impacts   || Employment 
 Public health 

22.                  
Annex XII: Carbon abatement costs and potential
(Source: ICF/Vivid Economics) 

Figure 7: marginal abatement costs (euro/tonne)
Figure 4: Compliance cost curve under baseline
scenario (non-ILUC) (option B1)
Figure 5: Compliance cost curve under baseline
scenario (non-ILUC) (option C)
Figure 6: Compliance cost curve under baseline
scenario (non-ILUC) (option D1)
Figure 7: Compliance cost curve under baseline scenario
(non-ILUC) (option E)

23.                  
Annex XIII: Monitoring, reporting and
verification actions

To measure progress towards the target,
fuel suppliers and fuel traders will have to annually report the GHG intensity
of the fuel they provided during that specific year. For each methodological
option ICF identified and analysed the Monitoring, Reporting and Verification
(MRV) costs that suppliers and public authorities will incur. Data requirements
of the different options are compared with the existing reporting practices in
order to identify data gaps and estimate the associated additional costs. The
majority of the MRV costs will be borne by the fuel refiners, without any
difference between EU and non-EU facilities. 
For each kind of compliance option, the
total cost has been calculated for each actor (either a supplier or a public
authority) and summed up for the entire EU, considering the total number of
actors involved. As far as UER projects are concerned, the estimate for the
administrative costs has been based on CDM transaction costs for suppliers.
However, the responsibility, and hence the costs, to set up a mechanism to
verify and validate the different projects submitted is attributed to public
authorities (e.g., MS). The following Table depicts the administrative actions
that suppliers would need to take under the different options.

24.                  
Annex XIV: Screening of competitiveness impacts
(Source: Vivid Economics)

The refining
industry is the focus of this competitiveness analysis but other sectors may
also affected by the FQD. These other sectors include biofuel production,
vehicle manufacture, public transport and the petrochemicals sector. 
After applying
the Commission’s guidelines on the extent of analysis required for sectors that
face competitiveness impacts from new policy proposals, only the
competitiveness impacts on the refining industry have been warranted to require
further analysis. Qualitative screening of the sectors uses the matrix
suggested in the guidelines referred above. 
Biofuels
production is assessed in Table 8. The sector faces some small direct impacts
due to the FQD, mainly regarding international competitiveness due to possible
variation in the emissions intensity of EU and foreign biofuels. These impacts
seem dependent on aspects of policy not under consideration in this study and
are likely to be insignificant. As a result the competitiveness impact on
biofuels is not pursued any further.
The
competitiveness impact on vehicle manufacturers is considered in Table 9. The
only relevant impacts are a possible decrease in demand for vehicles if fuel
prices were to increase due to the FQD and a slight increase in the demand for
electric vehicles. The impact of the FQD on fuel prices is likely to be low and
the demand response to such a change in price is uncertain but unlikely to be
large. The demand for electric vehicles before 2020 in the EU is likely to be
very small relative to demand for total vehicles. As a result the
competitiveness impact on vehicle manufacturers is likely to be insignificant
and so the analysis is not pursued any further for this sector.
Public
transport may experience an increase in demand if fuel prices were to increase
due to the FQD and this is described in Table 10. As is the case for vehicle
manufacturers this impact is expected to be small and so further analysis is
not pursued.
Table 11
evaluates the possible competitiveness impacts on petrochemicals. This sector
may suffer negative indirect impacts due to impacts on refineries. Some
petrochemical producers are co-located with refineries and so if a refinery
were to close due to the FQD then so would a co-located petrochemical plant.
Petrochemical plants usually rely on output from complex refineries as these
yield higher ratios of the most sought after petrochemical feedstocks. The FQD
is only likely to negatively impact simple refineries (e.g., hydroskimming) as
these exhibit the lowest margins. The FQD may also result in changes to the
composition and price of crude delivered to Europe as refineries adjust their
diet. As crude is a feedstock for petrochemicals these changes could also have
an impact on the competitiveness of the sector. This is also unlikely as the
small quantities of replaced feedstocks will not result in a noticeable carbon
price premium and the quality of the replaced feedstocks yield lower
proportions of the desired petrochemical inputs. Given that the impacts on
petrochemicals are a function of the impacts on refineries further analysis for
petrochemicals is not directly pursued but will be considered qualitatively
alongside the quantitative analysis conducted for refineries.
Refineries face
the greatest direct impacts from the FQD, as Table 12 describes. Furthermore,
these impacts are dependent on the way in which the policy is implemented.
Refineries may have to abate and the level of abatement required and the cost
of abatement may vary by refinery depending on the design of the policy.
International competitiveness impacts will also vary depending on how imports
of refined products are treated.
Ability of
refiners to select alternate crudes may influence competitiveness. Central and
eastern European refineries are disproportionately constrained in their ability
to choose different crudes as many of these are landlocked and dependant on
pipelines delivering crude from the FSU. However, they are also not likely to
be affected as the predicted change in crude uptake will affect the southern EU
region. The choice of methodology will also influence to what degree they will
be affected.
Cost
pass-through is also expected to influence competitiveness. Demand elasticity
is a key determinant of the ability of an industry to pass on price increases
to consumers or other downstream purchasers, allowing the identification of
where the burden of a regulatory measure or market change will lie. Where
consumers have limited options to substitute for other goods or reduce their
level of consumption, they are more likely to bear the price of input cost
increases. Note that input cost increases that only affect EU producers will
likely have a lower pass-through rate than shocks that affect all sellers into
the European market. Given that the FQD obligations cover imports as well as
European manufacture, it seems reasonable to consider that changes in the price
of crude oil provide the more relevant comparison point. Given, that the
cost-pass through rates for crude oil are more relevant, it appears that the
true pass-through rate lies between 90 and 100 per cent.
Finally, no
refinery closures are expected as all measures are predicted to reduce fossil
fuel demand by only 0.08%.
The other major
sector that will take part in compliance with the FQD is the fuel trader.
However, fuel traders hold an intermediary market position, that is, they
reduce the transaction costs of trading through specialisation. In contrast to
refiners, traders hold no major assets affected by the FQD. Further, modelling
results presented in Section 3 confirm that trade volumes are not adversely
impacted. Any reduction in trade of fossil fuel volumes is largely offset by an
increase in trade of biofuel volumes. Since these effects are too small to
produce changes in market structure and since cost pass through is almost
complete, there are no differences in the cost of capital (associated with
changes in margin volatility), employment (associated with plant closure or
large changes in output), value added (associated with changes in margins or
wages) and capacity to innovate (associated with profitability) among traders
and producers regardless of the implementation option considered. A summary of
the qualitative assessment is presented in Table 13.
 Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || the FQD provides a market for biofuels produced for compliance with Directive 2009/28/EC. There are additional impacts due to the FQD || none applicable || 3% increase in biofuel consumption || not applicable due to no expected additionality || there could be a shortage of biofuels relative to the quantity needed for compliance with the FQD, which could increase biofuel prices 
 Capacity to innovate || the FQD provides an increased incentive to raise the blend wall || none applicable || likely to be small given current research program || not applicable || not applicable 
 International competitiveness || ILUC proposal (European Commission, 2012b) may affect competitiveness of biofuels || none applicable || the emissions intensity of biofuels from ILUC can be 30 per cent more or less than default values (European Commission, 2012c) || for the duration of the FQD || (European Commission, 2012b) ILUC proposal has yet to be accepted and current details are limited 
Table 8: Biofuels production faces small
direct impacts that are contingent on other policies (Source: Vivid Economics)
 Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || none applicable || if fuel prices increase then demand for vehicles may decline || likely to be small as the FQD does not impose significant costs to fuel production || permanent change to demand || changes in fuel prices due to the FQD are uncertain; the price elasticity of demand for vehicles is uncertain 
 Capacity to innovate || small increase in demand for electric vehicles; flex-fuel vehicles are currently an established technology || none applicable || small due to limited expected deployment of electric vehicles prior to 2020 || not applicable || none applicable 
 International competitiveness || none applicable || none applicable || none applicable || not applicable || none applicable 
Table 9: Vehicle manufacturers could face
small changes in demand if fuel prices increase (Source: Vivid Economics)
         Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || none applicable || if fuel prices increase then demand for public transport may increase || likely to be small as the FQD does not impose significant costs to fuel production || permanent change to demand || changes in fuel prices due to the FQD are uncertain; the price elasticity of demand for vehicles is uncertain 
 Capacity to innovate || none applicable || none applicable || none applicable || none applicable || none applicable 
 International competitiveness || none applicable || none applicable || none applicable || none applicable || none applicable 
Table 10: Public transport could
experience a small increase in demand if fuel prices increase Source: Vivid
Economics)
 Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || none applicable || producers integrated with refineries are not likely to be exposed to impacts || input price changes are likely to be limited || No permanent change in input prices || uncertainty on the extent to which co-located refineries will be affected; some risk that input price changes could be greater than expected 
 Capacity to innovate || none applicable || none applicable || not applicable || not applicable || none applicable 
 International competitiveness || none applicable || there is an international competitiveness impact to the extent that input prices change || input price changes are likely to be limited || permanent change in input prices || some risk that input price changes could be greater than expected 
Table 11: The competitiveness impacts on
petrochemicals occur indirectly from the effects of policy on refineries
(Source: Vivid Economics)
 Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || refineries will face a cost of abatement to achieve compliance and will also enjoy high cost pass-through rates; demand for refined product could be displaced by biofuels || none applicable || Approximately 0.08% reduction in fossil fuel demand || permanent cost change || the magnitude of costs depends on the extent to which other abatement options are available; the variance in costs across refineries depends on how the policy is implemented 
 Capacity to innovate || profits may slightly fall, with a small risk of limiting R&D from retained profits || none applicable || depends on the extent to which R&D is funded from retained profits || a permanent cost change will permanently affect profits || refineries may be able to compensate for lost part to finance R&D in other ways 
 International competitiveness || Impacts on international competitiveness impacts will not occur as importers and domestic producers are equally affected || none applicable ||   || cost change may affect competitiveness || the impact depends on how the policy is implemented 
Table 12: Refineries face the greatest
direct effects to competitiveness and the nature of these effects depends on
how the policy is implemented (Source: Vivid Economics)
 Competitive impacts || Direct effects || Indirect effects || Sizing (timing) of impacts || Duration of impact || Risks and uncertainty 
 Cost and price competitiveness || traders will face a cost of abatement to achieve compliance; demand for traded refined products will be broadly displaced by biofuels; the costs will be passed through by traders || none applicable || depends on how the policy is implemented || permanent cost change which is passed through || the magnitude of costs depends on the extent to which other abatement options are available 
 Capacity to innovate || No effect || none applicable || none applicable || none applicable || none applicable 
 International competitiveness || No effect || none applicable || none applicable || none applicable || none applicable 
Table 13: Traders also face direct effects
but their competitiveness is largely unaffected

25.                  
Annex XV:
Assessment of competitiveness impacts on EU refineries (Source: Vivid economics)
25.1.            
Estimation of the marginal cost curves - exit
and sustainable margins

The first step undertaken was to model exit
of refiners under baseline conditions, to ensure realistic capacity utilisation
and construct realistic baseline projections. Vivid Economics took Ensys’
demand projection for 2020 and estimates on biofuels uptake from EC data to
calculate the margins and utilisations achieved in the sector, assuming all
current refineries remained in operation except for the announced closures. The
further step assumed the least profitable refineries in Europe to close down
until the margins recovered to levels typical of refinery operations in recent
years. This set of remaining refiners was the set upon which the assessment was
carried out.
The first step in the data inputting, which
involves estimation of exit, takes as inputs the fuel demand and price
projections from the World Model, shown in the figure below.
Figure 8: Relationship between data
gathering and analytical tasks. Source: ICF and Vivid Economics
The next steps in the modelling was to
construct a compliance cost curve for biofuels and upstream emissions
reductions, and to understand the current compositions and upstream carbon
intensities of crude and diesel imported into Europe.

25.2.            
Construction of marginal costs of compliance
options

The construction of the marginal cost
curves for compliance options has four elements: 
–    
crude switching;
–    
biofuel uptake;
–    
product switching; and
–    
upstream emissions
reduction.

24.2.1    Crude switching

The competitiveness of crudes is defined as
their value in the EU refining market. This is modelled by taking the current
import shares by crude and imputing their costs to refiners, which are the
combined purchase and processing costs. The cost to refiners is related to the
market share through some standard, powerful economic theory. Each crude type
has a distinct cost and therefore competitiveness that is in part affected
determined by its GHG intensity. As the carbon price changes, or equivalently,
as the value of carbon changes in the FQD compliance regime, the
competitiveness of the crude alters.
The model was used to estimate the
sensitivity of costs and markets shares to a change in carbon price. It showed
how the competitiveness of each crude type was affected by a change in the
carbon price. The output was a marginal cost curve which shows the reduction in
upstream emissions associated with crude imports as the carbon price increased.
The advantage of this approach is that, in
contrast to exogenous restrictions on certain crudes, a combination of cost
effectiveness and GHG intensity determines imports of crudes. 

24.2.2    Biofuels

The Renewable Energy Directive demands a
certain use of biofuels which will be subtracted from total fuel demand.
Further biofuel uptake as a result of the FQD was analysed as follows. The work
constructed compliance cost curves, which show the achievable absolute
emissions reduction in MtCO2e at each unit abatement cost in €/tCO2e
for each relevant abatement option under each compliance option. The abatement
options include biofuels and UERs under compliance options B1 and B2 and
biofuels, UERs, crude and product switching under compliance options C, D1/D2
and E.

24.2.3    Product switching (imports of finished products)

Diesel and gasoline imports have varying
carbon intensities dependent on their source material, be it bitumen,
conventional crude oil or gas to liquids. These imports currently command a
market share in Europe which reflects their relative competitiveness. As the
price of CO2 increases, the relative competitiveness of these
imports will change, resulting in gains or losses in market share. Vivid
Economics’ modelling estimated the changes in product imports for a range of CO2
prices. The combined effect of biofuels uptake and product switching on
emissions was tabulated as a marginal abatement curve across this range of CO2
prices.

24.2.4.   Upstream emissions reductions 

There are CO2 cost estimates
available for upstream emissions reductions and these activities have no direct
effect on fuel production. The magnitude and unit cost of these opportunities,
as developed by ICF, was added to the overall MACC resulting from the biofuels,
product and crude switching modelling.

24.2.5.   Overall marginal compliance cost curve

Once the cost estimates for each compliance
measure had been assembled, it was possible to compare them against other
estimates of compliance costs, such as those prepared by Wood MacKenzie for
Europia, as far as those parties agreed to share their estimates with Vivid
Economics.
The next step was to combine the individual curves into a single marginal
compliance cost covering crude switching, biofuels uptake and flare reduction.
This involved the inter-collation of the components of the individual curves
into a single curve. This overall curve showed the carbon price at which the
FQD target was satisfied, and an indication of the mix of abatement options that
were taken in response to the FQD. Once this carbon price had been found, it
was fed back into the models to generate estimates of impact for a range of
metrics.

25.3.            
Explanation of modelling method
24.3.1. Explanation
of crude switching 

Crude switching is undertaken for each EU
refinery and forms part of the abatement options available to each EU refinery.
EU refineries can switch crudes used to produce finished products under some of
the policy options. Any switch in the crudes used by EU refineries as a consequence
of the FQD is based on the relative competitiveness of each crude. This
competitiveness is based on the current market share and GHG intensity of each
crude. The GHG intensity required for this analysis is from ‘well to refinery
gate’, as provided by ICF, and not a ‘well to wheel’, lifecycle, measurement.
Vivid Economics modelled the
competitiveness of crudes by taking the current import shares by crude and uses
a model to impute their costs to refiners (combined purchase and processing
costs). Each crude had a distinct cost and therefore competitiveness that also
reflects its GHG intensity.
Vivid Economics estimated the change in
crude cost under a shadow carbon price. This creates a competitiveness impact,
raising the cost of importing all crudes, but raising the cost of some more
than others. The model estimates the redistribution of market shares between
crudes, with reductions in market share occurring for the higher carbon crudes
and gains in market share for lower carbon crudes. The output is a curve
showing the reductions in total upstream emissions associated with crude
imports for increases in the carbon price.
The work looked at the competitiveness of
crudes for the overall EU refining industry and did not match crudes to
individual refineries.

24.3.2.   Explanation of product switching 

Product switching is defined as changing
the imports of finished products outside the EU based on the underlying crudes
used to produce these finished products outside the EU. Product switching is
considered in the model together with biofuel blending and EU refinery
production as all three involve finished products. The relative competitiveness
of different sources of imports in the EU will determine the effect of the FQD
on imports. This might induce product switching, that is a relative decline in
the import of fuels derived from unconventional sources and a relative increase
in the import of conventional crudes.
Importers were grouped similarly to crude
imports, that was between conventional and unconventional and by individual
carbon intensities. Importer competitiveness was treated in the same way as
refinery competitiveness.

24.3.3    Pedigree of the model

The issues to be taken into account in this
work and the economic relationships that are important are described in the
inception report. The model used is a standard industrial organisation
treatment of oligopolistic competition between firms. Information on market
demand and firm output and margin levels are used to set up the model before
introducing changes in costs or demand. The model is solved algebraically,
rather than numerically, and is built in Excel. Vivid Economics had used
similar models in other sectors such as glass and aluminium and petrochemicals.
Vivid Economics has experience using this approach
in work on refinery operations:
–    
the modelling of crudes
shows a good fit between crude market share globally and cost of crude
extraction and transport;
–    
the distribution of
refinery margins across the EU portfolio fits well the anonymised data on margins
at refinery level;
–    
the model has been used
to predict exit of refineries in US and the EU;
–    
the model has been used
to examine refinery investment strategies. 
No work has been done to corroborate the
model against historic market events.

25.4.            
Establish where compliance costs fall, that is,
see whether traders or refiners bear it

Traders have only a market intermediary
position, that is, they hold, in contrast to refiners, no major assets affected
by the FQD, they simply reduce the transaction costs of trading through
specialisation. The compliance costs fall on traders, fuel producers, crude and
imported finished product suppliers, and on consumers.
The compliance costs appear as changes in
margin and changes in output for refiners, and the same metrics for crude and
product suppliers. Consumers experience changes in price and changes in
consumption. These changes were estimated and the magnitude of costs facing
each party was set out.
Building on previous work in EU taxation
and a literature survey of cost pass-through, Vivid  Economics took the final
cost and price increase in the fuel production market resulting from the FQD
and calculated the final pump price by using cost pass through and margin
estimates per Member State.

25.5.            
Construct cost curves for each policy option

For each of the policy options, Vivid
Economics models the costs and impacts for fuel suppliers, which are EU
refineries and importers of finished products, depending on the available
abatement options.
In addition, individual crudes and biofuels,
individual upstream emissions reductions and individual refineries will be
modelled. The modelling of compliance cost curves was not carried out at
supplier level, but the results of the modelling were used to estimate the
take-up of compliance measures by the aggregate of suppliers under each of the
compliance options. 
Although impacts are modelled at an
individual crude, product and refinery level, which could allow reporting (for
refineries) for each Member State, there is a reason for choosing a higher
level of aggregation. The modelling method and data used for this work is
appropriate for estimating general market effects, levels and distributions of
impact. It is not designed to give verifiable impacts at individual asset
level, where special circumstances which are not picked up in the model may be
important. For example, when some refineries are closed in the first step of
the work, it is uncertain which refineries would be the ones to close. Since
some Member States have a small number of refineries or even a single refinery,
the reporting of exit of capacity for that Member State would inappropriately
suggest a level of precision which the results will not carry. In addition,
there would be a concern that by reporting figures for all Member States, the
impacts on individual firms could be extracted in some cases. This might be
market sensitive and it is not our intention to present information which can
be taken up by financial market analysts and applied to individual firms. Thus
the output metrics are presented at EU level and for regional groupings of
Member States chosen to avoid disclosure of individual firm or asset
information. 

26.                  
Annex XVI: Summary of ILUC sensitivity
assessment

As explained in
section 2.6.4, on-going discussions on a legislative proposal for mitigating
against indirect land use change may lead to a reduction in the consumption of
biofuels in 2020 which could have significant impacts on the analysis of the
options. In order to better understand the potential magnitude of the reduced
contribution under the most extreme option (i.e. the inclusion of the ILUC
estimated emissions in the greenhouse gas emissions performance of biofuels)
being considered in the comparison of the options presented here, this was
included in the analysis conducted for the Commission[171]. 
As a result of
the introduction of ILUC factors in the sustainability criteria reduced the
amount of conventional biodiesel and inefficient bioethanol pathways that can
be counted towards the FQD. This gap is further widened as the performance of
all land using biofuels is reduced through the inclusion of the estimated
indirect land use change as the performance of biofuels. This means that the
total emission reductions needed to achieve the FQD increase almost fivefold
from 10Mt CO2 to 48Mt CO2. This results in much larger
contributions needed from all different available carbon abatement tools (i.e.
better performing biofuels, upstream emission reductions and replacing higher
intensity with lower intensity products) which increase marginal carbon
abatement costs significantly due to the higher demand for abatement tools
(from 6-7.7 euros per ton in the non ILUC to around 129-145 euros per ton). 
The key results
from such analysis highlight a number of interesting facts[172],
·      
There is little difference in overall trends in
both cases (ILUC and non-ILUC). All options lead to a more accentuated trend in
more petrol and less diesel being consumed driven by higher marginal abatement
costs. This is due to the fact that a) petrol has slightly lower GHG intensity
than diesel and b) that there is a larger share of biofuels from bioethanol
from maize, as well as waste and second generation biodiesel.
·      
There is very little difference between options
in both cases (ILUC and non-ILUC) in terms of abatement tools used. The
increased abatement costs caused by moving from non-ILUC to ILUC scenario leads
to a larger contribution from additional biofuel blending (10Mt CO2),
a much higher contribution from upstream emission reductions (37Mt CO2),
and accentuates the switching from unconventional to conventional sources for
those options where disaggregation is possible. 
·      
The key difference between options in both cases
(ILUC and non-ILUC) seems to be in terms of the fossil fuel mix that the different
options are driving. It is worth noting that disaggregated options lead to most
unconventional crudes not being consumed at all, with the exception of
Venezuelan natural bitumen (i.e. whose consumption is reduced only in part due
to being the most cost competitive unconventional fuel). In addition,
disaggregation leads to a stronger increase in EU refining of conventional
diesel vs imports of Russian and North America that decrease, given that the
latter group tend to have overall a higher GHG intensity. 
·      
 Administrative costs increase very slightly
under the ILUC scenario for all options due to the increased amount from
additional certification costs of the upstream emission projects. Nevertheless
the bulk of the increase in costs comes from additional compliance measures
being taken up, which increase to around 1600 million euros, which should be
seen as a moderate increase (pre-tax market costs of 0.5 cents per litre) in
the context of volumes of fuels being supplied. There is no significant differences
between the options in terms of either administrative or compliance costs.
·      
 As in the non-ILUC scenario, no significant
difference is expected between the options according to pump price impacts
under the ILUC scenario. As such, there is no difference in terms of impacts on
the competitiveness of EU refineries between the options. 

27.                  
Annex XVII: Projected road fuel mix 2020 for
each option (non-ILUC scenario) (Source: Vivid
Economics)

 Fuel || Feedstock || Option B1 || Option C || Option D || Option E 
 PJ || Mt CO2e || PJ || Mt CO2e || PJ || Mt CO2e || PJ || Mt CO2e 
 Petrol || Conventional crude || 2657 || 234.1 || 2660 || 232.9 || 2658 || 232.8 || 2658 || 232.8 
 Natural bitumen (Venezuela to EU) || 68 || 6.0 || 67 || 7.2 || 67 || 7.2 || 67 || 7.2 
 Oil shale || 2 || 0.2 || 0 || 0.0 || 1 || 0.1 || 1 || 0.1 
 Subtotal || 2727 || 240.2 || 2727 || 240.1 || 2725 || 240.0 || 2726 || 240.1 
 Diesel || Conventional crude (subtotal) || 6515 || 587.9 || 6550 || 585.4 || 6558 || 586.1 || 6549 || 585.4 
 Conventional crude (EU refined) || 4700 || 424.1 || 4728 || 422.5 || 4730 || 422.8 || 4724 || 422.2 
 Conventional crude (import USGC) || 167 || 15.1 || 169 || 15.1 || 169 || 15.1 || 169 || 15.1 
 Conventional crude (import Russia) || 1648 || 148.7 || 1653 || 147.7 || 1658 || 148.2 || 1656 || 148.0 
 Natural bitumen (Venezuela to EU) || 169 || 15.3 || 168 || 18.2 || 168 || 18.3 || 168 || 18.3 
 Natural bitumen (Canada to USGC) || 21 || 1.9 || 0 || 0.0 || 3 || 0.4 || 0 || 0.0 
 Oil shale || 4 || 0.4 || 1 || 0.1 || 1 || 0.2 || 1 || 0.2 
 CTL || 19 || 1.7 || 19 || 3.2 || 19 || 3.2 || 19 || 3.2 
 GTL || 62 || 5.6 || 53 || 5.2 || 55 || 5.4 || 53 || 5.2 
 Subtotal || 6790 || 612.8 || 6790 || 612.1 || 6805 || 613.6 || 6791 || 612.2 
 LPG ||   || 208 || 15.3 || 208 || 15.3 || 208 || 15.3 || 208 || 15.3 
 CNG ||   || 44 || 3.4 || 44 || 3.4 || 44 || 3.4 || 44 || 3.4 
 Electricity || EU-average || 87 || 3.9 || 87 || 3.9 || 87 || 3.9 || 87 || 3.9 
 Ethanol || Corn (maize) || 29 || 0.9 || 29 || 0.9 || 29 || 0.9 || 29 || 0.9 
 Sugar beet || 40 || 1.1 || 40 || 1.1 || 40 || 1.1 || 40 || 1.1 
 Sugar cane || 103 || 2.1 || 103 || 2.1 || 103 || 2.1 || 103 || 2.1 
 Wheat Process fuel not specified || 15 || 0.7 || 15 || 0.7 || 15 || 0.7 || 15 || 0.7 
 Wheat Natural gas as process fuel in CHP plant || 15 || 0.7 || 15 || 0.7 || 15 || 0.7 || 15 || 0.7 
 Wheat Straw as process fuel in CHP plant || 15 || 0.4 || 15 || 0.4 || 15 || 0.4 || 15 || 0.4 
 2G ethanol - land using || 10 || 0.2 || 10 || 0.2 || 10 || 0.2 || 10 || 0.2 
 2G ethanol - non-land using || 10 || 0.1 || 10 || 0.1 || 10 || 0.1 || 10 || 0.1 
 Subtotal || 236 || 6 || 236 || 6 || 236 || 6 || 236 || 6 
 Biodiesel || 2G biodiesel - land using || 15 || 0.1 || 15 || 0.1 || 15 || 0.1 || 15 || 0.1 
 2G biodiesel - non-land using || 15 || 0.1 || 15 || 0.1 || 15 || 0.1 || 15 || 0.1 
 Waste 1st. Gen. Diesel || 62 || 0.6 || 62 || 0.6 || 51 || 0.5 || 62 || 0.6 
 Palm oil || 82 || 4.2 || 82 || 4.2 || 82 || 4.2 || 82 || 4.2 
 Palm oil with methane capture || 82 || 2.4 || 82 || 2.4 || 82 || 2.4 || 82 || 2.4 
 Rapeseed || 385 || 15.4 || 385 || 15.4 || 385 || 15.4 || 385 || 15.4 
 Soybean || 105 || 4.9 || 105 || 4.9 || 105 || 4.9 || 105 || 4.9 
 Sunflower || 40 || 1.3 || 40 || 1.3 || 40 || 1.3 || 40 || 1.3 
 Subtotal || 787 || 29 || 787 || 29 || 775 || 29 || 787 || 29 
 Total || 10879 || 910.6 || 10879 || 909.9 || 10880 || 911.1 || 10879 || 910.0 

28.                  
Annex XVIII: General considerations around
environmental impacts associated with fossil fuel production (Source: JRC)
28.1.            
Environmental impacts: general considerations

The impacts of fossil fuels on the
environment result from the sum of upstream activities (extraction, including
exploration and production, followed by transportation by tanker or pipeline);
mid-stream activities (refining), and downstream activities (transportation by
tanker, pipeline or rail to marketing terminals and bulk plants and eventually
service stations and commercial accounts). 
The FQD objective refers to GHG intensity
of fossil fuels including those produced using production methods that are
energy intensive or involve practices that result in higher emissions.
Therefore such fuels do include unconventional sources (e.g. tar sands, coal,
oil shale), heavy oils, as well as conventional sources some of which may
require additional energy for crude oil recovery or use practices that result
in larger emissions (e.g. Nigerian crudes with flaring, Middle East and
California thermal enhanced oil recovery).
Figure 9: Crude Oil Life Cycle (Source:
JEC Well-to-Wheels Study, 2011)
Environmental impacts of fossil fuels
necessarily refer to lifecycle or “well-to-wheel” (WTW), i.e. those associated
with oil recovery, upgrading, transport, refining, distribution, and combustion
emissions. “Well-to-tank” (WTT) refers to emissions upstream of the vehicle
tank while “Tank-to-wheel” (TTW) refers to the in-vehicle combustion emissions.

In view of the FQD reporting mechanism
mandated by Article 7a of the FQD, the TTW segment is not relevant. For that
reason throughout this annex, WTT environmental impacts are considered.
It is worth noting that the attention of
researchers and governments alike is certainly focused on regulating/reducing
carbon-intensity of crude oils and fossil fuels, typically expressed as CO2e
per MJ[173].
There is a considerable wealth of information on this matter despite existing
differences largely due the use of different data sources, methods, lifecycle
boundaries, and assumptions used, making comparisons of results a challenging
issue. 
It is equally worth highlighting that crude
oil resources around the world vary significantly in regard to resource quality
and production methods. Thus, this annex does not intend to compare across types
of crudes because the results of such a comparison vary substantially in
function of which crudes are used as a reference and/or which crudes are
evaluated to determine a baseline. Indeed, results would be different if the
terms of comparison were ‘any specific crude type’ vs. an average of all crudes
consumed in the EU or ‘any specific crude type’ vs. the crudes it is most
likely to displace. 
Being relatively poor of resources, the EU
relies on foreign resources to meet its energy needs. The environmental effects
of expanding exploitation therefore fall largely outside its territory,
nevertheless implying a growing global footprint for the EU. Increasing
scarcity of, or other types of restrictions to use, fossil fuels may stimulate
greater efforts to shift to other energy sources that can be – at least
partially – found domestically, including turning to sources previously deemed
uneconomic. 
This may have various effects on Europe's environment, including increased land use for biofuels, disruption of ecosystems
from developing additional hydropower capacity, noise and visual pollution from
wind turbines. Expanding nuclear energy capacity may be expected to trigger
public debate about waste storage and safety risks.
Attention dedicated, and data are available,
to non-GHG concerns surrounding crude oils and fossil fuels’ production is
typically focused on the assessment of developments/projects in specific
contexts. This allows carrying out detailed analyses taking into account – and
rightly so – the specificities of different crude types and different impacted
environmental contexts.
Due to the general scope of this note, it
provides an overview of the main environmental impacts of fossil fuels without
providing specific assessments on any given crude type. 

28.2.            
Air quality impacts

Air emissions associated with oil and gas
production can impact air quality and impair visibility. 
Air emissions generated during oil and gas
production can be grouped into three categories:

 Air pollutants
     (ozone, carbon monoxide, sulphur dioxide, particulate matter, and their
     precursors, including nitrogen oxides and Volatile Organic Compounds);
 Haze
     precursors (including ozone, NOx, SO2, and PMs); and
 Greenhouse
     gases (GHGs, including CO2 and methane CH4) are generated during oil and
     gas development. 

OGP member
companies reported in 2011 that: 

 Normalised CH4
     emissions increased in 2011 by 6% compared with 2010;
 Normalised NOx
     emissions increased in 2011 by 3% compared with 2010, and;
 Normalised
     CO2, SO2 and NMVOC emissions remained stable compared with 2010.

Leaving aside GHG, including ozone as one
of the GHGs, the emissions of primary sub-10µm particulate matter (PM10) have
reduced by 26% across Europe between 1990 and 2010, driven by a 28% reduction
in emissions of the fine particulate matter (PM2.5) fraction. 
Emissions of particulates between 2.5 and
10 µm have reduced by 21% over the same period; the difference of this trend to
that of PM 2.5 is due to significantly increased emissions in the 2.5 to 10 µm
fraction from 'Road transport' and 'Agriculture' (of 50% and 15% respectively)
since 1990. Of this reduction in PM 10 emissions, 39% has taken place in the
'Energy Production and Distribution' sector due to factors including the
fuel-switching from coal to natural gas for electricity generation and
improvements in the performance of pollution abatement equipment installed at
industrial facilities.
Figure 11: Contribution per sector to
emissions of primary PM2.5 and PM10 in 2010.
Figure 12: The contribution made by each
sector to the total change in primary PM2.5 and PM10 emissions respectively
between 1990 and 2010. (Source: UNECE National emissions reported to LRTAP
Convention)
Beyond general information, the relevant
issue here is: would these levels of emissions be influenced depending on the
policy option chosen to implement the reporting mechanism mandated by FQD Art.
7a. 
It seems reasonable to conclude that a
marginal influence only of such reporting mechanism on air quality impacts
beyond the GHG component can be expected. 
In fact, despite projected overall growth
of GHG emissions with energy demand offsetting the impacts of technological
improvements for transportation fuels, sulphur and nitrogen emissions are
expected to fall by a quarter to a third from today’s levels thus continuing
last decade’s trend.
Figure 13: Time series of the average ppm
of sulphur in fuels in the EU27 countries (Source: EEA)
At the midstream segment and given the
progress that refineries have made in the abatement of sulphur emissions to
air, the focus of technology improvement is progressively shifting towards
volatile organic compounds, particulates (size and composition) and NOx, as in
the environmental debate generally.
Refinery processes require a lot of
energy; typically more than 60 % of refinery air emissions are related to the
production of energy for the various processes. 
Figure 14 Main air pollutants emitted by
refineries and their main sources (Source: IPPC Bureau, BREF on Mineral Oil and
Gas Refining, 2003).
Very different is the situation of methane
where atmospheric concentrations have been rising steadily. Despite the
recognition that fossil fuel upstream and midstream emissions share the
contribution to this trend with a number of other emissions’ sources, it is
certainly a key contributor. 
Figure 15: Time series of the average ppb
atmospheric concentration of methane in the EU 27 countries (Source: EEA).
Figure 16: Methane emissions per unit of
production (tonnes per thousand tonnes of hydrocarbon production) (Source: OGP,
2011).
Flaring produces predominantly carbon
dioxide emissions, while venting produces predominantly methane emissions. The
global warming potential (GWP) of methane is estimated to be 25 times that of
CO2 when the effects are considered over one hundred years. Although methane is
certainly one of the GHGs and is therefore included in the impacts analysis
dedicated to GHGs in this impact assessment, it is worth highlighting in this
section as well that the FQD Art.7a reporting mechanism is reasonably expected
to exert its effects on fuel suppliers to reducing flaring and venting in
fossil fuel production.
OGP reports that in 2011 15.7 tonnes of gas
was flared every thousand tonnes of hydrocarbon produced versus 16.0 tonnes in
2010 and 17.9 in 2009. Reductions in flaring rates are predominantly driven by
major infrastructure improvement projects that increase the capability to
inject gas for reservoir maintenance and to deliver gas to markets.
Figure 17: Flaring per unit of hydrocarbon
production (tonnes per thousand tonnes) as reported by OGP member companies by
region (Source: OGP 2011)
It is also worth highlighting that VOC
emissions come largely from flaring and venting (together representing ¾ of
total reported sources for VOCs) the remainder coming from fugitive emissions
and only to a very minor extent are attributable to energy use.

28.3.            
Pressures on biodiversity

Within the EU territory, habitat changes —
including loss, fragmentation and degradation — impose the greatest impacts on
species. Grasslands and wetlands are in decline, urban sprawl and
infrastructure fragment the landscape, and agro-ecosystems are characterised by
agricultural intensification and land abandonment. 
Relevant considerations when thinking of
fossil fuel production and threats to biodiversity address mainly soil and
water pollution and changing agricultural practices, including land-use change.
Agricultural intensification means decreased crop diversity, simplified
cropping methods, fertiliser and pesticide use, and homogenised landscapes:
biofuel crops may intensify fertiliser and pesticide use, exacerbating
biodiversity loss. Industrial chemicals do end up in the soil or in water and
although nitrate and phosphorus pollution of rivers and lakes is declining, NOx
emissions are still an outstanding issue across the EU.
Fossil fuel production and distribution
therefore do not belong to the key drivers for biodiversity loss. Nevertheless,
there are points of intersection. Key areas where the biodiversity issue and petroleum
industry activities overlap are: access, indigenous populations, and alien
invasive species.
·        
“Access” issues
include those surrounding land in general, marine and coastal areas, and
transportation routes. Bilateral agreements may also choose to enforce
stringent requirements on site habitat restoration/rehabilitation once a
company has moved out of an area.
Access to land
for oil and gas activities is increasingly subject to regulation through
multilateral or bilateral treaties, including restrictions on existing
operations if the industry cannot demonstrate its ability to operate within a
small footprint and minimal impacts.
Marine and
coastal access is typically regulated by international agreements and mandates
calling for the expansion and strengthening of coastal and marine protected
areas. Initiatives such as the International Coral Reef Initiative affect the
way the petroleum industry operates in the oceans and transports its products
worldwide.
Transportation
routes are also impacted by regulation on biodiversity through – for example –
sensitivity mapping and oil spill contingency plans which are addressed in the
context of conservation. This has led to tanker routes being restricted in
certain areas, such as the Great Barrier Reef, Australia.
·       
Many of the areas having the highest interest
for the petroleum industry and at the same time the highest levels of
biodiversity are in low or middle income countries where natural resources can
be crucial to the livelihoods of the inhabitants. There is increasing emphasis
on the impacts of petroleum industry activities on indigenous organisations
by fostering a participatory approach. 
·       
The colonisation of new areas by species from
outside the immediate environment is an important ecological process taking
place naturally. Anthropogenic activities though contribute to increasing the
number and rate of species introductions worldwide, enabling species to become
established in areas that they would not ordinarily be able to reach. When
species become established outside their natural range as a result of human
activity and threaten biodiversity, they are defined as “alien invasive
species”. The diversity of these species range from micro-organisms to
mammals and comprise both animal and plants in all sorts of ecosystems. It has
become acknowledged that alien invasive species represent a key threat to
global biodiversity, including the survival of species of commercial
significance (e.g. fisheries). Indirect ecological disturbance, relating mainly
to habitat degradation and the direct introduction of alien invasive species
often happen concurrently. The petroleum and gas industry has a potential
impact on creating indirect pathways for alien invasive species, namely because
it often works in remote areas with little or no previous human activity,
moving specialized equipment and personnel between sites and developing
large-scale linear features (e.g. pipelines). These characteristics set it
apart from many other sectors and increase the likelihood and potential
severity/consequences of invasion if appropriate measures are not implemented.
The business case for oil and gas companies to address this aspect of
biodiversity safeguarding relates mostly to legal compliance with requirements
in national law systems rather than with the type/quality of the energy source
and the resulting product(s). 
Despite recognition of points of
intersection between biodiversity and activities of the petroleum industry,
quantitative data and analyses are scarce with the relevant exception of oil
spills at sea. Limited information is available on infrastructure impacts and
maintenance (pipelines and oil port terminals) and this is certainly not linked
to the GHG intensity of any specific crude or finished fossil product via
different technological options.

28.4.            
Efficient use of resources: water

There is growing recognition that energy
and water are closely linked. Water is used in every step of fossil-fuel
extraction and processing. Oil refining requires approximately 4 to 8 million
m3 of water daily in the United States alone (the amount of water that two to
three million U.S. households use daily). Despite growing interests for water
demand by the energy industry, information on the impacts on water quality is
scattered. This is partly because water is used in different ways during
extraction and processing and can therefore be contaminated by different
pollutants (from sediment to synthetic chemicals) but also groundwater, rivers
or lakes can be contaminated by solid or liquid wastes resulting from
extraction.
Aside of ordinary operations for fossil
fuels extraction, accidents in the form of spills and other disasters
associated with the extraction process are another source of water
contamination. 
 
Water brought to the surface through mining
or drilling, called “produced water,” can contain dissolved salts, trace
metals, hydrocarbons, and radionuclides. Produced water is a by-product of oil
and gas production from reservoirs. Oil and gas reservoirs contain a mixture of
oil, gas and water at equilibrium: a small proportion of the hydrocarbons will
be dissolved in water depending on their solubility. Therefore, there is a
dissolved hydrocarbon component in the produced water consisting typically of
light aromatic hydrocarbons (due to their relatively high solubility) in
addition to suspended oil droplets. 
Figure 18: Water inputs and outputs for
crude oil production (Source: Argonne National Laboratory, 2009).
The treatment processes for separation of
oil and water before discharge of the produced water have traditionally been
based on the difference in specific gravity between oil droplets and water. The
oil droplets will generally float to the top of the water where they can be
removed. Gravity treatment methods are not able to remove dissolved hydrocarbon
components though. At wastewater treatment plants at refineries or other
facilities dealing with significant quantities of hydrocarbons, biological
treatment (breakdown by micro-organisms) is the best means of breaking down and
removing the dissolved hydrocarbons. This option is not available at offshore
oil and gas installations. 
The discharge of produced water from
offshore installations has been addressed by the OSPAR Commission[174], including setting
limits to the total amount of waste water permitted to be discharged. Treatment
technologies, including produced water re-injection and the types of
hydrocarbons contained in produced water are monitored and regularly updated.
Figure 19: Oil discharged in produced
water per unit of production (tonnes per million tonnes of hydrocarbon
production). (Source: OGP, 2011).
 
 ESTIMATES OF GLOBAL INPUTS OF OIL TO THE MARINE ENVIRONMENT   In a report published in 2002 by the National Research Council (NRC) of the U.S. National Academy of Sciences, the average total worldwide annual release of petroleum (oils) from all known sources to the sea has been estimated at 1.3 million tonnes. However, the range is wide, from a possible 470,000 tonnes to a possible 8.4 million tonnes per year. According to the report, the main categories of sources contribute to the total input as follows: natural seeps: 46% discharges from consumption of oils (operational discharges from ships and discharges from land-based sources): 37% accidental spills from ships; 12% extraction of oil: 3%   The Australian Petroleum Production and Exploration Association (APPEA) claims the following distribution of the inputs from different sources: Land-based sources (urban runoff and discharges from industry): 37% Natural seeps: 7% The oil industry - tanker accidents and offshore oil extraction: 14% Operational discharges from ships not within the oil industry: 33% Airborne hydrocarbons: 9%   (Source: UNEP GPA Clearing-House Mechanism) 
During the refining phase, water is
used intensively as process water and for cooling purposes. Its use
contaminates the water with oil products mainly increasing the oxygen demand of
the effluent. 
Figure 20: Water inputs and outputs for
biofuel production and oil refining (Source: Argonne National Laboratory,
2009).
Refineries discharge waste water
which originates from:

 Process water,
     steam and wash water. These waters have been in contact with the process
     fluids, and apart from oil, will also have taken up hydrogen sulphide
     (H2S), ammonia (NH3) and phenols. The more severe the conversion
     processes, the more H2S and NH3 are taken up by the process water. The
     process water is treated before discharge to the environment.
 Cooling water,
     once-through or circulating systems. This stream is theoretically free of
     oil. However, leakage
  into once-through
     systems, even at low concentrations, can result in significant mass losses
     because of the large volume of water involved.
 Rainwater from
     process areas. This type of water has not been in contact with the process
     fluids, but it comes from rainfall on surfaces which are possibly
     oil-polluted. It is often referred to as ‘accidentally oil-contaminated’
     water and is typically treated prior to discharge to the environment.
 Rainwater from
     non-process areas. This stream is oil-free.

Oil and hydrocarbons are the main
pollutants found in waste water generated by refineries but also other
pollutants are found in waste water generated by refineries, as listed below.
Refinery waste water treatment techniques are mature techniques, and emphasis
has now shifted to prevention and reduction. 
Figure 21: Main water pollutants generated
by refineries and their main sources (Source: IPPC Bureau, BREF on Mineral Oil
and Gas Refining, 2003, based on CONCAWE Best available techniques to reduce
emissions from refineries, 1999).
References
used
ANL – “Consumptive Water Use in
the Production of Ethanol and Petroleum Gasoline”, 2009
EEA – “The European Environment State and Outlook (SOER) 2010”, 2011
EEA – “Biodiversity – SOER
Thematic Assessment 2010”, 2011
EEA – “Emissions of primary
particulate matter and secondary PM precursors, CSI 003 Assessment”, 2012
EEA – “Absolute and Relative Gaps
between Average 2008–2011 non-ETS Emissions and Kyoto Target for non-ETS
Sectors”, 2012 
IPIECA – “Biodiversity and the
Petroleum Industry”, 2000
IPIECA, OGP - “Alien Invasive
Species and the Oil and Gas Industry”, 2010
JRC – “Integrated Pollution
Prevention and Control (IPPC), Reference Document on Best Available Techniques
for Mineral Oil and Gas Refineries”, 2003
JRC - “Unconventional Gas:
Potential Energy Market Impacts in the European Union”, EUR 25305 EN, 2012
Lattanzio, R. K. - “Canadian Oil
Sands: Life-Cycle Assessments of Greenhouse Gas Emissions”, US Congressional
Research Service, 2013
OECD - “Environmental Outlook to
2030”, 2008
OGP - “Aromatics in Produced
Water: Occurrence, Fate & Effects, and Treatment”, 2002
OGP - “Environmental Performance
Indicators. 2011 data, 2012
UNEP – GPA, http://gpa.unep.org    

29.                  
 Annex XIX: Detailed
information on administrative costs (Source: ICF)
  
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Regulation Review || All suppliers || 904 || Annualised over 10 years || Hour || € 70/hour || 15 || € 1,050 || € 129 || € 117,028 
 Verification -  development of a EU harmonised assurance standard || All EU refineries || 1 || Delegated responsibility from the MS. Part of the cost borne by the MS || / || / || / || / || / || € 2 – 3 million 
 UER Projects – pre-registration cost || UER projects || 4 || Once off cost per project – low estimate || / || / || / || € 31,000 || € 3,822 || € 15,288 
 4 || Once off cost per project – high estimate || / || / || / || € 116,500 || € 14,363 || € 57,454 
 UER Projects – post registration costs || UER projects || 4 || Annual cost per project – low estimate || / || / || / || € 7,750 || € 7,750   || € 31,000 
 4 || Annual cost per project – high estimate || / || / || / || € 15,500 || € 15,500 || € 62,000 
Table 11: MRV costs under Option B1 for
suppliers
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Periodical update of data required for the calculation || EC || 1 || Occur every 10 years || FTE || € 60,000 || 1/6 || € 10,000 || € 1,233 || € 1,233 
 UER Projects – verification and validation || EC || 1 || Costs are covered by the administrative fees || / || / || / || / || / || / 
 MS - Gathering and reporting data to the EC || 27 MS || / || Annual cost Low estimates || Person-day || € 157 || 51 || € 8,007 || € 8,007 || € 8,007 
 Annual cost High estimates || Person-day || € 157 || 76 || € 11,932 || € 11,932 || € 11,932 
 EC – Processing and analysis of data || EC || 1 || Based on reporting costs ||   ||   ||   ||   ||   || € 4,000 
 € 5,500 
Table 12: MRV costs under Option B1 for
public authorities
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Regulation Review || All suppliers || 904 || Annualised over 10 years || Hour || € 70/hour || 15 || € 1,050 || € 129 || € 117,028 
 Development of internal tool / spread sheet || Simple refinery || 87 || Annualised over 10 years || Hour || € 70/hour || 40 || € 2,800 || € 345 || € 30,034 
 Hour || € 70/hour || 80 || € 5,600 || € 690 || € 60,067 
 Complex refinery || 42 || Annualised over 10 years || Hour || € 70/hour || 80 || € 5,600 || € 690 || € 28,998 
 Hour || € 70/hour || 160 || € 11,200 || € 1,381 || € 57,996 
 Maintaining internal tool / spread sheet || Simple refinery || 87 || Annual cost Daily / weekly activity || Hour || € 70/hour || 260 || € 18,200 || € 18,200 || € 1,583,400 
 Complex refinery || 42 || Annual cost Daily / weekly activity || Hour || € 70/hour || 520 || € 36,400 || € 36,400 || €1,528,800 
 Verification -  development of a EU harmonised assurance standard || All EU refineries || 1 || Delegated responsibility from the MS. Part of the cost borne by the MS || / || / || / || / || / || € 2 – 3 million 
 Internal and external verification || Simple refinery || 87 || Averaging cost of internal and external auditing || Hour || € 70/hour || 15 || € 1,050 || € 1,050 || € 91,350 
 Complex refinery || 42 || Averaging cost of internal and external auditing || Hour || € 70/hour || 30 || € 2,100 || € 2,100 || € 88,200 
 Management and transfer of data by fuel traders and verification of this process || Fuel traders active in the EU || 775 || Administrative cost of fuel traders is equivalent to 20% of the costs for EU and non-EU refineries || / || / || / || / || / || €9.1 – 9.3m 
 UER Projects – pre-registration cost || UER projects || 4 || Once off cost per project – low estimate || / || / || / || € 31,000 || € 3,822 || € 15,288 
 4 || Once off cost per project – high estimate || / || / || / || € 116,500 || € 14,363 || € 57,454 
 UER Projects – post registration costs || UER projects || 4 || Annual cost per project – low estimate || / || / || / || € 7,750 || € 7,750 || € 31,000 
 4 || Annual cost per project – high estimate || / || / || / || € 15,500 || € 15,500 || € 62,000 
Table 13: MRV costs under Option C for
suppliers
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Periodical update of data required for the calculation || EC || 1 || Occur every 10 years || FTE || € 60,000 || 1/6 || € 10,000 || € 1,233 || € 1,233 
 UER Projects – verification and validation || EC || 1 || Costs are covered by the administrative fees || / || / || / || / || / || / 
 MS - Gathering and reporting data to the EC || 27 MS || / || Annual cost Low estimates || Person-day || € 157 || 51 || € 8,007 || € 8,007 || € 8,007 
 Annual cost High estimates || Person-day || € 157 || 76 || € 11,932 || € 11,932 || € 11,932 
 EC – Processing and analysis of data || EC || 1 || Based on reporting costs ||   ||   ||   ||   ||   || € 4,000 
 € 5,500 
Table 14: MRV costs under Option C for
public authorities 
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Regulation Review || Refineries, Suppliers, Traders || 904 || Annualised over 10 years || Hour || € 70/hour || 15 || € 1,050 || € 129 || € 117,028 
 Verification -  development of a EU harmonised assurance standard || All EU refineries || 1 || Delegated responsibility from the MS. Part of the cost borne by the MS || / || / || / || / || / || € 2 – 3 million 
 UER Projects – pre-registration cost || UER projects || 4 || Once off cost per project – low estimate || / || / || / || € 31,000 || € 3,822 || € 15,288 
 4 || Once off cost per project – high estimate || / || / || / || € 116,500 || € 14,363 || € 57,454 
 UER Projects – post registration costs || UER projects || 4 || Annual cost per project – low estimate || / || / || / || € 7,750 || € 7,750 || € 31,000 
 4 || Annual cost per project – high estimate || / || / || / || € 15,500 || € 15,500 || € 62,000 
Table 15: MRV costs under Option D for
suppliers (incurred by both opted in and opted out suppliers)

 MRV Actions || Reference actor || Number of actors || Cost per actor || Total annual cost for EU (low) || Total annual cost for EU (high) 
 Assumptions || Cost per actor || Annualised cost per actor(low) || Annualised cost per actor (high) 
 LCA calculation – own measurement || ⅓ opting out producers || 19 || Measured data for 2 stages (extraction and refining) || € 58,000 || € 13,028 || € 30,751 || € 247,539 || € 584,276 
 € 100,950 || € 22,676 || € 53,523 || € 430,846 || € 1,016,943 
 LCA calculation – engineering estimates || ⅓ opting out producers || 19 || Estimation - Engineering || € 70,000 || € 15,724 || € 37,114 || € 298,754 || € 705,161 
 € 93,000 || € 20,890 || € 49,308 || € 396,916 || € 936,856 
 LCA calculation – existing model || ⅓ opting out producers || 19 || Estimation – Existing model (e.g. GREET) || € 11,500 || € 2,583 || € 6,097 || € 49,081 || € 115,848 
 € 23,300 || € 5,234 || € 12,354 || € 99,442 || € 234,718 
 Verification and validation cost || Opting out refineries || 56 || External validation || € 11,500 || € 2,583 || € 6,097 || € 144,660 || € 341,446 
 € 23,300 || € 5,234 || € 12,354 || € 293,093 || € 691,800 
 Development of an internal tool / spreadsheet || Simple refineries || 38 || Annualised over 10 years || € 2,800 - € 5,600 || € 345 || € 690 || € 13,118 || € 26,236 
 Complex refineries || 18 || Annualised over 10 years || € 5,600 - € 11,200 || € 690 || € 1381 || € 12,428 || € 24,855 
 Maintaining an internal tool / spreadsheet || Simple refineries || 38 || Annual cost. Daily / weekly activity || € 18,200 || € 18,200 || € 18,200 || € 691,600 || € 691,600 
 Complex refineries || 18 || Annual cost. Daily / weekly activity || € 36,400 || € 36,400 || € 36,400 || € 655,200 || € 655,200 
 Management and transfer of data by fuel traders, verification of this process || Opted out traders || 378 || Administrative cost of fuel traders is equal to 20% of costs for EU and non-EU refineries ||   ||   ||   || € 6,770,308 || € 13,926,273 
Table 16: Additional MRV costs under
Option D for opted out suppliers
(Low Estimates based on repeated
calculations every 5 years and high estimates based on re-calculations every 2
years)
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Development of internal tool / spread sheet || Simple refinery || 49 || Annualised over 10 years || Hour || € 70/hour || 40 || € 2,800 || € 345 || € 16,916 
 Hour || € 70/hour || 80 || € 5,600 || € 690 || € 33,831 
 Complex refinery || 24 || Annualised over 10 years || Hour || € 70/hour || 80 || € 5,600 || € 690 || € 16,570 
 Hour || € 70/hour || 160 || € 11,200 || € 1,381 || € 33,141 
 Maintaining internal tool / spread sheet || Simple refinery || 49 || Annual cost Daily / weekly activity || Hour || € 70/hour || 260 || € 18,200 || € 18,200 || € 891,800 
 Complex refinery || 24 || Annual cost Daily / weekly activity || Hour || € 70/hour || 520 || € 36,400 || € 36,400 || € 873,600   
 Internal and external verification || Simple refinery || 49 || Averaging cost of internal and external auditing || Hour || € 70/hour || 15 || € 1,050 || € 1,050 || € 51,450 
 Complex refinery || 24 || Averaging cost of internal and external auditing || Hour || € 70/hour || 30 || € 2,100 || € 2,100 || € 50,400 
 Management and transfer of data by fuel traders and verification of this process || Opted in traders || 584 || Administrative cost of fuel traders is equivalent to 20% of the costs for EU and non-EU refineries ||   ||   ||   ||   ||   || €4.7m 
Table 17: Additional MRV costs under
Option D for opted in suppliers
 MRV Actions || Reference actor || Number of actor || Cost per actor || Total annual cost for the EU 
 Assumptions || Measurement unit || Cost per measurement unit || Number of unit || Cost per actor || Annualised cost per actor 
 Periodical update of data required for the calculation || EC || 1 || Occur annually || FTE || € 60,000 || 1/6 || € 10,000 || € 10,000 || € 10,000 
 UER Projects – verification and validation || EC || 1 || Costs are covered by the administrative fees || / || / || / || / || / || / 
 MS - Gathering and reporting data to the EC || 27 MS || / || Annual cost Low estimates || Person-day || € 157 || 51 || € 8,007 || € 8,007 || € 8,007 
 Annual cost High estimates || Person-day || € 157 || 76 || € 11,932 || € 11,932 || € 11,932 
 EC – Processing and analysis of data || EC || 1 || Based on reporting costs ||   ||   ||   ||   ||   || € 4,000 
 € 5,500 
Table 18: MRV costs under Option D for
public authorities

30.                  
Annex XX: Projected road fuel mix 2020 all
options (ILUC scenario) (Source: Vivid Economics)

 Fuel || Feedstock || Option B1 || Option C || Option D || Option E 
 PJ || Mt CO2e || PJ || Mt CO2e || PJ || Mt CO2e || PJ || Mt CO2e 
 Petrol || Conventional crude || 2709 || 238.6 || 2717 || 238.0 || 2703 || 236.7 || 2703 || 236.7 
 Natural bitumen (Venezuela to EU) || 69 || 6.1 || 55 || 5.9 || 55 || 5.9 || 55 || 5.9 
 Oil shale || 2 || 0.2 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Subtotal || 2780 || 244.9 || 2772 || 243.9 || 2759 || 242.7 || 2759 || 242.7 
 Diesel || Conventional crude (subtotal) || 7024 || 633.9 || 7154 || 639.5 || 7169 || 640.8 || 7169 || 640.8 
 Conventional crude (EU refined) || 5067 || 457.3 || 5312 || 474.8 || 5276 || 471.6 || 5276 || 471.6 
 Conventional crude (import USGC) || 180 || 16.3 || 110 || 9.9 || 109 || 9.8 || 109 || 9.8 
 Conventional crude (import Russia) || 1777 || 160.3 || 1732 || 154.8 || 1784 || 159.4 || 1784 || 159.4 
 Natural bitumen (Venezuela to EU) || 167 || 15.1 || 139 || 15.0 || 139 || 15.0 || 139 || 15.0 
 Natural bitumen (Canada to USGC) || 21 || 1.9 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Oil shale || 4 || 0.4 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 CTL || 19 || 1.7 || 19 || 3.2 || 19 || 3.2 || 19 || 3.2 
 GTL || 61 || 5.5 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Subtotal || 7296 || 658.4 || 7312 || 657.7 || 7327 || 659.1 || 7327 || 659.1 
 LPG ||   || 208 || 15.3 || 208 || 15.3 || 208 || 15.3 || 208 || 15.3 
 CNG ||   || 44 || 3.4 || 44 || 3.4 || 44 || 3.4 || 44 || 3.4 
 Electricity || EU-average || 87 || 3.9 || 87 || 3.9 || 87 || 3.9 || 87 || 3.9 
 Ethanol || Corn (maize) || 58 || 2.5 || 58 || 2.5 || 58 || 2.5 || 58 || 2.5 
 Sugar beet || 40 || 1.4 || 40 || 1.4 || 40 || 1.4 || 40 || 1.4 
 Sugar cane || 103 || 3.6 || 103 || 3.6 || 103 || 3.6 || 103 || 3.6 
 Wheat Process fuel not specified || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Wheat Natural gas as process fuel in CHP plant || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Wheat Straw as process fuel in CHP plant || 15 || 0.6 || 15 || 0.6 || 15 || 0.6 || 15 || 0.6 
 2G ethanol - land using || 10 || 0.3 || 10 || 0.3 || 10 || 0.3 || 10 || 0.3 
 2G ethanol - non-land using || 10 || 0.1 || 10 || 0.1 || 10 || 0.1 || 10 || 0.1 
 Subtotal || 236 || 8 || 236 || 8 || 236 || 8 || 236 || 8 
 Biodiesel || 2G biodiesel - land using || 22 || 0.4 || 15 || 0.3 || 15 || 0.3 || 15 || 0.3 
 2G biodiesel - non-land using || 80 || 0.7 || 80 || 0.7 || 80 || 0.7 || 80 || 0.7 
 Waste 1st. Gen. Diesel || 85 || 0.8 || 85 || 0.8 || 85 || 0.8 || 85 || 0.8 
 Palm oil || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Palm oil with methane capture || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Rapeseed || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Soybean || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Sunflower || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 || 0 || 0.0 
 Subtotal || 187 || 2 || 180 || 2 || 180 || 2 || 180 || 2 
 Total || 10837 || 936.2 || 10839 || 934.5 || 10840 || 934.6 || 10840 || 943.6 
[1]               Within the context of the Fuel Quality Directive,
suppliers are defined as the entity that passes the fuel
through the
duty point.
[2]               Directive 98/70/EC.
[3]               With regards to the post-2020 climate and energy
legislative framework, the Commission is of the view that sector specific
sub-targets, such as the FQD, should be discontinued http://ec.europa.eu/energy/doc/2030/com_2014_15_en.pdf
[4]               Directive 2009/30/EC includes mandatory
sustainability criteria aimed at preventing the conversion of land
characterised by high carbon stock and high biodiversity for biofuel
production, as well as requiring biofuels to achieve minimum greenhouse gas
emission savings compared to fossil fuels. Biofuels need to comply with these
criteria in order to be counted towards the targets and qualify for public
support. These criteria are also included in the Renewable Energy Directive
2009/28/EC.
[5]               Directive 2009/30/EC, Article 7a(5).
[6]               Annex 3 and 4 of the 2011 proposal: 
http://ec.europa.eu/transparency/regcomitology/index.cfm?do=search.documentdetail&XOvfOQKYHt67nl0gDR9EQ0pDU4MfDGIJHglKuEmrBsRhxbx1TISJ2Mfg5DtxY23N
[7]               All analysis and policy discussions referenced in
this report predate the accession of Croatia to EU Membership in July 2013. 
[8]               https://circabc.europa.eu/faces/jsp/extension/wai/navigation/container.jsp
for both the questions and
responses
[9]               The JEC consortium comprises the JRC, EUCAR and
CONCAWE. Thus the Commission, EU
automobile industry and oil industry take part in this work.
[10]             https://circabc.europa.eu/w/browse/9e51b066-9394-4821-a1e2-ff611ab22a2d

[11]             https://circabc.europa.eu/w/browse/9ab55170-dc88-4dcb-b2d6-e7e7ba59d8c3

[12]             https://circabc.europa.eu/w/browse/9e51b066-9394-4821-a1e2-ff611ab22a2d

[13]             https://circabc.europa.eu/w/browse/9ee501ad-fdfe-4975-80d4-477557384644
[14]              Meetings of this group were chaired by DG CLIMA
and included representatives of the
                Secretariat
General, DG MOVE, DG ENTR, DG ENER, DG AGRI, DG
TRADE, DG ENV and the                    Joint Research
Centre.
[15]              ARES(2013)2583437 and
ARES(2013)2954250
[16]             A summary of the latest report commissioned by the
Canadian authorities on this matter can be found here
http://www.nrcan.gc.ca/media-room/news-release/2013/13889
[17]             Note available https://circabc.europa.eu/w/browse/d627b43b-93b4-4547-a2a8-2a8c1bb8f007.
[18]             https://www.europia.eu/content/default.asp?PageID=412&DocID=37713.
Given the commercially sensitive nature of the information used, only a summary
of the results from this report has been published by Europia. As such, the
ability to draw comparisons with other available studies remains limited. 
[19]             It includes total costs. No
figures have been provided specifically for the resulting administrative
burden, although Europia has stated in several meetings that such costs are
minimal.
[20]                    However,
it should be noted that refineries are technically constrained by their
refining processes in terms of what feed stocks they
can process as this can impact on their product yield, and adjusting their processes
may incur capital expenditure at the refinery. With regards to unconventional
sources of oil, very few EU refineries are able today to process unconventional
oil sources although many are planning to upgrade their capacity in the near
future (i.e. Spanish and Estonian refineries).
[21]             http://www.transportenvironment.org/publications/nrdc-report-increased-tar-sands-imports-europe
[22]             http://www.cedelft.eu/publicatie/oil_reporting_for_the_fqd%3Cbr%3Ean_assessment_of_effort_needed
_and_cost_to_oil_companies/1245
[23]             “Economic and environmental impacts of the FQD on crude
oil production from tar sands”. CE Delft 
2013. 
[24]             More detail in Annex
I : Overview of the oil production process (Source: Europia).
[25]             The term "lifecycle greenhouse gas emissions"
is defined under Article 1 as "all
net emissions of CO2, CH4 and N2O that can be
assigned to the fuel (including any blended components) or energy supplied.
This includes all relevant stages from extraction or cultivation, including land-use
changes, transport and distribution, processing and combustion, irrespective of
where those emissions occur".
[26]             http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=COM:2011:0112:FIN:en:PDF
[27]             http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=COM:2011:0144:FIN:en:PDF
[28]                    The combustion of road fuel alone is currently responsible for around
20% of the Community’s
greenhouse gas
emissions.
[29]             IEA Energy Outlook 2013.
[30]             http://ec.europa.eu/energy/doc/2030/com_2014_15_en.pdf
[31]             Includes biofuels
[32]             BP 2013 statistical
review available at www.bp.com/statisticalreview 
[33]             Commission Staff Working Paper on Refining and the
Supply of Petroleum Products in the EU 
[SEC(2010)1398]
[34]             Trade figures presented here reflect total demand for
petroleum products for all sectors, not just that 
consumed in
EU road transport which is the sector regulated by the Fuel Quality Directive.
[35]             EUROPIA annual report for 2012.
[36]             Commission's calculation based on JEC Well to Wheel
study and UNFCCC's data.
[37]             The terms “natural bitumen”, “tar sands” and “oil
sands” are used indifferently throughout this
document.
[38]             ''Enhanced Recovery Methods for Heavy Oil and Tar
Sands'' Speight, 2009, p.23
[39]             ''Enhanced Recovery Methods for Heavy Oil and Tar
Sands'' Speight, 2009, p.20-22
[40]             "World Energy Outlook 2010", IEA, 2010, p.145
[41]             ''Handbook of Alternative Fuel Technology'', Speight,
p.198
[42]             ''Upstream greenhouse gas
(GHG) emissions from Canadian oil sands as a feedstock for European
 refineries'', 20 June 2011,
Brandt
[43]             ''Heavy Oil and Natural Bitumen Resources in Geological
Basins of the World'' USGS, 2007, p.36
[44]             Available at:
https://circabc.europa.eu/w/browse/9e51b066-9394-4821-a1e2-ff611ab22a2d

[45]             World Energy Outlook 2012.
[46]             International Association of Oil and Gas Producers,
Environmental Performance Indicators, 2011 data. In addition, US National
Oceanic and Atmospheric Administration satellite data indicate an 8% reduction
in total worldwide flaring volumes between 2008 and 2010.
[47]             Different tariff classification exists for natural
bitumen and oil shale (CN 2714 10 00) and conventional 
crude (CN 2707 99) under Council Regulation (EEC) N° 2658/87. 
[48]          Such
Union legislation includes Commission Regulation (EC) No 684/2009 of 24 July
2009
implementing Council Directive
2008/118/EC as regards the computerised procedures for the movement of excise
goods under suspension of excise duty; and Commission Regulation (EEC) No
2454/93 of 2 July 1993 laying down provisions for the implementation of Council
Regulation (EEC) No 2913/92 establishing the Community Customs Code.
[49]              COMMISSION REGULATION (EU) No 601/2012 of 21 June 2012 on the
monitoring and reporting of
greenhouse gas emissions pursuant to Directive 2003/87/EC of
the European Parliament and of the Council, OJ L 181, 12.07.2012, p. 30 (and p.
93).
http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2012:181:0030:0104:EN:PDF
[50]             Note available https://circabc.europa.eu/w/browse/d627b43b-93b4-4547-a2a8-2a8c1bb8f007.
[51]             IEA World Energy Outlook 2010. Oil shale projects are
expected to be competitive at lower prices of
 $60 per barrel.
[52]             EC’s calculations from IEA World Energy Outlook 2013.
[53]             Note submitted by the Spanish Oil Industry (AOP). 
[54]             Satellite observations provide total estimated flare
gas volumes per hydrocarbon-producing country but do not distinguish between
oil and gas production. In some countries the proportion of gas production is
large and it is reasonable to expect that a certain proportion of flaring is
associated with gas production. However, there is no widely recognised method
for apportioning flaring emissions between all hydrocarbons produced.
[55]             ICCT report. This is equivalent to around half of all US emissions from fossil fuels in 2008. 
[56]             For example, a number of pilot CCS projects are being
undertaken in Canada where the Albertan
government has committed $2 billion to
advancing four large-scale demonstration projects in the province.
[57]             Summary on LCFS policies available at the ICCT's
website. http://www.theicct.org/sites/default/files/publications/ICCTpolicyupdate12_USLCFS_2011.pdf
[58]             Article 2 (a) (ii) 8.
[59]             12 Member States representing 60% of the EU market
responded to the questionnaire in 2010. Only 33
fuel
suppliers responded to the questionnaire in 2012. 
[60]          A total
of 90 producers have been identified in the EU.
Please note that this is different from the total
number of EU refineries since some of these are single
suppliers with multiple refineries. Please see ICF
report for more information.  
[61]             Eurostat 2012
[62]             Eurostat
[63]             Eurostat/EC DG Energy
[64]             Europia 2010 Annual Report. In addition, an estimated
500,000 may be employed in marketing and
logistics,
and 778,000 in the petrochemical sector. Source: Commission Staff Working Paper
on Refining and the Supply of Petroleum Products in the EU [SEC(2010)1398] 
[65]             PÖYRY ENERGY CONSULTING report to DG Energy and
Transport on a Survey of the Competitive
                Aspects of Oil and
Oil Product Markets in the EU 
[66]             Note submitted to the EC by Spanish Oil Industry
Association (AOP). 
[67]             Tax incentives and transport structural changes have
led to a petrol to diesel current ratio of 1:3,
potentially increasing to 1:4 in 2020, from the
inverse situation 20 years ago (petrol to diesel ratio of 2:1). Source:Europia.
[68]             Compared to 3.5 million barrels a day have shut down
for the OECD as a whole over the same period.
                World Energy Outlook
2012.
[69]             P. 101 IEA's ''2010 Oil Mid-term Market Report"
http://www.oecdilibrary.org/docserver/
download/6112281e.pdf?expires=1369141213&id=id&accname=id24042&checksum=1FE94D51815C
0718EB5C4E64FE7B7ECA
[70]             Sustainable utilisation rates are defined at 84% in
order to maintain a 4% margin.
[71]             http://www.greenpeace.org.uk/media/reports/tar-sands-your-tank
[72]             Source: ICF from Eurostat and OPEC 2010.
[73]             http://ec.europa.eu/energy/renewables/action_plan_en.htm
[74]             2020 feedstock projections from IFPRI used in EC staff
working document SWD (2012) 343 have been 
adjusted to
2020 fuel consumption figures used in this assessment. The potential impacts of
a higher greenhouse gas emissions threshold at 50% under the FQD's
sustainability criteria have not been taken into account for the purpose of
this exercise and as such no biofuel feedstock has been excluded from this
assessment. This is because although the level of GHG improvements needed can
be challenging, it is theoretically possible in most cases.
[75]             Total figures in this table may include rounding error.
[76]             Information used included crude/non-crude oil breakdown
(biofuels, GTL/CTL etc.), data on every refinery worldwide with aggregation
into regional or sub-regional groups, multiple products and product quality
detail, detailed marine, pipeline and minor modes transport representation,
refining sector GHG emissions, projects, investments, etc.). Further
information on the WORLD model, the data inputs and outputs resulting from this
analysis, can be in the contractors' final report at https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619.
[77]             Further information on key modelling assumption and
input data can be found in ICF’s report.
[78]             Values were firstly adjusted to account for the
projected baseline 2020 EU crude mix changes.
http://ec.europa.eu/transparency/regcomitology/index.cfm?do=search.documentdetail&XOvfOQKYHt67nl0gDR9EQ0pDU4MfDGIJHglKuEmrBsRhxbx1TISJ2Mfg5DtxY23N.
The GHG intensity values for conventional fossil fuels included in this
assessment were based on the most recent Well to Wheel study at the time of being
conducted. Other sources emerging since then strongly suggest that upstream
emission reductions have been underestimated. In this context, any increases of
the carbon intensity baseline will lead to lower compliance costs to suppliers
than those reported in chapter 5 as they would indirectly also proportionately
lower the carbon abatement costs of mitigation measures such as biofuels.    
[79]             See details on assumptions in chapter 2.2 of the
report: Technical assistance for an evaluation of
International schemes
to promote biomass sustainability (2009) http://ec.europa.eu/energy/renewables/bioenergy/sustainability_criteria_en.htm.  
[80]             Table 4. EC staff working document SWD(2012) 343 final
[81]             Further information on specific carbon intensities at Member State level are shown in Annex VII: Average GHG intensities
by Member State (gCO2/MJ) (Source: ICF))
[82]             Well-to-wheels Analysis of Future Automotive Fuels and
Powertrains in the European Context, Appendix 2 WTW GHG-Emissions of Externally
Chargeable Electric Vehicles, CONCAWE/EUCAR/JRC, 2011. 
[83]             EU Energy Trends to 2030 – Update 2009, European
Commission, 2010. available online:
http://ec.europa.eu/energy/observatory/trends_2030/doc/trends_to_2030_update_2009.pdf

[84]             In recognition of such higher efficiency, the energy
contribution of electric vehicles towards the Renewable Energy Directive target
is 2.5 of the energy consumed.
[85]             Source: ICF from Eurostat and OPEC 2010.
[86]             Should all unconventional
fossil fuel sources be replaced by the conventional equivalents, the average
GHG intensity
of all fuels consumed would go down to 83gCO2/MJ, which would mean that the 6%
FQD target would be achieved with those in place to achieve the Renewable
Energy Directive targets. 
[87]             Most of today's biofuels are
produced from crops grown on agricultural land. When this land previously
destined for the food, feed and fibre markets is diverted to the production of
biofuels, the non-fuel demand will still need to be satisfied. If
non-agricultural land is brought into production, land use change occurs indirectly,
which could lead to substantial greenhouse gas emissions being released if
high carbon stock areas are affected. This is why the
Commission has proposed to limit incentives for first generation biofuels
(http://ec.europa.eu/clima/policies/transport/fuel/documentation_en.htm).
[88]             Please see full IFPRI report for further information on
how he estimated indirect land use change emissions from biofuels have been
calculated http://trade.ec.europa.eu/doclib/docs/2011/october/tradoc_148289.pdf

[89]             In reality, it is likely that the carbon intensity of
the additional fossil petrol and diesel that are being used here will be of a
higher intensity as some amounts of unconventional sources are likely to be
included. 
[90]             The Renewable Energy Directive 10% target would not be
met under this scenario either as a result of
the reduced
biofuel contribution. As the aim of the scenario is to focus on the impacts of
the FQD, additional contributions from available renewable energy technologies
(i.e. advanced biofuels, electricity in road and rail) needed to achieve this
have not been considered. 
[91]             Sub-totals and total figures reported in this table may
include rounding error. 
[92]             Directive 2009/30/EC, Article 7a(5).
[93]             While the need for accuracy of the chosen methodology
is key to a successful implementation of the FQD, it does not seem possible to
define such level more precisely in a non-arbitrary way. 
[94]              Annex III and IV of the 2011
proposal:
http://ec.europa.eu/transparency/regcomitology/index.cfm?do=search.documentdetail&XOvfOQKYHt67nl0gDR9EQ0pDU4MfDGIJHglKuEmrBsRhxbx1TISJ2Mfg5DtxY23N
[95]             For the purpose of this assessment, representative
values for petrol, diesel, LPG and CNG) were derived from the "Well to
Wheel" work carried out by the JEC consortium.  
[96]             Allowing for actual values to be reported under this
option may lead to the overall EU fuel carbon intensity being underestimated as
only those suppliers with lower carbon intensity would be encouraged to report.
This could be mitigated through the provision of more conservative default
values. 
[97]             Certain environmental NGOs have called into question
the compatibility of this simplified approach given that the legal requirements
on fuel suppliers seem focused in reporting specific information about the
fuels they supply (i.e. origin, carbon intensity, etc).    
[98]             These values were mainly derived from the "Well to
Wheel" work carried out by the JEC consortium, 
and a number
of studies conducted for the Commission for the oil sands/natural bitumen and
oil shales values. More information can be found in the Commission’s 2011
proposal. http://ec.europa.eu/transparency/regcomitology/index.cfm?do=search.documentdetail&XOvfOQKYHt67nl0gDR9EQ0pDU4MfDGIJHglKuEmrBsRhxbx1TISJ2Mfg5DtxY23N.
[99]             Allowing for actual values to be reported under this
option may lead to the overall EU fuel carbon intensity being underestimated as
only those suppliers with lower carbon intensity would be encouraged to report.
This could be mitigated through the provision of more conservative default
values. In the 2011 proposal, suppliers of feedstocks from unconventional
sources were given the possibility to report actual values if they wished to do
so in order to demonstrate better greenhouse gas emission performance than such
default value. This has not been taken into account into the assessment of the
options in chapter 5.
[100]            These values were mainly derived from the "Well to
Wheel" work carried out by the JEC consortium, 
and a number
of studies conducted for the Commission for the oil sands/natural bitumen and
oil shales values. More information can be found in the Commission’s 2011
proposal. http://ec.europa.eu/transparency/regcomitology/index.cfm?do=search.documentdetail&XOvfOQKYHt67nl0gDR9EQ0pDU4MfDGIJHglKuEmrBsRhxbx1TISJ2Mfg5DtxY23N.
[101]            Allowing for actual values to be reported under D1 may
lead to the overall EU fuel carbon intensity being underestimated as only those
suppliers with lower carbon intensity would be encouraged to report. This is
evaluated further in chapter 5. This effect could be mitigated through the
provision of more conservative default values, such as D2.
[102]            Such system could be simplified through the introduction
of default values, further disaggregated (i.e. field level, trade name,
Marketable Crude Oil Name, etc), as a method for compliance.   
[103]            For example, suppliers are required to report the GHG
intensity of the fuels they supply according to their MCON name to the
Californian Air Resources Board under the Californian Low Carbon Fuel Standard.
Significant improvements to available data inventories using the OPGEE model
have been recently made in a recent report from ICCT that can be found at https://circabc.europa.eu/w/browse/49f63fd8-7e27-4cf7-8790-3410ee8d308e
[104]            The use of actual values is only permitted to all fuel
suppliers under options D1, D2 and E. Under option C, only suppliers of high
ghg intensity products are permitted to do so.   
[105]            https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[106]            Other considerations, such as compatibility of different
feedstocks with refinery configuration, have 
also been
taken into account. Please see final reports from ICF and VIVID for full
details.
[107]            As explained in chapter 2, the Commission has recently
proposed a limit on the maximum level of 
conventional biofuels that can be counted towards the Renewable
Energy Directive in regards to   concerns about indirect land use change
impacts. The possible impacts of a reduced contribution from            biofuels
are explored under the sensitivity section at the end of this chapter. 
[108]            http://ec.europa.eu/governance/impact/key_docs/docs/sec_2012_0091_en.pdf
[109]            See Annex XIV: Screening of competitiveness impacts for further information.
[110]            https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[111]            Further detail on how the analysis has been conducted
can be found in 
Annex XV: Assessment of competitiveness impacts on EU refineries 
[112]            Fuel traders have a market intermediary position, that
is, they                 reduce the transaction costs of trading
through
specialisation. In contrast to refiners, traders hold no major assets affected
by the FQD.
[113]            It is acknowledged that SMEs may be more sensitive to
any increase in administrative burden and so simplified SME specific reporting
provisions may be needed depending on the final methodological choice.  
[114]            The accuracy of this option would be improved
significantly if suppliers were, for example, required to
report on
the carbon intensity of the fuels based on a more disaggregated system, as to
ensure such average would be based on a large sample of reported data.
[115]            In such case, default values would need to be set at
conservative level as to avoid large under-reporting.  
[116]            Or between 10 to 25% of overall FQD reduction target. 
[117]            Well to wheel study, JEC consortium.
[118]            Further information on the environmental impacts
associated with fuel production can be found in Annex
XVIII: General considerations around environmental impacts associated with
fossil fuel production (Source: JRC) .
[119]            Should all unconventional fossil
fuel sources not be captured by the methodology, the average
GHG intensity
of all fuels consumed would go down to 83gCO2/MJ, which would mean that the 6%
FQD target would be achieved on paper but in reality it would constitute a 5.2%
reduction.
[120]            All costs presented here are annual costs.
Administrative costs associated with the chosen mechanism
will apply to
suppliers every year given that the reported obligation is set on an annual
basis, while
compliance
with the FQD target, and therefore the associated compliance and market costs,
does not
apply until
the year 2020. Full details on administrative costs can be found in Annex
XIX: Detailed information on administrative costs.  
[121]            Instead, compliance costs reported here only reflect the
sum of  the expenditure on all abatement
measures.
[122]            The pump price increases reported here represent the
change in cost between the baseline and the different options- the effort
required to achieve the Fuel Quality Directive target once the Renewable Energy
Directive target has been met. Absolute pump price increases for the 6%
reduction would be around 0.3 cents per litre. Further detail can be found in
ICF/VIVID report at https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[123]            In the context of the overall uncertainty associated
with the results from the modelling, these variations
should be
interpreted with caution as they represent very small proportion (>1%) of
the total fuel mix at
11000PJ.
[124]            Under this option, the amount of unconventional sources
being consumed remains largely unaffected
and so the
decrease in diesel demand comes mainly from conventional sources. As most of
the
refineries in
the EU are not able to process unconventional feedstocks, a larger decrease on
consumption of conventional sources indirectly leads to a larger share of
imports.  
[125]            Negative impacts on employment may be limited to those
related to the small reductions in EU refining
throughput.
Although these reductions are likely to be offset with increased biofuel
production at EU level, these effects may concern different groups of workers
and not occur in the same Member State.
[126]            Or between 2 to 3% of overall FQD reduction target. 
[127]            Refiners report to the MS and MS to the Commission
monthly summary of delivered crude quality, crude name, density, and sulphur
content pursuant to Council Regulation 2904/95.
[128]            It is not possible to determine whether the level of
disincentives provided by such methodology under the Fuel Quality Directive
will ultimately lead to the unconventional sources not being extracted or
instead these would be routed to markets outside the EU. Diverging results from
stakeholder studies conducted on this topic can be found in section 1.3.  
[129]            All costs presented here are annual costs. Administrative
costs associated with the chosen mechanism
will apply to
suppliers every year given that the reported obligation is set on an annual
basis, while
compliance
with the FQD target, and therefore the associated compliance and market costs,
does not
apply until
the year 2020. Full details on administrative costs can be found in Annex
XIX: Detailed information on administrative costs.  
[130]            The pump price increases reported here represent the
change in cost between the baseline and the different options- the effort
required to achieve the Fuel Quality Directive target once the Renewable Energy
Directive target has been met. Absolute pump price increases for the 6%
reduction would be around 0.3 cents per litre. Further detail can be found in
ICF/VIVID report at https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[131]            These results should be interpreted with caution as they
represent very small variations (>1%) of the 
total fuel
mix at 11000PJ.
[132]            It is worth noting that US imported diesel derived from
natural bitumen is expected to exit the market
before other
unconventional sources such as oil shale and Venezuelan natural bitumen as its
competitiveness
inside the EU is influenced by having a lower market share than Venezuelan
natural
bitumen. In
addition, its upstream emissions intensity and the lifecycle emissions
intensity is high, almost as high as oil shale and above Venezuelan natural
bitumen levels. Oil shale is slightly more competitive than North American
natural bitumen as it is harder to substitute. 
[133]            In our assessment, this leads to less abatement measures
needed to be put in place overall under D1.
[134]            Or around 27% of overall FQD reduction target. 
[135]            Or around 17% of overall FQD reduction target. 
[136]            It is not possible to determine whether the level of
disincentives provided by such methodology under the Fuel Quality Directive
will ultimately lead to the unconventional sources not being extracted or
instead these would be routed to markets outside the EU. Diverging results from
stakeholder studies conducted on this topic can be found in section 1.3.  
[137]            The difference in compliance costs would be determined
by the level of abatement needed. This would
range between
the costs of 1 million for D1 (i.e. which presents low costs given its
underestimation of
EU emissions to
8 million euros, which equals the compliance costs for option E
as it would
be the most extreme variant for D2. 
[138]            All costs presented here are annual costs.
Administrative costs associated with the chosen mechanism
will apply to
suppliers every year given that the reported obligation is set on an annual
basis, while
compliance
with the FQD target, and therefore the associated compliance and market costs,
does not
apply until
the year 2020. Full details on administrative costs can be found in Annex
XIX: Detailed information on administrative costs.  
[139]            Option D1 would lead to lower costs as due to the
underestimation of EU average default values less
abatement
tools are needed than for the other options. The costs for both D1 and D2 will
ultimately lie
somewhere
between those of options C and E. 
[140]            The pump price increases reported here represent the
change in cost between the baseline and the different options- the effort
required to achieve the Fuel Quality Directive target once the Renewable Energy
Directive target has been met. Absolute pump price increases for the 6%
reduction would be around 0.3 cents per litre. Further detail can be found in
ICF/VIVID report at https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[141]            These results should be interpreted with caution as they
represent very small variations (>1%) of the 
total fuel
mix at 11000 PJ.
[142]            This could be mitigated through the development of
default values based on data at further level of disaggregation, such as those
included in the Californian Low Carbon Fuel Standard.
[143]            All costs presented here are annual costs.
Administrative costs associated with the chosen mechanism
will apply to
suppliers every year given that the reported obligation is set on an annual
basis, while
compliance
with the FQD target, and therefore the associated compliance and market costs,
does not
apply until
the year 2020. Full details on administrative costs can be found in Annex
XIX: Detailed information on administrative costs.  
[144]            The pump price increases reported here represent the
change in cost between the baseline and the different options- the effort required
to achieve the Fuel Quality Directive target once the Renewable Energy
Directive target has been met. Absolute pump price increases for the 6%
reduction would be around 0.3 cents per litre. Further detail can be found in
ICF/VIVID report at https://circabc.europa.eu/w/browse/6893ba02-aaed-40a7-bf0d-f5affc85a619
[145]            These results should be interpreted with caution as they
represent very small variations (>1%) of the 
total fuel
mix at 11000PJ.
[146]            Article 8 (3) of 98/70/EC.
[147]            Based on
information provided from chapter 2 of the Delft Report March 2012: Oil
reporting for the 
FQD: An
assessment of effort needed and cost to oil companies.
[148]            Minimum Reporting Obligations in the Fuel Quality
Directive, Administrative burden of tar sand
classification in the Fuel Quality
Directive, T&E.
[149]            Based on
diagram from Delft Report March 2012: Oil reporting for the FQD: An
assessment of effort
needed and
cost to oil companies.
[150]            Based on Chapter 2 of the Delft Report March 2012: Oil
reporting for the FQD: An assessment of effort
needed
and cost to oil companies and Minimum Reporting Obligations in the Fuel Quality
Directive, Administrative burden of tar sand classification in the Fuel Quality
Directive, T&E.
[151]                            Regulation (EC) No 450/2008 of the European
Parliament and of the Council of 23 April 2008 laying down the  Community Customs
Code (Modernised Customs Code) 
([152])         Council
Directive 2008/118/EC of 16 December 2008 concerning the general arrangements
for excise duty and repealing Directive 92/12/EEC (OJ L 009, 14.1.2009, p.12).
([153])         Council
Directive 2003/96/EC of 27 October 2003 restructuring the Community framework
for the taxation of energy products and electricity (OJ L 283, 31.10.2003,
p.51).
[154]            Chapter 3 of the Delft Report March 2012: Oil reporting
for the FQD: An assessment of effort needed
 and cost to oil companies
[155]            of 95.86 g CO2 eq./MJ for petrol and 94.71 g CO2 eq./MJ
for diesel.
[156]            http://www.arb.ca.gov/fuels/lcfs/122310-new-pathways-guid.pdf
[157]            It includes the states of Connecticut, Delaware, Maine,
Maryland, Massachusetts, New Hampshire,              New Jersey, New York,
Pennsylvania, Rhode Island and Vermont.
[158]            It includes the states of Illinois, Indiana, Iowa,
Kansas, Michigan, Minnesota, Missouri, Ohio, South  
Dakota and Wisconsin.
[159]            Both CARB and RLCFRR methodological approaches have been
revised since their entry into force. 
For
simplicity, only the most current approach is described here.
[160]            It is worth noting that because of industry concerns
around potential crude shuffling of lower crudes by
companies
(i.e. these being diverted into British Columbia as to benefit from RLCFRR
credits), the option for reporting actual emission values is being discontinued
from 2013 onwards.
[161]            Biomass = the biodegradable fraction of products, waste
and residues from biological origin from
agriculture
(including vegetable and animal substances), forestry and related industries
including fisheries and aquaculture, as well as the biodegradable fraction of
industrial and municipal waste.
[162]            Ec Renewable Energy Progress report COM(2013) 175 final
[163]            This number excludes biofuels produced in the EU from
imported feedstocks.
[164]            In this context, there are some 150 oil crops processing
and vegetable oils and fats production facilities
across
Europe, for which the trade in biodiesel products will be one of their major
markets.
[165]            Further detailed information on the biofuel and related
agricultural industries can be found in 
SWD2012(343).
[166]            All the plans, in both English and original language are available
here:
                http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm
[167]            JEC Reference scenario:
http://ies.jrc.ec.europa.eu/uploads/jec/JEC%20Biofuels%20Programme.pdf. 
[168]            http://europa.eu/rapid/press-release_IP-12-1112_en.htm
[169]            Renewable Energy Progress report SWD(2013) 102 final
[170]            The NREAPs estimate a total of 0.7 Mtoe of renewable
electricity in road vehicles by 2020. In order to
convert
this figure to overall electricity it has to be divided by the fraction of
renewable energy in the electricity mix of 2020, assumed to be 34% for the EU
in the NREAPs. This gives 2.1 Mtoe of electricity. The real figure is likely to
be lower, as countries with higher than average share of renewable energy in
the electricity mix, will use national values rather than the EU-average. 
[171]            Reference to final report ICF/VIVID.
[172]            Detail information on the modelled fuel mix under each
option is available in Annex XVII: Projected road fuel mix 2020 for each
option (non-ILUC scenario) (Source: Vivid Economics).
[173]            CO2e describes for a given mixture and amount of
greenhouse gas, the amount of CO2 that would have 
the same                
global warming potential (GWP), when measured over a specified timescale
(generally, 100 years).
[174]            OSPAR is the mechanism by which fifteen Governments of
the western coasts and catchments of
Europe,
together with the European Union, cooperate to protect the marine environment
of the North-East Atlantic (http://www.ospar.org)