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February 2006

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1. Petroleum Refining

1.1 This Section

This section covers the petroleum refinery sector (“Contract D”), as part of an overall project

for DTI on “EU Emissions Trading Scheme (ETS) Phase II – UK New Entrants Spreadsheet

revisions”.

The overall aim of this project is to validate and revise appropriately the existing New Entrants (NE) allocation spreadsheet. The following sub-sections present the findings for this sector.

1.2 Background and Sector Description

This section is intended to provide a brief overview of the sector structure and the process

operations which give rise to CO2 emissions. It is not intended to be a comprehensive description of the sector and its processes. The reader should refer to the relevant BAT

reference document for detailed information on the sector.

1.2.1 Sector structure

The main activity carried out at refineries is the separating and processing of crude oil and

natural gas liquids to make fuels (e.g. petrol, diesel, LPG) and selected chemical products (e.g. white spirit, bitumen). The main operations are distillation, reforming, cracking and conversion,

all of which require significant heat input via fuel combustion. Overall, refineries use around 6% of crude oil processed for their own energy requirements (DTI 2005).

At the end of 2004 there were 9 major refineries and three minor refineries operating in the UK.

Total UK distillation capacity at the end of 2004 was 92.0 million t/yr. Total UK reforming capacity 14.2 million t/yr and cracking and conversion capacity was 36.5 million t/yr (DTI

2005). Existing UK refineries range widely in their size and complexity (from 0.7 to 16.2 million tonnes distillation capacity) with some facilities now reaching 40-50 years since first

operation. Although it is considered unlikely that any new large refineries will be built in the UK in the foreseeable future, there is significant ongoing investment to replace and upgrade

plant equipment at existing sites (UKPIA 2006).

The maintenance of adequate petroleum refining capacity and efficient use of all fractions of crude oil processed at refineries is a key part of the UK’s energy strategy. The UK is a net

exporter of oil products and existing UK refining capacity ensures a high degree of self-sufficiency in supply of essential fuels and chemical feedstocks for industry and commerce,

transport and domestic users. Total output from UK refineries in 2004, at 90 million tonnes of products, was 6% higher than in 2003. Around 75% of the UK’s primary oil production is

exported, and imported crude oil accounts for two-thirds of the UK’s requirements. In future, a decline in exports and increase in imports is likely to occur as indigenous oil production

declines.

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The US remains one of the key markets for UK exports of oil products, with 5.3 million tonnes

being exported there in 2004. These exports made up 17% of total UK exports of oil products in 2004, with the main other countries receiving UK exports being Belgium, France, Ireland, the

Netherlands, and Spain (DTI 2005).

In recent years the sector has come under increasing pressure to produce cleaner fuels due to Sulphur Content of Liquid Fuels Directive. This has required a large investment to

modify/replace existing plant and has led to significant plant downtime (DTI 2005). These plant modifications have also increased the energy intensity of the processes, leading to an

increase in fuel consumption per tonne of oil processed.

The oil refining industry has used benchmarking as an aid to improving operational productivity and efficiency for two decades. Simple normalisation on the basis of crude throughput or

product make has generally been regarded as too inaccurate to be helpful even as management information. In practice the market in refinery benchmarking has been dominated by Solomon

Associates, who have developed proprietary approaches with the aim of providing useful management information by benchmarking the various components of operating cost

1.2.2 Process Overview

This section provides a summary of the combustion activities and process operations at petroleum refineries which give rise to CO2 emissions. For additional information, refer to the

relevant sector BREFs (EIPCCB 2001a; 2001b).

In 2004, UK refineries consumed approximately 6,600 kilotonnes oil equivalent (ktoe) of energy (or 77,000 GWh) to satisfy their heat and power requirements (DTI 2005). The majority

of this heat and power is generated by burning gaseous, liquid and solid fuels derived from crude oil in on-site boilers, furnaces and power plants, with the remainder being imported.

Around 90% of the total energy use is for process heating and approximately 70% of refinery electricity demand is generated on-site (DTI 2005). Fuel consumption figures for refinery

generated fuels in 2005 are shown in Table 1.1. Combustion of these four fuels represents the main source of refinery CO2 emissions. Some refineries also import natural gas for use as a fuel

for on-site heat and power generation and this leads to additional CO2 emissions.

Table 1.1 Refinery Fuels Consumption at UK Refineries in 2004 (DTI 2005)

Refinery Generated Fuel Fuel Consumption (kt) Energy Equivalent (ktoe)

Refinery fuel gases 2,569 3,111

Refinery fuel oils 1,680 1,749

Petroleum coke 1,012 865

Gas oil 192 209

Total refinery generated fuels 5,453 5,943 1

Note

1: The difference between this total and the 6,600 ktoe total quoted above is due to use of non-refinery generated fuels such as imported natural gas.

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A refinery is made up of a number of different process units for separating and converting crude

oil into saleable petroleum products. The list below is intended to summarise the main distinct process units found at refineries and a description of each can be found in the sector BREF.

Note that a refinery may not have all of these process units and the exact configuration varies significantly between refineries. These processes would all need to be covered separately by the

benchmarking method if a direct approach were used as a NE application could be for any one of these units.

MAIN REFINERY PROCESSES

Separation Crude oil desalting/dewatering

Atmospheric distillation

Vacuum distillation

Light ends recovery

Conversion Thermal cracking - coking, visbreaking

Catalytic cracking

Hydrocracking

Steam cracking

Catalytic reforming

Isomerisation

Alkylation and polymerisation

Treating Processes Hydrodesulphurisation

Hydrotreating

Extraction

Bitumen blowing

Lube oil manufacture

Auxiliary Facilities Boiler/process heaters

Hydrogen production

Sulphur recovery and production

Compressor engines

Power generation

Blowdown systems Flares

Refinery complexity varies significantly and there is no standard configuration which presents problems for CO2 emission benchmarking. A wide variety of different crude oils are used and

different refinery process configurations are applied to produce a wide range of products. Whilst all refineries have crude oil distillation, there are many options for further processing to

enhance the yield of more valuable products (e.g. to increase yield of transport fuels at the expense of heavy fuel oil), and to produce cleaner products meeting the specifications for

sulphur-free petrol and diesel. In addition some refineries may produce lubricants or speciality chemical streams. All refineries use considerable quantities of steam and significant amounts of

power, and there are a variety of ways of supplying these either on-site or with import arrangements. Traditionally refineries have been designed to use refinery fuel gas and refinery

fuel oil produced in their own operations, although in recent years some refineries have been able to take advantage of the possibility to import natural gas as part of the refinery fuel mix.

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Refineries need to use increasing quantities of hydrogen to remove sulphur from the product

streams, and a refinery with a hydrocracker will need to use large quantities of hydrogen, resulting in a refinery gas with higher carbon content. As a result of this complexity, CO2

emissions per tonne of product from a specific refinery unit are dependant on a number of factors including feedstock properties, fuel mix, operating temperature and pressure, and

product mix and specification.

Most refinery sites have several direct fired process heaters, gas turbines, incinerators and flare stacks together with steam raising plant, which may include electricity generating facilities and

Combined Heat and Power facilities (CHP). These combustion processes generate CO2 emissions and are normally fuelled by refinery-generated fuel gas and fuel oil systems, although

natural gas may also be imported to site. The capacity of refinery combustion units varies widely from less than 10 megawatts thermal input (MWth) up to 200 MWth. Total installed

capacities at individual refineries range from several hundred to 1300 MWth or more on the largest refineries (EA 1995a). In some refinery process units such as fluidized bed catalytic

cracking (FCC) units the process feedstock itself is partially consumed to provide heat, leading to ‘process’ (rather than ‘combustion’) CO2 emissions. Process CO2 emissions are also

generated from a number of other refinery units due to partial combustion of feedstocks, regeneration of catalysts and flaring. Since all refinery CO2 emissions are covered by Annex I

of the EU ETS Directive the distinction between process and combustion CO2 for this sector is not significant in terms of NER allocation.

A variety of furnaces and burner types are used in refineries, largely determined by the heat

release characteristics required by a particular process. Many furnaces are dual-fired (oil/gas) to allow flexibility in the refinery fuel system. Petroleum coke is also manufactured at refineries

and some of the product is consumed for on-site heating purposes. Refinery process heaters are typically rectangular or cylindrical enclosures with multiple up-fired burners of specialised

design using mainly low combustion intensity while boilers are generally fairly standard steam producing units of medium or high combustion intensity (EA 1995a). The proportion of energy

supplied by fuel oil and gas oil is normally >20% and can be up to 60% at some refineries (the remainder being supplied by refinery fuel gas, natural gas and coke). Bearing in mind the highly integrated and interdependent nature of the refinery processes, refinery operators aim to

match continuously the variable production and consumption of fuels on processes and utilities at the lowest economic and environmental cost (EA 1995a). Although fuel switching at

refineries is technically possible, economic and practical considerations limit the fuel switching options. For example, there are high capital costs for installing a natural gas pipeline to supply

a refinery and limited alternative disposal routes for refinery fuel oil which may be high in sulphur content. Currently 3 UK refineries use significant amounts of natural gas amounting to

energy use of approximately 5.7 TWh/year or 8% of all refinery fuel use (DTI 2005). Wholesale fuel switching to natural gas at UK refineries would require a net increase in total

UK natural gas supplies of 6% (66 TWh/year) which would potentially threaten UK energy security and diversity.

Sector guidance (EIPCCB 2001a; EA 1995a) on best practice states that as far as possible,

refinery fuel demand should be minimised by making maximum use of heat recovery and exchange techniques to meet process heating duties. New and revamped-fired heaters should be

of energy efficient design with modern control systems (EA 1995a). Many refineries have on-site CHP units, which burn refinery fuels to generate electricity. To help reduce CO2 emissions

from generation, energy efficient electrical equipment such as variable speed drives (VSDs) should also be used where appropriate (EA 1995a).

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1.2.3 Phase I Incumbent and New Entrant Installations

Identification of how sector is covered under EU ETS

Petroleum refineries are covered by Annex I of the EU ETS Directive under ‘mineral oil

refineries’. All refinery activities are covered and there is no de-minimis limit for inclusion of CO2 emissions from refinery installations or individual refinery sources. CO2 emitted from a

multitude of small refinery sources, such as flare stacks and process vents is therefore included. Each refinery may have, say, 10 large points sources of CO2 emissions (i.e. boilers, direct fired

process heaters, CHP units) and as many as 50 or so smaller point sources (i.e. flare stacks, process vents, smaller process heaters) which are all captured under the EU ETS.

CO2 emissions from sector

The table below presents the total carbon dioxide emissions arising from UK petroleum refinery operations over the years 1998-2003. Equivalent data for 2004 and 2005 are not available at

this time.

Table 1.2 CO2 Emissions and Throughput for UK Petroleum Refining Sector (DEFRA 2005a, DTI 2005)

Year Primary Oil Feedstock (kt)

CO2 Emissions (kt)

Specific Emission Factor (tCO2/t oil

processed)

Increase in Emission Factor

(% c.f. 1998)

1998 93797 18054 0.1925 0.0

1999 88286 17304 0.1960 1.8

2000 88014 18036 0.2049 6.5

2001 83343 17111 0.2053 6.7

2002 84784 18150 0.2141 11.2

2003 84585 18061 0.2135 10.9

The data above indicates the general increase in CO2 emissions per tonne of oil processed. Emissions intensity has increased by over 10% since 1998, largely due to the requirements to

process petroleum products to meet tighter product standards, for example to reduce sulphur content, which requires more energy input and hence increases CO2 emissions. This trend is

likely to continue due to increased conversion of heavier feedstocks to meet the demand for lighter-fraction transport fuels (e.g. aviation fuel) and a drop in demand for heavier fuels (e.g.

fuel oil). Under the revised NAP, the oil refining sector has been granted a total Phase I allocation of 19,430 ktCO2/year. Therefore the NAP allocation is 7.6 % above the 2003 sector

total emission level.

The data from the revised NAP (14th February 2005) is summarised below.

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Table 1.3 CO2 Emissions and NAP Data for UK Petroleum Refineries (DEFRA 2005a)

Note 1: The ‘relevant emission’ data are taken from the revised phase I NAP and are for baseline period of 1998-2003.

The above data on 2003 actual emissions and the revised NAP allocations for each refinery can be used to analyse the impact of different benchmark emissions allocation methods on refineries

as a whole. However, data on energy use and CO2 emissions for individual process units at UK refineries is not readily available as it is considered to be confidential by refinery operators.

Identification of Non-benchmarked incumbents, Benchmarked incumbents and New Entrants

The refinery sector incumbents in Phase I of the EU ETS are identified by their NAP ID in Table 1.3 above. Allocations for these incumbents were not based on benchmarks in Phase I

since they have been operating for some time and had sufficient historical emissions data from which to make Phase I allocations. The only known proposal for a new entrant in Phase I was

for the rebuild of a FCC unit at an existing refinery installation operated by BP Ltd. In this case the Phase I benchmarking method is applicable, although the existing refinery NE allocation

spreadsheet does not provide any benchmarks and therefore requires a verifier’s opinion to determine the allocation. DEFRA has provided guidance on new entrant verification (DEFRA

2005b) and this should be referred to as required.

1.2.4 Possible types of New Entrant Technologies in phase II

Brief description of known or likely new entrants and market developments

There is an expectation/speculation of significant investment at selected sites in the refining

sector. Investment may include capacity for biofuels processing and conversion projects to destroy heavy fuel oil to make more valuable products such as jet fuel. Whilst it was relatively

easy to predict immediately before the start of Phase I which new plants/developments were likely to come on-stream (i.e. 1 year ahead), Phase II developments (2008-2012) are difficult to

No. Operator Refinery Name NAP ID EU ETS Sector

Annual

Allocation

during

Phase 1

2003

Emission

(tCO2)

Relevant

Emission

(tCO2)

1 Shell UK Ltd Stanlow 407 Refineries 2,967,750 2,807,950 2,781,012

2 Exxon Mobil Co. Ltd Fawley 403 Refineries 3,624,339 3,368,808 3,396,288

3 BP Ltd Coryton 399 Refineries 2,397,369 2,234,091 2,246,521

4 BP Ltd Grangemouth 409 Refineries 1,464,020 1,414,547 1,371,901

5 Total Fina Elf Ltd. Lindsey Oil Refinery 2960 Refineries 2,115,851 1,911,647 1,982,717

6 Texaco Refining Co. Ltd Pembroke 408 Refineries 2,176,095 1,819,991 2,039,170

7 Conoco Ltd Killingholme 4077 Refineries 2,580,953 2,424,954 2,418,553

8 Total Fina Elf / Murco Pet. Ltd Milford Haven 402 Refineries 1,221,633 1,178,740 1,144,765

9 Petroplus International Ltd North Tees 406 Refineries 283,919 245,018 266,054

10 Petrochem Carless Ltd Harwich 405 Chemicals -- CIA 37,998 34,769 43,446

11 Eastham Refinery Ltd Eastham 401 Refineries -- CIA 58,250 48,799 55,637

12 Nynas UK AB Dundee (Camperdown) 410 Refineries -- CIA 22,568 20,500 21,555

13 NPower Cogen Trading Ltd Fawley 2531 Refineries 479,983 551,043 449,781

2&13 Total for Fawley Refinery Fawley 403 & 2531 Refineries 4,104,322 3,919,851 3,846,069

Total all UK Refineries 19,430,727 18,060,857 18,217,401

Refinery Emissions Data and NAP Allocations

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predict at this early stage (i.e. 3-7 years ahead). Data provided by the DTI indicates that Phase

II new entrants may include:

• Two refineries installing new boilers/CHP units;

• One refinery installing a hydrodesulphurisation unit; and,

• One refinery installing a full conversion hydrocracker.

It also noted that drivers for future increases in UK refinery CO2 emissions will include:

• Tighter fuel specifications which will require more intensive processing of crude oil

fractions. This will exert an upward pressure on refinery energy use and CO2 emissions;

• Increased processing of heavier and sourer crude oils. This will increase refinery

energy use and CO2 emissions per unit of throughput compared to processing lighter sweet crude oil feedstocks.

• Production rates of sweet light North Sea crude oil are declining and this trend is set to continue. Many UK refineries were designed to process this feedstock but are

now installing additional process units to process imported heavier sourer crude oil. Lower quality feedstocks are cheaper and refineries that can process heavier sourer

crude tend to have higher profit margins.

Summary of possible types of New Entrants in Phase II

A summary of possible types of New Entrants in Phase II is given in Table 1.4.

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Type of New Entrant Is this type of New

Entrant

realistically

possible in Phase

II? (Y/N)

Technology type(s)? Fuel type(s)? Other relevant details

New installation Y New installations for biofuels refining are

possible in the UK but the sector

association (UKPIA) consider a major a

new installation for mineral oil refining to

be unlikely.

Refinery fuel oil and refinery

fuel gas, possibly natural gas

and biofuels

Several UK oil refineries have closed in the past 10

years due to industry rationalisation and competition.

The remaining nine UK large refineries have

adequate capacity to supply the UK's oil refining

needs at this time.

New piece of equipment

to increase capacity

Y New cracking units to expand capacity

and biofuels distillation units are possible

at existing mineral oil refineries. In

theory, an operator could install any one

of the main types of process unit found

at refineries as part of a capacity

increase.



and biofuels

It is difficult to predict what new plants will come on

line in Phase II due to the commercial confidentiality

of operator's refinery development plans. The

demand for production of biofuels and tightening fuel

emission standards are the main drivers for new

plant investment.

Extension to existing

piece of equipment to

increase capacity

Y Modifications to existing cracking and

distillation units to increase production

and replace end-of-life equipment at

mineral oil refineries are likely. In

theory, an operator could rebuild/extend

any one of the main types of process

unit found at refineries as part of a

capacity increase.



and biofuels

The increasing demand for cleaner transport fuels

and the need to replace ageing plant, often with new

plant of a larger capacity, will be the main drivers for

plant extensions/rebuilds. In phase I, one company

planned to rebuild a fluidised catalytic cracker unit,

leading to a refinery capacity increase and an

application to the NER.

Table 1.4 Summary of possible types of New Entrants in Phase II

1.3 Review of relevant data

1.3.1 Data sources

The following organisations in the sector have been contacted during this study:

• UK Petroleum Industries Association (UKPIA);

• CONCAWE (European oil industry association);

• EUROPIA (European petroleum industry association);

• Selected refinery operators; and

• Solomon Associates Ltd (refinery benchmarking company).

These organisations have provided commentary on key issues which has been used to inform the assessment and development of alternative allocation methods. A range of additional data

sources on refinery energy use and CO2 emissions have been obtained and reviewed, as follows:

• FES report and spreadsheet on NE allocations, including methods for CHP units,

boilers and refinery processes;

• Phase I NAP submission forms for the 12 UK petroleum refineries;

• Digest of UK Energy Statistics 2005;

• European BREF on mineral oil refineries;

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• Journal articles on energy use benchmarking for refineries; and

• Papers on allocation methodologies from other member states.

The above data sources have been useful in assessing aggregate energy use figures for some European refineries and also specific energy use for some types of process units. Total fuel use

data for individual UK refineries has been obtained from the NAP submission forms and this information has been used to inform the analysis but is not reproduced in this report due to

confidentiality.

1.3.2 Data from literature

Data from literature searches and other sources on emission factors and capacity utilisation /

load factors of best operating practice installations relevant to Phase II New Entrants is summarised in Table 1.5 below. The only source of readily available fuel use and CO2 emission

data for individual process units is the sector BREF as this type of data is usually treated as confidential by the operators. The table presents a summary of the data in the BREF for

different types of process unit typically found at a refinery. It is not an exhaustive list but simply illustrates the variation in emission factors between common process unit types at

different refineries. The key point to be taken from the table is that energy use varies significantly between process units depending on their feedstock and product mix and that there

are many types of process unit, making benchmarking complex.

Table 1.5 Data from sector BREF on emission factors and capacity utilisation / load factors of best operating practice installations relevant to Phase II New Entrants (EIPCCB 2001a)

Type of installation and process unit

Unit Throughput (t feed/year)

Fuel consumption (GWh/year)

Specific fuel use (MWh/t feed unless specified)

CO2 emissions (t/year)

Specific CO2 emissions (kg/t feed)

OMV Schwechat refinery, Naptha Hydrotreater

1,160,000 205.9 0.178 40,152 35

Mider refinery, Naptha Hydrotreater

1,500,000 205.9 0.137 39,937 27

OMV Schwechat refinery, Middle Distillate Unit

1,780,000 135.8 0.076

26,341 15

Mider refinery, Middle Distillate Unit

3,000,000 205.9 0.069 39,937 13

OMV Schwechat refinery, Vacuum Distillate Unit

1,820,000 72.4 0.040 19,466 11

Mider refinery, Vacuum Distillate Unit

2,600,000 578.2 0.222 164,776 63

Hydrocracking No data No data 0.111-0.333 (also steam produced 30-300 kg/t feed)

No data No data

Hydroconversion No data No data 0.167-0.278 (also steam produced 200-300 kg/t feed)

No data No data

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Type of installation and process unit

Unit Throughput (t feed/year)

Fuel consumption (GWh/year)

Specific fuel use (MWh/t feed unless specified)

CO2 emissions (t/year)

Specific CO2 emissions (kg/t feed)

Steam reforming No data No data 9.72-22.22 MWh/t H2 produced (also steam produced 2-8 t/t H2)

No data No data

Hydrotreatment of naptha

No data No data 0.056-0.097 No data No data

Hydrotreatment of distillate


Hydrotreatment of residue


From the table above the key points are as follows:

• The specific energy consumption and specific CO2 emissions for each type of refinery process unit varies significantly between refineries (e.g. hydrocracking

400-1200 MJ/t feed);

• This significant variation is a complex function of parameters such as the feedstock

composition, degree of feedstock conversion, process conditions and product yield; and

• It may not be possible to accurately predict energy use or CO2 emissions with use of a single factor (i.e. MJ/t feed) for each process unit.

The data presented above is not further assessed or discussed since it is considered to be of

limited use for the purposes of benchmarking new entrants and is not subsequently used in this

study.

1.3.3 Benchmarks used in other contexts, including other Member States (if available)

Investigations have been undertaken to try to identify benchmarking approaches for new

entrants in other Member States. Overall, the extent of information available within the tight timescales of this study has been limited. Furthermore, information will tend to relate to Phase I

approaches, and hence may not be indicative of approaches in Phase II, which this study is focussed on. Notwithstanding this, it is useful to consider these approaches, as briefly

summarised below.

Denmark

The Danish NAP assumes an efficiency factor of 0.9 for new entrants but no distinction is made between sectors for this factor. No discussion of new entrant benchmarks or formula.

Germany

New entrants are granted allocation on BAT benchmarks. These benchmarks are established for

installations with comparable products, and derived from BAT for new installations in that

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class. Also, each product category will have a benchmark. New entrants that don’t have defined

benchmarks will be granted allowance based on BAT.

New entrant formula (industry non-specific);

Allocationi = Ci ·P

iU ·BAT,

where

i is an index for the installation;

Ci is the installation-specific output capacity in MW;

P

iU is the projected utilisation or load factor by installation; and

BAT BAT benchmark for emissions per output unit.

Greece

Known new entrant allocation for specific sectors including; steelworks and refineries.

Ai = Pi x Hi x 3.6 x 10-3 x BAi x EFj x CFi

where

Ai = annual installation-i allowances (t CO2/year);

Pi = new entrants installations-i power (MW);

Hi = installation’s-i hours of operation (h/year);

BAi = installation’s-i efficiency ration;

CFi = installation’s-i compliance factor (compliance factor less than or equal to 1).

Netherlands

The allocation is based on refineries attaining top 10% performance worldwide, using the Solomon Energy Intensity Index (EII). The Solomon EII is a proprietary energy efficiency index

for refineries operating across the world. It is understood that Dutch industry argued for this approach (c.f. simply using refinery energy use per tonne of throughput) on the basis that it is

more accurate for benchmarking.

Sweden

Allocation05-07 = k x Projected output05-07 x BM / BAT

Where

k = Scale factor applied to fuel-related emissions from combustion installations in the

energy sector. For non energy sector sites, k = 1.0;

Projected output05-07 = emissions in accordance with projected produced quantity of

installation-specific product 2005-2007. Only production based on fossil fuels is meant

for electricity and heat production;

BM = Benchmark emission factor;

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BAT = Corresponds to estimated specific emissions at installation (tCO2/t product).

Other Member States

For a number of other Member States, the readily available information simply indicates that

new entrant allocations are to be based on BAT levels of performance. This applies to Czech Republic, Ireland, Malta, Portugal (explicitly stating BAT Reference Documents), Slovenia

(also referencing BAT Reference Documents), and Spain.

Based on this data the Netherlands is the only Member State we are currently aware of that provides a benchmark value for refineries and this involves use of the Solomon Energy Intensity

Index (EII)1. Other Member States such as Germany and Greece provide equations to determine refinery allocations but benchmark values to be used for each parameter in the equations are not

given.

1.4 Review of Phase I benchmarks

1.4.1 Characterisation of existing New Entrant benchmarks

The existing allocation methodology (used in Phase I) for new entrant refineries from the FES report2 is as follows:

Ai = Ci * Us/100 * SECt * EFf

Allocation = Capacity * Utilisation * Benchmark Specific

Energy Consumption

* Emissions

Factor

tCO2 tonnes

feedstock capacity

% tonnes fuel/ tonne

throughput tCO2 / t fuel

The FES report suggests that this equation be applied to new fluidised bed catalytic cracking (FCC) units but does not provide any guidance on the values to be used for parameters such as

benchmark fuel consumption. Standard emission factors (tCO2/t fuel) for different types of refinery fuels are quoted in the FES report, although in the NAP submissions, each refinery used

different emission factors according to their own site specific fuel data.

The current NE spreadsheet3 uses a different allocation equation for FCC units as follows:

1 The Energy Intensity Index (EII) is a proprietary energy benchmarking method for refineries that has

been developed by Solomon Associates Ltd. Solomon Associates has previously provided data on the EII to Entec for use in EU ETS studies. As such, all information on the EII that is presented in this report

should be treated as confidential and should not be used outside the DTI without the prior permission of Solomon Associates Ltd.

2 EU Emissions Trading Scheme – Calculating the Free Allocation for New Entrants, Report for DTI produced by Future Energy Solutions (FES), November 2004,

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Ai = Qi * Mi/100 * Ni/100

Allocation = Throughput * Mass percentage of feed

consumed as primary fuel

* Carbon content of

primary fuel

tCO2 tonnes

feedstock throughput

% %

The NE spreadsheet does not provide any guidance on the values to be used for parameters such as the quantity of feed consumed as fuel in a FCC unit. The value for annual fresh feed

throughput is equivalent to the actual feedstock processed by the unit per annum.

As such the allocation methods for refinery new entrants are not based on BAT benchmarks, a verifiers opinion is required to assess applications from refinery new entrants in Phase I.

Although the approach adopted for Phase I for the refinery sector as a whole was an ‘integrated’ one, the specific formula for the FCC benchmarked allocation is in fact closer to a ‘direct’

approach. The FES equations take a ‘direct’ approach to allocation by calculating the CO2 emissions from the new refinery unit itself (i.e. a FCC unit). They do not take an ‘integrated’

approach to allocating allowances for CO2 emissions in that the net impact of the new unit on refinery total emissions is not considered. The difference between ‘direct’ and integrated

approaches is summarised as follows:

• A direct approach means that allocations are awarded only for the emissions arising

directly from a new piece of equipment added to an installation. For example, if a site adds new boiler or CHP capacity, then it will be given a new entrant allocation

based on the capacity of that piece of equipment. By contrast, if the new piece of equipment does not directly produce any emissions, it is not eligible for a new

entrant allocation. For example, the addition of a new paper machine to a paper mill typically would not qualify for a new entrant allocation, as there are no

emissions directly from the paper machine (even though its addition may result in higher emissions as existing boiler/CHP capacity is run harder once the new paper

machine is added).

• An integrated approach means that the benchmark is based on the production

capacity of the installation as a whole. For example, in integrated steelworks, the allocation is calculated on the basis of the production capacity of liquid steel by the

whole steelworks. If equipment is added to the site then the new entrant allocation is based on the resulting change in total production capacity. For example, the

addition of a new ladle is likely to lead to higher utilisation of other components of the works (blast furnace, casting, rolling, etc.), and the new entrant allocation therefore also is likely to exceed the emissions produced directly by the new ladle

itself.

3 Calculating the Allocation for New Entrants: spreadsheet for applicants by FES, updated 23rd May 2005, available at www.dti.gov.uk.

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The DTI have indicated that they wish to pursue a direct approach to allocating NE allowances

in Phase II.

In the FES report, load factors and allocation methodologies are given for standard boilers (i.e. ‘other combustion plant >20 MW’) and CHP plants operating in the refinery sector. The

methodology for generators in the FES report should be generally applicable to electricity generating plant in the refinery sector although this methodology is currently under review by

the DTI.

Therefore, the main gap for this sector is in the development of new entrant benchmarks for the multitude of refinery CO2 sources which are not covered by the methodology for standard

boilers, CHP units or electricity generators in the FES report. These sources include but are not limited to FCC units, crude distillation units, steam reformers, hydrocrackers,

hydrodesulphurisation units, direct fired process heaters, flare stacks, etc.

A characterisation of the Phase I benchmarking method is given in Table 1.6.

Table 1.6 Characterisation of the Phase I benchmarking method

Item Parameter value / details

Justification for choice of parameter value / details given by FES

Source of data

Coverage of activities (how does the coverage of activities included in the spreadsheet compare to the activities in the sector that are covered by EU ETS)

Only covers FCC units. Other types of unit would be assessed on an ad-hoc basis by the DTI

A FCC unit rebuild was the only known new entrant proposal at the time of the FES report

The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final report.

Level of sector differentiation (Is there one set of formulae / parameter values for the whole sector, or are there separate formulae / parameter values for different technologies, fuels, products etc)

Allocation is made separately for each refinery process unit but only an equation for FCC units is given.

There are a number of different types of refinery process units to perform different functions. Benchmarks are required for each type of unit.

Industry consultation on new entrant types. The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final report.

Degree of standardisation of formulae (ie what types of input parameters are required in the formulae?)

Simple standard formula calculates actual CO2 emissions from consumption of feedstock as fuel but is not benchmarked

Simple approach but specific standardised values are not proposed and values are assumed to vary by installation.

Industry consultation on key parameters

Technology / process types (What types of technologies / processes are used as the basis for the parameter values?)

Only covers FCC units. Pre-heating of feed is not covered.

Simple approach Industry consultation on new entrant technologies

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Item Parameter value / details

Justification for choice of parameter value / details given by FES

Source of data

Fuels assumed (What types of fuels are used as the basis for the parameter values?)

User defines carbon content of feedstock used as fuel

Simple approach No fuel use benchmarks provided

Emission factors (What are the fuel CO2 and Process CO2

emission factors?) User defines proportion of feedstock used as fuel

Simple approach No fuel emission factor benchmarks provided

Capacity utilisation factors / load factors (What are the values for these factors?)

User defines annual feedstock throughput

Simple approach No load factor benchmarks provided

Other assumed parameters, excluding input parameters (one row per parameter to identify the parameter – what are the values for these parameters?)

n/a n/a n/a

1.4.2 Validation of Phase I benchmarking method

Since the Phase 1 benchmarking method only applies to FCC units and does not provide any benchmarks at all it is not possible to make any meaningful validation of the existing NE

spreadsheet for refineries.

If data were available for existing refinery FCC units (this data is considered confidential by operators) then use of the allocation equation would simply allow calculation of actual CO2

emissions, rather than benchmark CO2 emissions. This is because the spreadsheet simply calculates the actual CO2 emissions from the FCC unit based on three user defined parameters.

The allocation is then set to be equal to the actual CO2 emission predicted. Therefore the new entrant will receive 100% of its predicted CO2 emissions as an allocation. New entrant

guidance states that a verifier’s opinion is also required for refinery applications. This would involve auditing of the values entered for the user defined parameters to ensure that they are

accurate and representative of the proposed FCC unit. DEFRA guidance refers to the NE operator providing a Design Report containing documentation to demonstrate that the projected

inputs for the NE spreadsheet are reasonable (DEFRA 2005b). The verifier will use the Design Report to examine the figures used and the justification of these figures (DEFRA 2005a).

It is concluded that the Phase 1 benchmarking method is not comprehensive enough to cover all

potential refinery new entrants. The list of main refinery units given in Section 1.2.2 indicates the extent of required coverage of the benchmarking method for refineries.

1.5 Assessment of Phase I benchmarks and proposed revisions to these benchmarks

Based on the research completed so far, there are four types of alternative benchmarking

methodology that may be appropriate for use in the refinery sector, as follows:

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Option 1 - Literature Based Benchmark Fuel Consumption Approach

This approach would use the existing allocation equations given in the FES report and

spreadsheet but would be applied to different types of refinery unit using single literature-based value for benchmark fuel consumption.

As summarised in Table 1.5 the refinery BAT Reference Document (BREF) reports values for

fuel use in different types of refinery unit (e.g. hydrocracking in the range 400-1200 MJ per tonne of throughput). For example the allocation equation for a hydrocracker could be based on

the lowest achievable value of 400 MJ per tonne of throughput and would then be:

Ai = Ci * Us/100 * SECt * EFf


Energy Consumption

* Emissions

Factor

tCO2 tonnes

feedstock capacity

% MJ fuel/ tonne

throughput tCO2 /MJ fuel

Where:

Parameter / Variable Value

SECt 400 MJ/tonne of throughput for a hydrocracker unit

An initial review of the international literature on refinery fuel consumption was carried out with the aim of deriving a standard benchmark value for each type of refinery unit. However,

whilst this approach would be transparent and simple, it became clear that the published data on refinery energy use is not comprehensive or detailed enough for benchmarking. Much of the

data required is confidential and is not available in the public domain. The further problem with this approach is that a single benchmark value for a process unit would not take account of the

significant variations in the type of technology employed, feed composition, operating conditions or process energy outputs such as steam and hydrogen. All of these parameters

affect energy use and CO2 emissions and it is beyond the scope of this study to fully describe these complex aspects of refinery unit design and operation. However, variations in these

parameters are the result of genuine differences between refinery units in terms of the intended product mix and they do not represent more/less energy efficient means of making the same

products. Also, UKPIA and EUROPIA have both indicated that this option would not lead to a realistic assessment of the energy requirement and therefore CO2 emissions of new refinery

plant. Therefore Option 1 has not been developed further.

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Option 2 - Solomon Based Benchmark Fuel Consumption Approach

This option would use a direct approach to allocation for each refinery unit with the benchmark

energy consumption figure being provided by the Solomon worldwide refinery model4. This section is not intended to fully describe the Solomon model equations which are proprietary.

The aim is to outline how the Solomon approach could be applied to determine a refinery NE allocation. This option has the backing of UKPIA and EUROPIA but would require further

investigation and development outside the scope of this study prior to being adopted.

For example, the Solomon model provides a standard energy consumption value for severe hydrocracking processes as follows (Solomon 2005):

SECi = 300 + [0.08* (Pi-1500)] - [Di + 1.5*(Gi + Bi)]

Standard Specific Energy

Consumption

= Function of operating

pressure -

Function of product mix for D (diesel), G (gas oil) and B

(balance of products)

btu fuel/barrel of oil

throughput

pressure in psi gauge % of each product type

The key observation from this equation is that energy use is a function of a number of parameters which relate to the hydrocracker design and operating conditions. This approach

provides a more accurate means of predicting energy use (c.f. using a single literature based value) in that it accounts for operating pressure and product mix. The standard energy

consumption is based on US refineries operating in the 1980’s. Modern refineries would be expected to operating more efficiently than this according to the energy efficiency index (EII),

as defined below:

BSEC = EII/100 * SSECt

Benchmark Specific Energy Consumption

= Benchmark EII * Standard Specific Energy

Consumption

MJ fuel/ tonne throughput % MJ fuel/ tonne throughput

Where:


EII 75

4 Solomon Associates Ltd are the world leader in refinery energy use benchmarking. They own a

proprietary model which includes the majority of the world’s refineries. Over a period of 20 years they have developed benchmark fuel consumption values for the full range of refinery units.

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A Solomon EII value of 100 indicates a plant with an efficiency equal to that of the average US

refinery operating in the 1980s, which corresponds to the ‘Standard Energy Consumption’ in the above equations. A Solomon EII plant-specific value below 100 indicates a more efficient

plant, while a value above 100 indicates a less efficient plant. Currently, the average worldwide EII is 92 with a range from 62 to 165 for individual refineries. Based on 2004 data from

Solomon Associates the top 10% of worldwide refineries currently achieve a whole-site EII of 75 or less (Solomon 2005). The Dutch allocation method for refineries is based on incumbents

achieving such a top 10 percentile target. New entrants in the UK therefore might be expected to meet a benchmark EII of 75 for the new process unit itself (i.e. rather than the whole-site)

which should be broadly indicative of BAT for the new plant based on the comprehensive Solomon Associates data (i.e. in the top 10% of current worldwide refinery energy efficiency performance). Solomon (2006) have confirmed that the EII can in principle be applied to

individual refinery units (rather than the whole refinery) for a given capacity and load factor.

With this proposed approach the equations above would be applied to determine the allocation

for a new severe hydrocracking process. Solomon’s model also has equations for standard energy use for the full range of other refinery process units. In the Solomon model some

process units have a single standard energy use figure (e.g. visbreaking = 140 btu/barrel of oil) whilst other are more complex and based on the fundamental physics of the reactions and

theoretical heating duties involved. The key process parameters which are inputs to the Solomon model include:

• Feedstock composition;

• Feedstock temperature and pressure;

• Refinery unit operating temperature and pressure;

• Product mix;

• Process unit type and technology (e.g. catalytic or non-catalytic); and,

• Fuel mix including imports and exports.

These parameters are a function of the fundamental process design given the type of refinery

unit with a specific hydrocarbon feedstock and intended product mix. The parameters are well defined and should be part of the contractual design specification for the new refinery unit. The parameters such as operating temperature and pressure are dictated by the reaction kinetics and

catalyst properties and are essentially fixed for a given product mix and feedstock type. The above process parameters which form the design specification form part of a legal agreement

between the operator and the design/construction contractor and are therefore easily verified.

Solomon Associates Ltd have confirmed that the suggested allocation approach is viable and

can be verified (Solomon 2006). This may involve the verifier meeting with the operator and a Solomon representative to discuss a specific NE application and inspect the data inputs and

outputs used in determining the allocation. The verifier would seek assurance that the proposed process design represents BAT by reference to the sector BREF, although it should be noted that the petroleum refining company will separately need to demonstrate to the competent authority

that their process and its intended operation represents BAT in order to obtain a ‘PPC’ permit, under the IPPC Directive. The verifier would also seek assurance that the model inputs were

representative and accurate but did not allow differentiation for use of heavier crude oil feedstocks, for example, when lighter crude oil feedstocks are available on the market. The

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allocation method must ensure that both combustion and process CO2 emissions arising directly

from the unit are fully accounted for. A simple approach would be for Solomon to determine the total fuel use for the refinery unit including feedstock use but subtract any energy use for

electricity generation as appropriate. The fuel emission factor would be a weighted value calculated according to the actual fuel mix but using standard fuel emission factors for each

fuel. Based on the above considerations, a draft protocol for running of the Solomon model is summarised in the Table below.

Table 1.7 Draft Protocol for Running of Solomon Model to Generate Standard SEC Value for Use in Refinery NE Allocation

Issue Allocation Basis Corresponding Protocol for Solomon Model Use

Practical Implementation

Raw Material Differentiation

Operators should not be rewarded for use of ‘dirtier’ feedstocks to make the same product (e.g. use of heavier and sourer crude oil should not result in extra allowances)

Model should be run using a standard crude oil specification based on UK refinery average crude oil feedstock. For intermediate feedstocks use a standard specification based on refinery operation with lighter/sweeter crude oil.

Solomon model data input for feedstock parameters can be changed to reflect protocol. Verifier to seek assurance this has been done in model.

Technology Differentiation

Operators should not be rewarded for using technologies that are more CO2 intensive when making the same product (e.g. use of non-catalytic reactor to reduce capital cost versus when a catalytic reactor is more energy efficient)

Model should be run using a standard technology type for common processes which represents BAT given the feedstock and product mix. The separate requirement for the operator to justify that their process represents BAT in order to obtain a ‘PPC permit’ under the IPPC Directive is noted.

Solomon model data input for unit operation type can be selected to avoid undue differentiation (e.g. choosing BAT for severe hydrocracking). Verifier to seek assurance this has been done in model.

Double-counting

Double counting of CO2 emissions and energy must be avoided particularly with regard to electricity generation/use and steam import/export in an integrated refinery complex

Model should be run so that only the fuel use that results in direct CO2 emissions from the new process unit is reported. Electricity and steam imports/exports are not to be included. If a new boiler or CHP plant is required at the refinery to power the new entrant process unit then the separate boiler / CHP methodologies should be applied. If an existing boiler or CHP plant at the refinery is required to increase its load factor then this does not qualify as a new entrant and should not receive additional allowances.

Solomon model setup can be modified to report only direct fuel use with contributions from electricity generation and steam import subtracted. Verifier to seek assurance this has been done in model.

Use of BAT Operators are expected to use BAT for energy efficiency

Model should be run assuming that commercially viable heat integration and heat recovery is part of the new unit design. See also above comment about the separate requirement to implement BAT under the IPPC Directive.

Solomon model setup can be modified to assume that BAT for energy saving measures is part of the new refinery unit design. Verifier to seek assurance this has been done in model.

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The proposed allocation method would require the applicant to obtain from Solomon a value for

standard energy consumption for their new refinery unit and submit this in their NER application. The benefit of this approach is that it is uses a world-wide recognised approach to

refinery energy use benchmarking. The approach is reliant on use of the Solomon model which is proprietary and the implementation of the process would require an agreement between the

DTI and Solomon Associates Ltd outside the scope of this study. However, a workable proposed process has been developed during this study based on discussion with relevant

stakeholders and is summarised in the figure below. It is noted that the operator would pay a fee to Solomon Associates Ltd in addition to the verifiers fees. Solomon have indicated that

they typically charge each refinery around $35,000 every 2 years for participation in their worldwide refinery benchmarking study, of which energy benchmarking is only a small part (Solomon 2006). Based on this data, Entec estimate that the Solomon fee would be in the range

£2-10 k per new entrant depending on the complexity of the refinery unit, which is not excessive in relation to the overall current NE application and verification costs of circa £10k in

the application year. The actual fee scale for providing this service would need to be agreed between the DTI, Solomon and UKPIA in due course in the same way that verifiers fees are

currently agreed.

Figure 1.1 Proposed Process for Use of Solomon Based Benchmark Fuel Consumption Approach

Operator submits

Process Design

Specification for NE

refinery unit to Solomon with

appropriate fee

Solomon runs refinery

energy model to

determine Standard

SEC

Solomon issues

Standard SEC

certificate to operator

Operator enters

standard SEC value

into NER allocation

spreadsheet

Allocation Process

Verifier checks that

data submitted by

operator corresponds

with contractual process design

specification

Verifier meets with

Solomon and

operator to check that

data entered correctly into model


certificate matches

model output and

performs sanity check


operator has correctly entered data into

NER allocation

spreadsheet

Verification Process

Sanity checks of

Standard SEC value:

1. Value corresponds

to BAT ranges for unit

type as given in

BREF

2. Value is at lower

end of range of SECs

for actual worldwide

refinery operating units in Solomon

database once EII

factor of 75 is applied

3. Value is broadly

consistent with

calculated energy use

in contractor process

design documentation once EII factor of 75

is applied

Design Report

submitted for

verification

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Option 3 - Solomon Based Integrated Refinery Energy Efficiency Approach

The addition of a new unit at a refinery may affect the overall refinery fuel balance and energy

consumption. This approach recognises this complexity and takes an ‘integrated’ refinery view using the Solomon EII value for the whole refinery both before and after the new refinery unit is

added.

For example, assuming that a refinery currently had an overall Solomon EII of 85, and that a new hydrocracking unit were to be added. It could be assumed that the upgraded refinery would

at least maintain an overall Solomon EII of 85. That is, the expansion should improve or maintain overall current levels of refinery energy efficiency. The benefit of such an integrated

approach would be the proper consideration of the effect of the new hydrocracker on the balance of refinery fuel use, steam production, hydrogen production and use, by-product fuels,

etc. To implement this approach the operator would provide data to Solomon for use in their refinery model. Solomon would then calculate the net emissions increase from the refinery

assuming an EII of 85 was to be maintained once the new refinery unit was installed. The NE allocation would then be based on the net increase in emissions. The drawback of such an

approach is that it would be complex and potentially costly to verify the NE allocation due to the large number of parameters that affect the overall refinery EII.

Further analysis would be required to assess the feasibility of such an integrated refinery

approach to NE allocation. However, the DTI’s preference at this stage is to implement a ‘direct’ approach to new entrant allocation in all sectors (e.g. based on the modified/new

refinery unit only, rather than the modified refinery as a whole). Therefore the ‘integrated’ approach described under Option 3 above has not been developed further. UKPIA and

EUROPIA have commented that this option may lead to a different allocation for the same new unit (i.e. same feedstock, product mix and operating temperature/pressure) installed at two

different refineries and therefore they do not support this option.

Option 4 - Combustion Unit Thermal Efficiency Approach

This approach aims to simplify down the allocation method to benchmark each combustion unit

that makes up or supplies energy to the new refinery unit. For example, a new hydrocracking unit would typically include a fired process heater for pre-heating of the feedstock. Based on the process design, the energy input to the process would be known. The allocation equation for

the feed preheater would then be as follows:

Ai = Ci * Us/100 * SECt / Tt/100 * EFf

Allocation = Capacity * Utilisation * Process Actual

Energy Requirement

*

Benchmark Thermal

Efficiency of Process

Heater

* Emissions

Factor

tCO2 tonnes

feedstock capacity

% MJ/ tonne throughput

% tCO2 /MJ

fuel

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The allocation method would provide benchmarks for thermal efficiency (for example a

benchmark efficiency of 70% for a feed preheater fired by refinery fuel oil) depending on the type of process heater technology in use. The benefits of this approach is that it simplifies the

refinery unit down into basic combustion units which can be benchmarked on efficiency. The main drawback is that it takes no account of the use of feedstock as a fuel (which is significant

for units such as hydrocrackers). It also does not account for process CO2 emissions such as contributions to flaring from the process unit. Complexity may also be added due to the new

unit being integrated with existing units, leading to CO2 allocation problems (e.g. a fired heater may serve both an existing unit and the new unit, thereby leading to problems apportioning fuel

use to the new unit).

Plant Capacity and Load Factor

With all alternative new entrant allocation methods, the plant capacity and load factor are required to determine total annual plant throughput. Data on load factors for UK refinery units

was not available since operators consider this data to be confidential. However, the key points regarding load factors are discussed below.

Information from UKPIA (2006) indicates that refinery plants typically operate at high load

factors (>80%) as opposed to plants in other sectors which may operate at low load factors (e.g. standby power plant often with <40% load factor). For example, after a commissioning period a

new FCC unit will typically run at almost full capacity for 3 years with a high load factor in excess of 95% (UKPIA 2006). There will typically be a month-long shutdown period for

maintenance in the fourth year, giving a four-year average load factor in the region of 93% (UKPIA 2006). The actual load factor will depend upon the operator’s future production plans,

type of technology in use, maintenance schedules and projected sales volumes. Historical refinery load factors can be determined from UK Energy statistics (DTI 2005). Using the most

recent data for the three year period 2002-2004 the average load factor of crude oil distillation units in UK refineries was 95.4%, with annual values ranging from 93.6 % to 97.6% (DTI

2005). Load factors for other refinery units would be expected to correspond to this value on average as they use the distilled crude oil fractions as feedstock and are designed to have an

equivalent capacity. On this basis it is suggested that a sector standard load factor of 95% (i.e. UK historical refinery average value) be used in the allocation methodology.

The plant capacity value should be the nameplate capacity of the equipment (i.e. theoretical

maximum annual production capacity) and should be backed up with verifiable data such as relevant parts of the PPC application for the unit. This evidence to justify plant capacity could

be part of a Design Report provided by the operator as per the verification guidelines (DEFRA 2005b).

Fuel Emission Factors

With all alternative new entrant allocation methods, the fuel emission factor is required to determine the CO2 emission allocation. Refinery fuels are mix of refinery fuel gas generated from process operations, FCC unit coke (this is coke deposited on the circulating catalyst which

is continuously burned off in the FCC unit Regenerator, releasing a lot of heat, much of which is then recovered and used), refinery fuel oil (generally a heavy vacuum residue), and in some

cases imported natural gas. These streams vary enormously in carbon content. Additionally, the carbon content of refinery fuel gas will vary significantly between refineries due to differing

process configurations. For example a refinery with a large catalytic reformer may produce a high proportion of hydrogen (of zero carbon but good heat value) in the fuel gas. However,

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refineries need to use increasing quantities of hydrogen to remove sulphur from the product

streams, and a refinery with a hydrocracker will need to use large quantities of hydrogen, resulting in a refinery gas with higher carbon content.

For example, an operator may use fuel gas which consists of mostly hydrogen in a new

hydrotreating unit, in which case the CO2 emission factor would be close to zero. Alternatively if the fuel gas is 50% hydrogen and 50% methane the emission factor would be 0.10

kgCO2/kWh. For a unit using heavy fuel oil for preheating the feed and consuming a proportion of the feedstock itself the weighted emission factor could be up to around 0.30 kgCO2/kWh.

Natural gas supplies are available to some UK new refinery units but not others, depending on location and infrastructure. However, allocation based on natural gas as a fuel (i.e. 0.19

kgCO2/kWh) would lead to significant under-allocation (up to 30%) in the case of refinery units which use feedstock as a fuel (e.g. catalytic cracking units). It would also lead to significant

over-allocation (up to 500%+) for refinery units which are fed with a hydrogen rich fuel gas (e.g. hydrotreating units). Operators are unlikely to switch to natural gas due to economic

considerations and allocation based on natural gas could lead to competitive distortion if other member states do not do the same for refineries. Use of a standard fuel emission factor based

on UK refinery average fuel mix could also lead to similar under and over-allocation issues for new entrants. However, as explained in the evaluation section, this is a verifiable parameter,

whereas site specific fuel mixes are considered to be difficult to verify. There are other advantages with using a standardised fuel mix as set out in Section 1.6.

Summary

From the research completed and discussion with industry representatives, it is concluded that

Option 2 (Solomon Based Benchmark Fuel Consumption Approach) is the most feasible

alternative allocation method.

The following table assesses the key elements of the Phase I benchmarking method and summarises details of proposed revisions. The proposals are then justified against the agreed

evaluation criteria in the following section.

Table 1.8 Summary assessment of key elements of Phase I benchmarking method and proposals for potential revision

Tests to be applied to Phase I benchmarking method

Answer / Details of proposed revision Source of data

Differentiation: should there be less or more differentiation within the sector (i.e. differentiating based on sub-product, raw materials, technology, fuel, efficiency etc)? If so, what should it be?

The existing NE spreadsheet and report by FES applies only to refinery FCC units and provides no benchmarks for any of the parameters. Differentiation at the refinery unit level is proposed by FES for other types of new entrant using a verifiers opinion for allocation to that unit.

Proposed revision includes standardised emission factor, fuel mix and utilisation. A protocol is proposed to limit the differentiation in the Solomon model.

The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final allocation method.

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Tests to be applied to Phase I benchmarking method

Answer / Details of proposed revision Source of data

is the emission factor consistent with sector best practice

5? If “No”,

what should it be?

No benchmarks for emission factor are provided in existing NE spreadsheet. The user specifies the carbon content of the fuel and the proportion of feedstock used as fuel.

The proposed benchmark Energy Intensity Index (EII) is based on the best refineries in the world (eg. top 10%) which should broadly be indicative of BAT for the sector.

No benchmarks are given for emission factor in the existing NE spreadsheet.

Level at which benchmark is set

is the load factor realistic for new entrants in that sector? If “No”, what should it be?

No benchmarks for load factor are provided in existing NE spreadsheet. The user specifies the annual plant throughput.

The proposed revision uses an industry standard load factor of 95% based on recent UK energy statistics.

No benchmarks given for load factor in the existing NE spreadsheet.

Overall, the proposals for potential revisions to the formulae to be used in the benchmarking method are:

Ai = Ci * U/100 * BSECt * EF


Energy Consumption

* Emissions

Factor

tCO2 tonnes

feedstock capacity

% kWh fuel/ tonne

throughput tCO2 /kWh fuel

Where:

BSECt = EII/100 * SSECt

Benchmark Specific Energy Consumption

= Benchmark EII * Standard Specific Energy

Consumption

kWh fuel/ tonne throughput

% kWh fuel/ tonne throughput

5 Interpreted as ‘Best Available Techniques’ (BAT), as defined in the IPPC Directive. In practice, within

the scope of this study it will only be possible to assess this in broad indicative terms at a sectoral level. It

is clearly not within our scope to define BAT at the level of detail that would be required for a site specific PPC Permit.

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And:


U 95%

EII 75%

EF UK refinery average fuel mix

It is noted that:

• The standard specific energy consumption is the total specific energy consumption

by the process unit based on the Solomon worldwide refinery database. This

includes any feedstock used as fuel but excludes energy inputs which do not give rise to direct CO2 emissions such as steam and electricity. This value is obtained by

the operator from Solomon Associates Ltd for the proposed new refinery process unit.

• The new entrant application should be supported by a technical annex which

includes a copy of the Solomon report.

• The benchmark energy intensity index (EII) for new entrants is initially set at 75

based on the top 10 percentile of worldwide refinery performance but will be

reviewed periodically by the DTI.

• The operator specifies the capacity of the refinery unit based on the process design.

• Values for each parameter should be justified in a Design Report according to

DEFRA guidance on new entrant verification. For example, the Design Report may include a copy of relevant parts of the PPC permit or design documentation to

justify the plant capacity.

1.6 Evaluation of proposed benchmarks

Feasibility

• The Solomon Energy Intensity Index (EII) is used for wide range of purposes in the

petroleum sector in Europe and worldwide and has industry support for use in new

entrant allocation. In particular, it is already being used by the Dutch authorities to benchmark refineries. Literature based benchmarks are not feasible since the

publicly available data on refinery unit energy use is not comprehensive or detailed enough for this application.

• The plant capacity value should be the nameplate capacity of the new refinery unit

and should be backed up with verifiable data.

• It is suggested that a standardised load factor of 95% be used in view of historical

refinery sector data which indicates consistently high load factors.

• Key documents to allow verification may include the PPC application / permit,

process design specification and refinery fuel analysis reports.

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• Solomon Associates have confirmed that they would be able to provide a certified

standard energy consumption figure for any type of new refinery unit. The Solomon model is proprietary which potentially reduces the transparency of this

approach. However, a process that would allow verification has been proposed (see Figure 1.1) and this is considered to be feasible by Solomon Associates Ltd. This

is also backed up by a proposed protocol in Table 1.7 for use of the Solomon model which limits technology differentiation and ensures that BAT is assumed in

calculating the allocation.

• Overall, the proposed approach is regarded as verifiable and an operator should be

able to justify their values for all parameters in the allocation equation.

• A UK refinery average fuel mix is proposed, which is simple and verifiable. This contrasts with site specific fuel mix data which would be considered difficult to

verify.

• The proposed benchmark EII is based on performance of the best refineries in the

world (i.e. top 10 percentile) which should be broadly indicative of BAT for new entrants in the sector. This equates to a benchmark EII of 75 for new entrants,

which is some 15% below the current UK refinery average EII of 88. This indicates that a new entrant refinery unit would be expected to achieve CO2 emissions of

around 15% lower than the equivalent existing refinery unit through the application of BAT. This is considered to be achievable given that new plant will employ the

latest technology and energy efficiency measures compared to existing ageing refinery equipment which may be 20 or more years old.

Incentives for clean technology

• In general there is always an incentive to apply the cleanest technology unless the

benchmark directly includes technology as a parameter. This is not the case with the

proposed benchmark. Though it takes key production conditions such as the feedstock quality and product mix into account, it still benchmarks each process and

therefore includes an incentive to apply the most efficient technology. It proposed to limit the extent to which the feedstock is taken into account. When the feedstock

is being imported to the refinery as raw material no credit will be given in case of a lower quality crude being used. Only when the unit is a downstream process within

the refinery the feedstock composition (ie product from upstream activity) enters the benchmark calculation. In this way the full incentive for using the cleanest and

most efficient technology is preserved while still differentiating by the production activity and conditions related to that.

• Refinery-specific information reduces the degree of standardisation of the

benchmarking approach. However, a standardised simple benchmark approach

would not recognise the significant variations in refinery feedstock composition, degree of feedstock conversion, process conditions and product yield. These variations are genuine differences in refinery units due to the product mix and type

of feedstock. They are also a function of the fundamental physics of the reactions and heating duties involved and accounting for them does not reward the use of less

energy efficient technology provided that the benchmark is based on BAT for that type of unit. In contrast, not accounting for them could lead to significant under and

over allocation and would not incentivise clean technology. For example,

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hydrocrackers allocated based on a single literature based benchmark of 400 MJ/t of

feed could leave some operators (i.e. those carrying out sever hydrocracking) under-allocated by up to 200% - not because they are less efficient but because they are

making different products.

• The assessment of alternative benchmarks for the NE allocation spreadsheet has

also considered using site specific refinery fuel-mix. Such an approach would recognise the need for refineries to fully utilise refinery fuels which could not be

sold on the open market. It would therefore allow the operators to maximise the energy recovery/fuel production per barrel of crude oil processed without the risk of

potentially significant under-allocation. With a standardised approach there could be a shortfall of allowances when a refinery would be using residual fuels with no market value. Whether this in reality would imply an incentive to use other fuels

depends on the site specific conditions. As the residual fuels have no market value the overall financial benefit of using them instead of fuels that could be sold might

still provide sufficient incentive for the most efficient use of refinery fuels. An alternative option of allowing for site specific fuel mix might also have introduced

an undesirable incentive to re-distribute the fuels used within a refinery as to maximise the total allocation of free allowances for a new capacity. The costs of a

process modification would on the other hand make such changes less likely.

• The choice of the most efficient fuel mix depends on site specific conditions. The

many complicating factors preclude any firm conclusion on what provides the strongest incentives to use clean technology. Because of the weightings the

Government has applied to simplicity and incentives for cleaner production, as well as achieving consistency with approaches adopted for other sectors, it is proposed to

use the UK refinery average fuel mix as a standardised approach.

• The benchmark method proposed recognises the need for increased transport fuel

supplies in the UK to meet market demand. This is typically achieved by converting heavier crude oil components to lighter fuels which requires more

energy input. However, such conversion processes help to ensure security of energy supply in the UK by maximising the efficient use of available crude oil

supplies to meet domestic fuel demands.

Competitiveness and impact on investment

• The impact of alternative benchmarks on the allocation to a new refinery unit could

be significant. The maximum impact with no free allowances could be up to 15-30% of running costs. Compared to the total refinery margin (difference between

crude oil price) and average price of refinery products, the CO2 costs would be up to approximately 4-8%. This could affect the profitability of various refinery products.

• The proposed Solomon approach uses a ‘direct’ approach by specifying a

benchmark EII for the new refinery unit and excluding any energy imports and exports. This ensures that the same new refinery unit will receive the same

allocation whichever UK refinery it is installed at. This is as opposed to an ‘integrated’ approach, which is not supported, and would use the EII for the whole

of the modified refinery and accounts for energy imports and exports.

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• The proposed benchmark method allows for the refinery-specific complexity,

feedstock composition, product mix and process conditions in making an allocation. This method prevents significant under or over-allocation compared to using a

single literature-based benchmark per tonne of throughput.

• In reality a refinery is unlikely to change parameters for a new unit such as

technology type, feedstock composition or product mix based on the allocation it would receive. However, if the new unit were to be significantly under or over

allocated there would be competitive distortion c.f. other European refineries. The proposed allocation method is the most likely to avoid such competitive distortions

whilst still making an allocation based on BAT.

• Refineries do not normally have much choice over their fuel mix and BAT is to fully utilise the available refinery fuels. The fuels used also vary significantly in

carbon content between refineries. There is a risk of under or over allocation of allowances when using a standardised fuel mix. Potentially, this introduces impacts

on competitiveness and distortion of the competition. As discussed above, it is not possible to derive a clear conclusion on which approach provides the strongest

incentive to use clean technology. Overall, the standardised approach has been chosen due to Government’s priorities. The weightings the Government has applied

to simplicity and incentives for cleaner production, as well as achieving consistency with approaches adopted for other sectors leads to the standardised fuel mix being

proposed.

• The EII approach takes into account the feedstock quality in assessing the energy

intensity of a process unit. Sites using lower quality, heavier feedstocks have higher energy use to produce fuels but also tend to have higher overall profit

margins. However, the benchmarking method would use a protocol as proposed in Table 1.7 to ensure that use of ‘dirtier’ feedstocks is not rewarded with a higher

emissions allowance.

• The refinery sector is a key part of the UK energy industry and conversion of

available heavier feedstocks improves the security of transport fuel supplies. By meeting need and still applying BAT the EII approach should reduce the risk that

new refinery capacity will be located outside the UK, which should not adversely affect the security of energy supply.

• Given the fact the benchmark takes the above mentioned mainly ‘external’

conditions into account and given that the overall level of energy costs into total

production costs is relatively low in the refinery sector there are considered to be no competition or competitiveness issues attached to the proposed benchmark.

• The proposed benchmark method using the Solomon EII approach is already being

used by the Dutch authorities to benchmark refineries. It is also widely accepted across the industry both in Europe and worldwide as the leading benchmarking

method.

Consistency with incumbent allocations

• The fact that the benchmark takes refinery specific conditions into account

combined with proposed EII benchmark of 75 (equivalent to top 10 percentile of

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worldwide refinery performance) compared to a UK average of 88 suggests that

benchmark will allocate similar to the best performing refinery unit operations.

• Overall, it is expected to allocate approximately 15% less than existing incumbent

refineries in the UK. However, it would be expected to allocate broadly similar allocations compared to ‘best practice’ new incumbent unit operations at refineries.

Such an allocation should be achievable given that new plant will employ the latest technology and energy efficiency measures compared to existing ageing refinery

equipment which may be 20 or more years old.

• Refinery plant tends to operate at high load factors and therefore use of a standard

load factor of 95% is unlikely to lead to significant over-allocation to new entrants compared to incumbents.

1.7 References

DTI 2005. Digest of UK Energy Statistics 2005. Department of Trade and Industry. 2005.

DEFRA 2005a. Revised UK National Allocation Plan (NAP) for the EU ETS. Department of the Environment, Food and Rural Affairs. 14 February 2005.

DEFRA 2005b. Guidance on New Entrant Verification. Department of the Environment, Food

and Rural Affairs. 9 June 2005.

EA 1995a. IPC Guidance Note S2 1.10: Petroleum Processes: Oil Refining and Associated Processes. Environment Agency. November 1995.

EA 1995b. IPC Guidance Note S2 1.01: Combustion Processes: Large Boilers and Furnaces 50MW(th) and Over. Environment Agency. November 1995.

EA 2006. Pollution Inventory England & Wales. Environment Agency. www.environment-

agency.gov.uk (accessed January 2006).

EIPPCB 2001a. Reference Document on Best Available Techniques in the Best Available Techniques for Mineral Oil and Gas Refineries. European IPPC Bureau. December 2001.

EIPPCB 2001b. Reference Document on Best Available Techniques for Large Combustion

Plants (Draft). European IPPC Bureau. March 2001.

Solomon 2005. Description of EII Methodology and EII Statistics. Provided by Solomon

Associates Ltd for use within ETS studies. March 2005.

Solomon 2005. Communication with Lawrence Anness, Solomon Associates Ltd. March 2006.

UKPIA 2006. Communication with Ian McPherson, UK Petroleum Industries Association. February 2006.

EUROPIA 2006. Communication with Bruno Conti, European Petroleum Industries

Association. February 2006.

Wang, M., Lee, H. and Molburg, J. 2004. Allocation of Energy Use in Petroleum Refineries to

Petroleum Products. International Journal of Life Cycle Assessment. 9 (1) 34-44. 2004.