Guidance

Combustion activities: pollution inventory reporting

Updated 29 November 2024

Applies to England

• Publication for Northern Ireland
• Publication for Scotland
• Publication for Wales

If you operate an A1 facility, you must submit data to the pollution inventory. The Environment Agency will have sent you a notice explaining this when your environmental permit was issued.

The ‘general guidance’ available in the pollution inventory reporting guidance gives information that applies to all business and industries. It explains what the pollution inventory is and how to report.

This guidance gives information specific to the combustion sector.

The scope includes:

• common combustion activities (for example, combustion appliances with a rated thermal input of 50MWth or more)
• combustion activities regulated because of their association with other listed activities

If your operations include waste incineration, you may also want to read the incineration activities guidance.

Emissions to air

Relevant pollutants

The combustion of fossil fuels will almost always lead to releases to air of:

• carbon dioxide (CO₂)
• carbon monoxide (CO)
• nitrogen oxides (NOx)
• particulates (total, PM10, PM2.5)

Other pollutants will be released in varying quantities, depending on the fuel and combustion technology used. These may have a significant influence on the environment due to their toxicity or their persistence. This is likely to include:

• dioxins
• hydrogen halides
• non-methane volatile organic compounds (NMVOCs)
• sulfur dioxide (SO₂)
• trace metals
• unburnt hydrocarbons

Pyrolysis and gasification can be used to pre-treat fuels to remove impurities or to produce fuel that can be combusted more readily. Fuels can be either pre-cleaned before combustion or directly combusted. The pollutants emitted from the process are therefore dependent on the fuel used and the nature of the process.

The air pollutants most commonly emitted from different types of fuel are:

• biomass (solid)
  • carbon dioxide (CO₂)
  • carbon monoxide (CO)
  • methane (CH₄)
  • nitrogen oxides (NOx)
  • non-methane volatile organic compounds (NMVOCs)
  • particulate matter (including PM10)
  • sulfur oxides (SOx)
  • trace metals (from sewage sludge)
• coal (solid)
  • carbon dioxide
  • carbon monoxide
  • dioxins
  • fugitive dust
  • hydrogen halides (Hx)
  • methane
  • nitrogen oxides
  • nitrous oxide (N₂O)
  • non-methane volatile organic compounds
  • particulate matter (including PM10)
  • polyaromatic hydrocarbons (PAHs)
  • polychlorinated biphenyls (PCBs)
  • sulfur oxides
  • trace metals
• fuel oil (liquid)
  • carbon dioxide
  • carbon monoxide
  • dioxins
  • hydrogen chloride
  • nitrogen oxides
  • particulate matter (including PM10)
  • polyaromatic hydrocarbons
  • polychlorinated biphenyls
  • sulfur oxides
  • trace metals
• natural gas (gaseous)
  • carbon dioxide
  • carbon monoxide
  • methane
  • nitrogen oxides
• secondary fuels (solid, liquid, or gaseous)
  • ammonia (NH₃)
  • carbon dioxide
  • carbon monoxide
  • dioxins
  • hydrogen sulfide (H₂S)
  • hydrogen halides
  • non-methane volatile organic compounds
  • nitrogen oxides
  • particulate matter (including PM10)
  • polyaromatic hydrocarbons
  • polychlorinated biphenyls
  • sulfur oxides
  • trace metals

Use this list as a guide only. You should verify that there are no other pollutants emitted from your process.

The ‘landfill’ guidance in the pollution inventory reporting: guidance notes includes information about GasSim, a computer model that calculates emissions from landfill gas combustion. It may be useful for some combustion activities.

Subsidiary or substitute fuels may contain other pollutants that will require reporting.

Sources of your emissions

Point source emissions

Point source emissions are exhausted via a stack or vent. That is, from a single point source, into the atmosphere. Abatement equipment, such as an electrostatic precipitator (ESP) or fabric filter (bag house), can be incorporated into the exhaust system prior to discharge to atmosphere. Point source emissions will be the most significant emission source for combustion activities.

Fugitive emissions

Fugitive emissions are those that are not released from a point source such as a stack. They include dust from coal and ash stockpiles and entrainment of pollutants during material handling. Leaks from valves and flanges are also examples of fugitive emissions. With appropriate management and control, these emission sources are generally minor for the combustion sector.

For the pollution inventory, you only need to report fugitive emissions that leave the site. You don’t need to report contained spills. You do need to report vapour emissions that may have dispersed.

Quantifying your emissions and emission factors

Normalising your emission concentrations

Take care to ensure that the emission concentration and flow rate are compatible. For instance, normalised emission concentrations should be multiplied by normalised volumetric flow rates. Alternatively, your actual, measured emission concentrations should be multiplied by actual, measured volumetric flow rates.

Normalised emission rates are quoted in terms of a standard oxygen concentration, and are usually dry gas, at a temperature of 273.15K (0°C) and a pressure of 101.3kPa. It is always good practice to confirm the basis of measured data.

Check the ‘technical guidance and equations’ in the pollution inventory reporting: guidance notes for formulae to convert between normalised and actual emission concentrations.

Using emission factors

If you have monitoring data, use this to complete your pollution inventory return. In the absence of monitoring data or other information, you can use generic emission factors based on currently achievable emission rates from various combustion plant. We have copied relevant factors into this guidance for your convenience.

The existing UK regulatory guidance contains achievable emission data post abatement. This is in terms of mg/MJ of net thermal input, together with the equivalent normalised emission concentrations (mg/m³).

If you know the normalised emission concentration of your combustion appliance, you can calculate the equivalent emission factor in terms of mg/MJ and use Equation 1.

Equation 1: E = A_e x EF x 10^-6

Where:

• E = emission of pollutant, kg/yr
• A_e = annual energy consumption, MJ/yr
• EF = energy emission factor of pollutant, mg/MJ

The relevant mg/MJ and mg/m³ values from the guidance are listed for each fuel category in the relevant section.

The emission factors enable you to estimate the size of combustion plant that would be needed for the emission to be above the reporting threshold values. These estimates are included for reference in the relevant sections.

Solid fuel combustion factors - electricity supply industry (ESI)

The emission factors given as Table 1 represent currently agreed factors for electricity generating stations. They have been developed from measurements on large electricity generating stations (greater than 300 MWth) and are updated regularly by the Joint Environmental Programme (JEP). The emission factors apply to pulverised coal plant with or without fuel gas desulfurisation (FGD).

Further detail on these emission factors is contained in Electricity Supply Industry’s (ESI) Pollution Inventory Methodology. Copies are available from:

The Library, Power Technology
Ratcliffe on Soar Power Station
Ratcliffe on Soar
Nottingham
NG11 OEE

The list includes estimates of the amount of ‘as received’ coal that would need to be burnt in a year to exceed the reporting thresholds. ESI plant burning less than the indicated tonnage of coal can provide either the actual calculated figure, or record emissions as ‘brt’ (below reporting threshold) for that substance. Only enter ‘brt’ if there are no other sources of the substance on site, which would bring your total emissions above the threshold when added to the combustion emissions.

Table 1 UK ESI pollution inventory emission factors for large combustion plant

Substance	Emission factor (kilogrammes per tonne ‘as received’ coal burnt) for pulverised coal plant with or without FGD	Tonnes of coal burnt to exceed reporting threshold
Anthracene	2.7 x 10-7	Reporting threshold unlikely to be reached
Benzo(a)pyrene (BaP)	9.0 x 10-7	1,111,111
Benzo(b)fluoranthene	5.4 x 10-7	1,851,852
Benzo(g,h,i)perylene	5.4 x 10-7	1,851,852
Benzo(k)fluoranthene	5.4 x 10-7	1,851,852
Carbon monoxide	1.1	90,909
Chrysene	3.6 x 10-7	Reporting threshold unlikely to be reached
Dioxins and furans (expressed as I-TEQ)	1.5 x 10-11	666,667
Dioxins and furans (expressed as WHO – TEQ)	1.6 x 10-11	625,000
Fluoranthene	4.5 x 10-7	2,222,222
Indeno(1,2,3-cd)pyrene	5.4 x 10-7	1,851,852
Methane	1.4 x 10-2	714,286
Naphthalene	4.9 x 10-5	2,040,816
Nitrous oxide	2.6 x 10-2	384,615
Non-methane volatile organic compounds	2.7 x 10-2	370,370
PCB (expressed as WHO –TEQ)	1.8 x 10-10	55,556
PCB (expressed as total mass)	9.9 x 10-8	1,010,101
Sulfur trioxide (SO3), reported as part of sulfur oxides (SO2 and SO3 as SO2)	6.3 x 10-2	Report SO3 with SO2 - either estimated from CEMS or using fuel analyses

Particulate matter concentrations are normally measured by continuous emission monitoring systems (CEMS) for ESI plant. The annual mass emission is the instantaneous measured concentration multiplied by the instantaneous volumetric emission. Where load and abatement performance are constant, you can use the average concentration and flow rate. For ESI plant it is generally assumed that each tonne of coal generates 9,000 m³ of flue gas normalised at 6% oxygen concentration.

The pollution inventory return requires you to report the total, PM10 and PM2.5 fractions of the particulate matter. For ESI coal fired plant, the fractions of PM10 and PM2.5 of the total particular matter emitted are assumed to be:

• PM10: 80%
• PM2.5: 40%

You can also use these factors when burning peat or biomass.

Emissions of hydrogen chloride, ‘chlorine and inorganic compounds – as HCl’ and ‘fluorine and inorganic compounds – as HF’ are normally estimated from fuel analysis. This is discussed in the section on Fuel Analysis Data.

You can calculate emissions of NOx from ESI coal fired power plants that do not use CEMS for annual mass emissions using the fuel burn and NOx factors. You need to have previously agreed these with us on a site-specific basis.

Solid fuel combustion – generic emission factors

The generic emission factors (EFi) for coal firing are given as tables 2, 3 and 4. The EFi are expressed in terms of the net heat input into the combustion appliance.

Our estimates for exceeding the reporting threshold are made in terms of the average MWth net thermal input of the plant, assuming that the combustion appliance operates for 100% of the year. If the combustion plant operates for less than 100% of the year, the calculated MWth threshold can simply be divided by the percentage operating time to provide the appropriate MWth threshold.

For single combustion appliances that are rated less than the indicated MWth threshold, you can make a ‘brt’ return for that substance. If you have more than one combustion appliance on site, your aggregate emission may be above the threshold value. If your emissions are below the reporting threshold, you can still report an actual figure if available.

Table 2 Solid fuel firing generic emission factors (net basis) for particulate matter

Technology	Particulate matter emission factor (mg/MJ)	Particulate matter emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
Stoker boiler, in-furnace desulfurisation	9	25	35
CFBC in-bed desulfurisation	9	25	35
PFBC, in-bed desulfurisation and SNCR	9	25	35
PF boiler, dry lime injection, low NOx burners	9	25	35
PF boiler, wet limestone scrubbing, low NOx burners and reburn	5	15	63
PF boiler, wet limestone scrubbing, low NOx burners and selective catalytic reduction (SCR)	5	15	63
Boiler, 20-50MWth, stoker firing	108	300	2
Boiler, 20-50MWth, other firing	108	300	2

Table 3 Solid fuel firing generic emission factors (net basis) for nitrogen oxides (NOx)

Technology	Nitrogen oxides emission factor (mg/MJ)	Nitrogen oxides emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
stoker boiler, in-furnace desulfurisation	105	300	30
CFBC in-bed desulfurisation	70	200	45
PFBC, in-bed desulfurisation and SNCR	21	60	151
PF boiler, dry lime injection, low NOx burners	225	650	14
PF boiler, wet limestone scrubbing, low NOx burners and reburn	87	250	36
PF boiler, wet limestone scrubbing, low NOx burners and SCR	70	200	45
Boiler, 20-50MWth, stoker firing	160	450	20
Boiler, 20-50MWth, other firing	225	650	14

Table 4 Solid fuel firing generic emission factors (net basis) for carbon monoxide (CO)

Technology	Carbon monoxide emission factor (mg/MJ)	Carbon monoxide emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
stoker boiler, in-furnace desulfurisation	50	150	63
CFBC in-bed desulfurisation	50	150	63
PFBC, in-bed desulfurisation and SNCR	10	30	315
PF boiler, dry lime injection, low NOx burners	35	100	91
PF boiler, wet limestone scrubbing, low NOx burners and reburn	35	100	91
PF boiler, wet limestone scrubbing, low NOx burners and SCR	35	100	91
Boiler, 20-50MWth, stoker firing	50	150	63
Boiler, 20-50MWth, other firing	50	150	63

If you have a coal fired plant incorporating selective catalytic reduction (SCR), you can use an emission factor of 4 mg/MJ (10 mg/m³) for ammonia.

Plant employing selective non-catalytic reduction (SNCR) might also release ammonia and nitrous oxide. In the absence of other information, emission factors for SNCR can be assumed to be:

• ammonia: 2 mg/MJ (5 mg/m³)
• nitrous oxide: 21 mg/MJ (60 mg/m³)

Of the total particulate matter emitted, you can assume the PM10 fraction is:

• 40% for unabated emissions of coal, peat or biomass powered plant
• 80% for plant with electrostatic precipitators (ESPs) or bag filters and dry flue gas desulfurisation (FGD)
• 95% for plant with ESPs or bag filters and wet FGD

Liquid fuel combustion factors – electricity supply industry (ESI)

The UK ESI emission factors given as Table 5 are for heavy fuel oil fired plant. Further detail on these emission factors is contained in the ESI methodology.

We have given estimates of the amount of oil that would need to be burnt to exceed the reporting threshold for each emission factor. For ESI plant burning less than the indicated tonnage of oil you can provide either the actual calculated figure, or record emissions as ‘brt’ for that particular substance. Only enter ‘brt’ if there are no other sources of the substance on site, which combined with combustion would bring your total emissions above the threshold.

Table 5 UK ESI pollution inventory emission factors for large combustion plant

Substance	Emission factor (kilogrammes per tonne oil burnt) for heavy oil-fired plant	Tonnes of oil burnt to exceed the reporting threshold
Anthracene	3.6 x 10-7	reporting threshold unlikely to be reached
Benzo(a)pyrene (BaP)	1.2 x 10-6	833,333
Benzo(b)fluoranthene	7.2 x 10-7	1,388,889
Benzo(g,h,i)perylene	7.2 x 10-7	1,388,889
Benzo(k)fluoranthene	7.2 x 10-7	1,388,889
Carbon monoxide	1.5	6,667
Chrysene	4.8 x 10-7	reporting threshold unlikely to be reached
Dioxins and furans (expressed as I-TEQ)	2.1 x 10-11	497,512
Dioxins and furans (expressed as WHO – TEQ)	2.1 x 10-11	497,512
Fluoranthene	6.0 x 10-7	1,666,667
Indeno(1,2,3-cd)pyrene	7.2 x 10-7	1,388,889
Methane	1.8 x 10-2	555,556
Naphthalene	6.5 x 10-5	1,538,462
Nitrous oxide	3.5 x 10-2	285,714
Non-methane volatile organic compounds	3.6 x 10-2	277,778
PCB (expressed as WHO –TEQ)	2.4 x 10-10	41,667
PCB (expressed as total mass)	1.3 x 10-7	769,231
Sulfur trioxide (SO3), reported as part of sulfur oxides (SO2 and SO3 as SO2) - for plant with Mg(OH)2 flue gas conditioning	4.2 x 10-2	report SO3 with SO2 - either estimated from CEMS or using fuel analyses
Sulfur trioxide (SO3), reported as part of sulfur oxides (SO2 and SO3 as SO2) - for plant without Mg(OH)2 flue gas conditioning	1.08	report SO3 with SO2 - either estimated from CEMS or using fuel analyses

If your plant does not use CEMS for determining annual mass emission, you can calculate emissions of NOx from ESI oil fired power plants using the fuel burn and NOx factors. These will have been agreed with us on a station specific basis.

Particulate matter concentrations are normally measured by CEMS for ESI plant. The annual mass emission should be calculated from the instantaneous measured concentration multiplied by the instantaneous volumetric emission, as in Equation 1. Where load is constant, the average concentration and flow rate can be used. For ESI plant it is generally assumed that each tonne of oil generates 12,000m³ of waste gas normalised at 3% oxygen concentration.

You need to report the total, PM10 and PM2.5 fractions of the particulate matter to the pollution inventory. For ESI oil fired plant, the fractions of PM10 and PM2.5 of the total particular matter emitted are assumed to be:

• PM10: 71%
• PM2.5: 52%

Liquid fuel combustion – generic emission factors

You can use Equation 1 to calculate emissions, using achievable emission rates from various liquid fired combustion plant. Relevant emission factors for liquid fired plant (in terms of net heat input), are given as tables 6, 7 and 8. You should use the same methodology as that outlined in the general guidance.

Table 6 Liquid fuel firing generic emission factors (net basis) for particulate matter

Technology	Particulate matter emission factor (mg/MJ)	Particulate matter emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
Gas turbine (post-1994)	0	0	n/a
Gas turbine (pre-1994)	0	0	n/a
Boilers, 20-50MW (light, medium and heavy fuel oil firing)	42	150	8
Boilers, 20-50MW, distillate firing	28	100	12
Compression ignition engine, SCR	40	50	8

Table 7 Liquid fuel firing generic emission factors (net basis) for nitrogen oxides (NOx)

Technology	Nitrogen oxides emission factor (mg/MJ)	Nitrogen oxides emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
Gas turbine (post-1994)	105	125	30
Gas turbine (pre-1994)	140	165	23
Boilers, 20-50MW (light, medium and heavy fuel oil firing)	125	450	25
Boilers, 20-50MW, distillate firing	55	200	58
Compression ignition engine, SCR	125	150	25

Table 8 Liquid fuel firing generic emission factors (net basis) for carbon monoxide (CO)

Technology	Carbon monoxide emission factor (mg/MJ)	Carbon monoxide emission factor (mg/m3)	Net thermal input to exceed reporting threshold (MWth)
Gas turbine (post-1994)	50	60	63
Gas turbine (pre-1994)	84	100	38
Boilers, 20-50MW (light, medium and heavy fuel oil firing)	42	150	75
Boilers, 20-50MW, distillate firing	42	150	75
Compression ignition engine, SCR	125	150	25

For liquid fuel fired plants incorporating SCR, an emission factor of 3 mg/MJ (10 mg/m³) for ammonia can be used.

Of the total particulate matter emitted, you can assume the PM10 fraction is:

• 45% for unabated emissions
• 80% for plant with ESPs or bag filters and dry FGD
• 90% for plant with ESPs or bag filters and wet FGD

Natural gas combustion factors – electricity supply industry (ESI)

The UK ESI emission factors for natural gas fired plant are taken from the ESI methodology. Sulfur dioxide emissions are derived from JEP11SG01: Emission factors for sulfur in natural gas. This is available from:

The Library, Power Technology
Ratcliffe on Soar Power Station
Ratcliffe on Soar
Nottingham
NG11 OEE

Note that the emission factors are based on gross calorific values (GCV).

These substances have an emission factor of zero (0):

• anthracene
• benzo(a)pyrene (BaP)
• benzo(b)fluoranthene
• benzo(g,h,i)perylene
• benzo(k)fluoranthene
• chrysene
• dioxins and furans (expressed as I-TEQ)
• dioxins and furans (expressed as WHO – TEQ)
• fluoranthene
• indeno(1,2,3-cd)pyrene
• naphthalene
• PCB (expressed as WHO –TEQ)

Where the emission factor is not zero (0), we have calculated the approximate GJ of energy that would be required to exceed the reporting threshold, given the listed emission factor and burning only natural gas.

The emission factors are in grams per gigajoule (g/GJ) of gas burnt (based on GCV). UK ESI pollution inventory emission factors for large combustion plant are:

• carbon monoxide: 13 (7,692,300 GJ to exceed ‘brt’)
• methane: 3.7 (2,702,700 GJ to exceed ‘brt’)
• nitrous oxide: 0.5 (20,000,000 GJ to exceed ‘brt’)
• NMVOCs: 0.9 (11,111,000 GJ to exceed ‘brt’)

Nitrogen oxide (NOx) emissions from combined cycle gas turbine (CCGT) and gas-fired plant are generally calculated from continuous monitors.

For the combustion of natural gas, the ESI pollution inventory methodology advises these revised emission factor for particulates from gas turbine plant:

• 0.80 g/GJ GCV
• 0.89 g/GJ NCV (net calorific value)

For gas turbines running on distillate fuel, for example during start-up, you can use the generic liquid fuel firing emission factors. In this case, 100% of the particulate matter emission assumed to be PM2.5.

Natural gas combustion – generic emission factors

Emission factors based on achievable emission rates from various natural gas fired combustion plant can be used in Equation 1. Relevant emission factors for natural gas fired plant (in terms of net heat input) are given as tables 9, 10 and 11. You should use the same methodology as that outlined in the general guidance. Note that the emission factors are based on net calorific values (NCV).

Table 9 Natural gas fuel firing generic emission factors (net basis) for particulate matter

Technology	Particulate matter emission factor (mg/MJ)	Particulate matter emission factor (mg/m3)	Net input to exceed reporting threshold (MWth)
Gas turbine, after 1994	0	0	n/a
Gas turbine, pre- 1994	0	0	n/a
Boilers, 20-50MW, flue gas recirculation (FGR)	1	5	317
Dual fuel compression ignition engine, SCR	15	20	21
Dual fuel compression ignition engine, lean burn	15	20	21
Spark ignition engine, SCR1	0	0	n/a
Spark ignition engine, lean burn, exhaust gas recirculation (EGR)	0	0	n/a

Table 10 Natural gas fuel firing generic emission factors (net basis) for nitrogen oxides (NOx)

Technology	Nitrogen oxides emission factor (mg/MJ)	Nitrogen oxides emission factor (mg/m3)	Net input to exceed reporting threshold (MWth)
Gas turbine, after 1994	50	60	63
Gas turbine, pre- 1994	105	125	30
Boilers, 20-50MW, FGR	39	140	81
Dual fuel compression ignition engine, SCR	85	100	37
Dual fuel compression ignition engine, lean burn	125	150	25
Spark ignition engine, SCR1	85	100	37
Spark ignition engine, lean burn, exhaust gas recirculation (EGR)	125	150	25

Table 11 Natural gas fuel firing generic emission factors (net basis) for carbon monoxide (CO)

Technology	Carbon monoxide emission factor (mg/MJ)	Carbon monoxide emission factor (mg/m3)	Net input to exceed reporting threshold (MWth)
Gas turbine, after 1994	50	60	63
Gas turbine, pre- 1994	84	100	38
Boilers, 20-50MW, FGR	30	100	106
Dual fuel compression ignition engine, SCR	375	450	9
Dual fuel compression ignition engine, lean burn	125	150	25
Spark ignition engine, SCR1	125	150	25
Spark ignition engine, lean burn, exhaust gas recirculation	125	150	25

For both compression ignition engines and spark ignition engines, you can use a factor of 170 mg/MJ (200 mg/m³) for NMVOCs. For natural gas fired plants incorporating SCR, you can use an emission factor of 8 mg/MJ (10 mg/m³) for ammonia.

Apart from mercury, trace metallic elements in natural gas are assumed to be zero. For mercury, an emission factor of 1 x 10^-4 mg/m³ of gas burnt can be used to calculate mercury vapour emissions. In this case, greater than 1 x 10¹⁰ m³ of gas would need to be burnt in a year to exceed the reporting threshold.

The PM10 and PM2.5 fractions can be assumed to be 100% of the total particulate matter emitted when burning natural gas.

Fuel analysis data

General notes

The use of fuel analysis data to determine emissions is similar to the use of emission factors. Check the technical guidance and equations in our pollution inventory reporting guidance for basic equations used in fuel analysis emission calculations. You might find equations 7 and 8, and example E useful.

When using equation 7, it is normally assumed that all the sulfur in the fuel is converted to SO₂. When using the equation for coal fired plant, you should assume that 5% of the sulfur is retained in the ash.

When using equations 7 or 8, be aware that the amounts of pollutants present in the fuel can vary significantly. For UK ESI plant, the trace element concentration in coal is calculated as a yearly weighted mean average for each plant, based on the delivered tonnage of coal. Where coals have not been analysed for trace element content, then you should use an average value for coals from a similar geographic region.

Solid fuel analysis

For elements that are captured effectively in either bottom ash or fly ash, equation 7 can result in the overestimation of emissions. Emission quantities of volatile and semi-volatile components will greatly depend on the emission temperature and abatement collection efficiency as volatile and semi-volatile substances can condense on fine particulate matter. Increasing the emission temperature may significantly increase the pollutant release rate of volatile components. You need to consider any changes to the process conditions that may affect pollutant partitioning or capture in emission calculations by the determination of site-specific retention and enrichment factors.

Mass emissions of trace metallic elements from coal combustion can be calculated indirectly from the amount of particulate matter emitted. These must be corrected by factors representing the concentration of the trace element in the coal and how much of the element is chemically present in the ash, using equations 2 and 3 (below). The total emission is the sum of the emission from the non-volatile and volatile phases.

Non-volatile phase

Equation 2: E_nv = PC_coal x (100 / AA) x F x R x PM

Where:

• E_nv = non-volatile pollutant emission (kg/yr)
• PC_coal = trace element weight fraction in the coal
• AA = average ash mass percentage in coal (%)
• F = retention factor in ash
• R = enrichment factor
• PM = particulate matter emission (kg/yr)

Volatile phase

Equation 3: E_v = PC_coal x (1 – F) x CB

Where:

• E_v = volatile pollutant emission (kg/yr)
• PC_coal = trace element weight fraction in the coal
• F = retention factor in ash
• CB = coal burned (kg/yr)

To use equations 2 and 3, you need to know the percentage of trace metallic elements present in the coal. Coal composition can vary significantly depending on the source of the fuel. As such, you should obtain information on the trace elements from the supplier or have specific coal analysis carried out.

Common retention and enrichment factors that are used across UK coal fired ESI plant are given below. These factors are appropriate for exhaust gas temperatures of less than 130°C. For higher exhaust gas temperatures, the factors may differ, especially for the more volatile elements. In this case, you should use site-specific factors.

Retention factors for UK coal fired ESI:

• arsenic: 1
• cadmium: 1
• chromium (total): 1
• copper: 1
• lead: 1
• mercury: 0.5
• nickel: 1
• selenium: 0.8
• zinc: 1

Enrichment factors for UK coal fired ESI:

• arsenic: 3.4
• cadmium: 4.5
• chromium (total): 1.7
• copper: 2.0
• lead: 2.9
• mercury: 4.0
• nickel: 1.9
• selenium: 9.0
• zinc: 4.0

The use of FGD will lead to the retention of sulfur from the emission, but it will also lead to the retention of soluble acid halides such as hydrochloric acid (HCl) and hydrogen fluoride (HF). In the absence of site-specific data for FGD, use these retention factors:

• HCl: 98%
• HF: 72%

For wet limestone and gypsum systems, you should use these FGD retention factors (vapour):

• mercury: 0.50
• selenium: 0.65

You should also consider fuel composition when determining pollutant emissions from subsidiary or substitute fuels. In the absence of other data, for fuels such as biomass that have a low ash content, the enrichment and retention factors given above can be used.

Liquid fuel analysis

You can use Equation 3 to calculate trace metallic emissions from oil-fired plant. Within the ESI methodology, you can assume that for large, heavy fuel oil plant with particulate or grit arrestors, a retention factor of 0.75 can be used for trace elements. Appropriate retention factors should be determined for other abatement plant. In the absence of abatement, the retention factor would be zero.

As with coal, information on the composition of the trace elements in the fuel should be obtained from the supplier or be measured.

Emissions of halogens from oil-fired plant can be assumed to be zero.

Natural gas analysis

Natural gas supplies in the UK are currently assumed to have zero trace metal content, except for mercury. Emission factors for mercury are given in the section Natural gas combustion – generic emission factors (above).

Emissions of halogens from natural gas fired plant are assumed to be zero.

Where no specific gas analysis is available, you can calculate emissions from gas venting by assuming natural gas to comprise:

• 92% methane (CH₄)
• 6% NMVOCs
• 1% carbon dioxide (CO₂)
• 1% nitrogen

Estimating fugitive emissions

For solid fuel plant, particulate matter emissions can occur by dust blow from coal stocks and ash storage areas. You can assume these to be low in comparison to stack emissions unless specific events have occurred which you know have released significant quantities of material off-site.

Techniques for estimating fugitive emissions from the surface of stockpiles are limited. Your options include measuring ambient dust levels upwind and downwind of the source of interest and/or applying predictive mathematical models.

Methane and other hydrocarbon emissions from coal stocks and oil tank filling can be assumed to be small in relation to emissions through the stacks. For natural gas fired plant, where gas is vented to atmosphere for operational and maintenance purposes, you should calculate the mass emissions of carbon dioxide, methane, and NMVOCs from the gas composition.

Emissions to water

Emissions of substances to water can be either direct to controlled waters or indirect, following transfer to off-site effluent treatment plant.

Check the ‘general guidance’ in the pollution inventory reporting guidance for what constitutes an emission or a transfer.

We recognise that it might be hard to separate EPR and non-EPR releases of substances to water where both pass through a common monitoring point as a combined effluent. In cases where it is not possible to estimate the individual contributions, you should use the combined effluent value.

Relevant pollutants

You need to consider a variety of substances when reporting emissions to water or transfers in wastewater. The most common substances from combustion activities are:

• arsenic
• cadmium
• chlorides
• chromium
• copper
• fluorides
• iron
• lead
• mercury
• nickel
• nitrogen (total as N)
• phosphorus (total as P)
• zinc

Use this list as a guide only and verify that there are no other pollutants emitted from your processes. The significance of each parameter depends on the specific plant configuration and the process applied. This also determines the type and amount of pollutant present in the wastewater prior to treatment.

Emission sources

Emissions to water generally come from the following sources:

• ash transport wastewater
• boiler blowdown
• cleaning water
• cooling water system
• demineralised water treatment plant
• FGD wastewater treatment plant
• surface water run-off from storage areas (for example, fuel, ash, FGD material)

You need to consider all emission sources to water and characterise the flows and emission concentrations from each source.

Off-site waste transfers

You must classify wastes using the European Waste Catalogue 6-digit codes and the relevant Waste Framework Directive disposal or recovery codes. Check the ‘reporting codes list’ in the pollution inventory reporting guidance.

Relevant wastes

Wastes that are commonly produced by combustion activities are:

• bottom ash and boiler slag
• chemical wastes
• flue gas desulfurisation residues
• fluidised bed ash
• fly-ash
• general waste
• metallic wastes
• special wastes (for instance solvents)
• waste oils

You do not have to report materials that are recognised as by-products rather than wastes, such as sold gypsum, under the off-site waste transfer section.

General waste should only include those from your installation itself. It does not include associated wastes from areas outside the installation boundary such as offices or canteens.

Transboundary shipments of hazardous waste

You must report the annual quantities of any transboundary hazardous waste shipments taking place to the pollution inventory.