9/98 External Combustion Sources 1.1-1

1.1 Bituminous And Subbituminous Coal Combustion

1.1.1 General

Coal is a complex combination of organic matter and inorganic mineral matter formed over eons

from successive layers of fallen vegetation. Coals are classified by rank according to their progressive

alteration in the natural metamorphosis from lignite to anthracite. Coal rank depends on the volatile

matter, fixed carbon, inherent moisture, and oxygen, although no single parameter defines a rank. 

Typically, coal rank increases as the amount of fixed carbon increases and the amount of volatile matter

and moisture decreases. 

Bituminous coals are by far the largest group and are characterized as having lower fixed carbon

and higher volatile matter than anthracite. The key distinguishing characteristics of bituminous coal are

its relative volatile matter and sulfur content as well as its slagging and agglomerating characteristics. 

Subbituminous coals have higher moisture and volatile matter and lower sulfur content than bituminous

coals and may be used as an alternative fuel in some boilers originally designed to burn bituminous

coals.1 Generally, bituminous coals have heating values of 10,500 to 14,000 British thermal units per

pound (Btu/lb) on a wet, mineral-matter-free basis.2 As mined, the heating values of typical U.S.

bituminous coals range from 10,720 to 14,730 Btu/lb.3 The heating values of subbituminous coals range

from 8,300 to 11,500 Btu/lb on a wet, mineral-matter-free basis2, and from 9,420 to 10,130 Btu/lb on an

as-mined basis.3 Formulae and tables for classifying coals are given in Reference 2. 

1.1.2 Firing Practices4

Coal-fired boilers can be classified by type, fuel, and method of construction. Boiler types are

identified by the heat transfer method (watertube, firetube, or cast iron), the arrangement of the heat

transfer surfaces (horizontal or vertical, straight or bent tube), and the firing configuration (suspension,

stoker, or fluidized bed). The most common heat transfer method for coal-fired boilers is the watertube

method in which the hot combustion gases contact the outside of the heat transfer tubes, while the boiler

water and steam are contained within the tubes.

Coal-fired watertube boilers include pulverized coal, cyclone, stoker, fluidized bed, and handfed

units. In stoker-fired systems and most handfed units, the fuel is primarily burned on the bottom of the

furnace or on a grate. In a fluidized bed combustor (FBC), the coal is introduced to a bed of either

sorbent or inert material (usually sand) which is fluidized by an upward flow of air. In pulverized

coal-fired (PC-fired) boilers, the fuel is pulverized to the consistency of talcum powder (i.e., at least 70

percent of the particles will pass through a 200-mesh sieve) and pneumatically injected through the

burners into the furnace. Combustion in PC-fired units takes place almost entirely while the coal is

suspended in the furnace volume. PC-fired boilers are classified as either dry bottom or wet bottom (also

referred to as slag tap furnaces), depending on whether the ash is removed in a solid or molten state. In

dry bottom furnaces, coals with high fusion temperatures are burned, resulting in dry ash. In wet bottom

furnaces, coals with low fusion temperatures are used, resulting in molten ash or slag.

Depending upon the type and location of the burners and the direction of coal injection into the

furnace, PC-fired boilers can also be classified into two different firing types, including wall, and

tangential. Wall-fired boilers can be either single wall-fired, with burners on only one wall of the

furnace firing horizontally, or opposed wall-fired, with burners mounted on two opposing walls. 

Tangential (or corner-fired) boilers have burners mounted in the corners of the furnace. The fuel and air

are injected tangent to an imaginary circle in the plane of the boilers. Cyclone furnaces are often
1.1-2 EMISSION FACTORS 9/98

categorized as PC-fired systems even though the coal is crushed to a maximum size of about 4-mesh. 

The coal is fed tangentially, with primary air, into a horizonal cylindrical furnace. Smaller coal particles

are burned in suspension while larger particles adhere to the molten layer of slag on the combustion

chamber wall. Cyclone boilers are high-temperature, wet-bottom type systems. 

Stoker-fired systems account for the vast majority of coal-fired watertube boilers for industrial,

commercial, and institutional applications. Most packaged stoker units designed for coal firing are small

and can be divided into three groups: underfeed stokers, overfeed stokers, and spreader stokers. 

Underfeed stokers are generally either the horizontal-feed, side-ash-discharge type or the gravity-feed,

rear-ash-discharge type. An overfeed stoker uses a moving grate assembly in which coal is fed from a

hopper onto a continuous grate which conveys the fuel into the furnace. In a spreader stoker, mechanical

or pneumatic feeders distribute coal uniformly over the surface of a moving grate. The injection of the

fuel into the furnace and onto the grate combines suspension burning with a thin, fast-burning fuel bed. 

The amount of fuel burned in suspension depends primarily on fuel size and composition, and air flow

velocity. Generally, fuels with finer size distributions, higher volatile matter contents, and lower

moisture contents result in a greater percentage of combustion and corresponding heat release rates in

suspension above the bed.

FBCs, while not constituting a significant percentage of the total boiler population, have

nonetheless gained popularity in the last decade, and today generate steam for industries, cogenerators,

independent power producers, and utilities. There are two major categories of FBC systems: (1)

atmospheric, operating at or near ambient pressures, and (2) pressurized, operating from 4 to 30

atmospheres (60 to 450 pounds per square inch gauge). At this time, atmospheric FBCs are more

advanced (or commercialized) than pressurized FBCs. The two principal types of atmospheric FBCs are

bubbling bed and circulating bed. The feature that varies most fundamentally between these two types is

the fluidization velocity. In the bubbling bed design, the fluidation velocity is relatively low in order to

minimize solids carryover or elutriation from the combustor. Circulating FBCs, however, employ high

fluidization velocities to promote the carryover or circulation of the solids. High-temperature cyclones

are used in circulating FBCs and in some bubbling FBCs to capture the solid fuel and bed material for

return to the primary combustion chamber. The circulating FBC maintains a continuous, high-volume

recycle rate which increases the residence time compared to the bubbling bed design. Because of this

feature, circulating FBCs often achieve higher combustion efficiencies and better sorbent utilization than

bubbling bed units.

Small, coal-fired boilers and furnaces are found in industrial, commercial, institutional, or

residential applications and are sometimes capable of being hand-fired. The most common types of

firetube boilers used with coal are the horizontal return tubular (HRT), Scotch, vertical, and the firebox. 

Cast iron boilers are also sometimes available as coal-fired units in a handfed configuration. The HRT

boilers are generally fired with gas or oil instead of coal. The boiler and furnace are contained in the

same shell in a Scotch or shell boiler. Vertical firetube boilers are typically small singlepass units in

which the firetubes come straight up from the water-cooled combustion chamber located at the bottom of

the unit. A firebox boiler is constructed with an internal steel-encased, water-jacketed firebox. Firebox

firetube boilers are also referred to as locomotive, short firebox, and compact firebox boilers and employ

mechanical stokers or are hand-fired.
9/98 External Combustion Sources 1.1-3

1.1.3 Emissions4

Emissions from coal combustion depend on the rank and composition of the fuel, the type and

size of the boiler, firing conditions, load, type of control technologies, and the level of equipment

maintenance. The major pollutants of concern from bituminous and subbituminous coal combustion are

particulate matter (PM), sulfur oxides (SOx), and nitrogen oxides (NOx). Some unburned combustibles,

including carbon monoxide (CO) and numerous organic compounds, are generally emitted even under

proper boiler operating conditions. 

1.1.3.1 Particulate Matter4

 - 

PM composition and emission levels are a complex function of boiler firing configuration, boiler

operation, pollution control equipment, and coal properties. Uncontrolled PM emissions from coal-fired

boilers include the ash from combustion of the fuel as well as unburned carbon resulting from incomplete

combustion. In pulverized coal systems, combustion is almost complete; thus, the emitted PM is

primarily composed of inorganic ash residues. 

Coal ash may either settle out in the boiler (bottom ash) or entrained in the flue gas (fly ash). 

The distribution of ash between the bottom ash and fly ash fractions directly affects the PM emission rate

and depends on the boiler firing method and furnace type (wet or dry bottom). Boiler load also affects

the PM emissions as decreasing load tends to reduce PM emissions. However, the magnitude of the

reduction varies considerably depending on boiler type, fuel, and boiler operation.

Soot blowing is also a source of intermittent PM emissions in coal-fired boilers. Steam soot and

air soot blowing is periodically used to dislodge ash from heat transfer surfaces in the furnace,

convective section, economizer, and air preheater.

Particulate emissions may be categorized as either filterable or condensable. Filterable emissions

are generally considered to be the particles that are trapped by the glass fiber filter in the front half of a

Reference Method 5 or Method 17 sampling train. Vapors and particles less than 0.3 microns pass

through the filter. Condensable particulate matter is material that is emitted in the vapor state which later

condenses to form homogeneous and/or heterogeneous aerosol particles. The condensable particulate

emitted from boilers fueled on coal or oil is primarily inorganic in nature.

1.1.3.2 Sulfur Oxides4

 -

Gaseous SOx from coal combustion are primarily sulfur dioxide (SO2), with a much lower

quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the organic and pyritic

sulfur in the coal are oxidized during the combustion process. On average, about 95 percent of the sulfur

present in bituminous coal will be emitted as gaseous SOx, whereas somewhat less will be emitted when

subbituminous coal is fired. The more alkaline nature of the ash in some subbituminous coals causes

some of the sulfur to react in the furnace to form various sulfate salts that are retained in the boiler or in

the flyash.

1.1.3.3 Nitrogen Oxides5-6 - 

NOx emissions from coal combustion are primarily nitric oxide (NO), with only a few volume

percent as nitrogen dioxide (NO2). Nitrous oxide (N2O) is also emitted at a few parts per million. NOx

formation results from thermal fixation of atmospheric nitrogen in the combustion flame and from

oxidation of nitrogen bound in the coal. Experimental measurements of thermal NOx formation have

shown that the NOx concentration is exponentially dependent on temperature and is proportional to

nitrogen concentration in the flame, the square root of oxygen concentration in the flame, and the gas

residence time.7

 Cyclone boilers typically have high conversion of nitrogen to NOx Typically, only 20 to

60 percent of the fuel nitrogen is converted to NOx. Bituminous and subbituminous coals usually
1.1-4 EMISSION FACTORS 9/98

contain from 0.5 to 2 weight percent nitrogen, mainly present in aromatic ring structures. Fuel nitrogen

can account for up to 80 percent of total NOx from coal combustion.

1.1.3.4 Carbon Monoxide - 

The rate of CO emissions from combustion sources depends on the fuel oxidation efficiency of

the source. By controlling the combustion process carefully, CO emissions can be minimized. Thus, if a

unit is operated improperly or is not well-maintained, the resulting concentrations of CO (as well as

organic compounds) may increase by several orders of magnitude. Smaller boilers, heaters, and furnaces

typically emit more CO and organics than larger combustors. This is because smaller units usually have

less high-temperature residence time and, therefore, less time to achieve complete combustion than larger

combustors. Combustion modification techniques and equipment used to reduce NOx can increase CO

emissions if the modification techniques are improperly implemented or if the equipment is improperly

designed.

1.1.3.5 Organic Compounds - 

As with CO emissions, the rate at which organic compounds are emitted depends on the

combustion efficiency of the boiler. Therefore, combustion modifications that change combustion

residence time, temperature, or turbulence may increase or decrease concentrations of organic

compounds in the flue gas.

Organic emissions include volatile, semivolatile, and condensable organic compounds either

present in the coal or formed as a product of incomplete combustion (PIC). Organic emissions are

primarily characterized by the criteria pollutant class of unburned vapor-phase hydrocarbons. These

emissions include alkanes, alkenes, aldehydes, alcohols, and substituted benzenes (e.g., benzene, toluene,

xylene, and ethyl benzene). 8,9

Emissions of polychlorinated dibenzo-p-dioxins and polychlorinated dibenzofurans

(PCDD/PCDF) also result from the combustion of coal. Of primary interest environmentally are

tetrachloro- through octachloro- dioxins and furans. Dioxin and furan emissions are influenced by the

extent of destruction of organics during combustion and through reactions in the air pollution control

equipment. The formation of PCDD/PCDF in air pollution control equipment is primarily dependent on

flue gas temperature, with maximum potential for formation occurring at flue gas temperatures of 450

degrees to 650 degrees Fahrenheit.

The remaining organic emissions are composed largely of compounds emitted from combustion

sources in a condensed phase. These compounds can almost exclusively be classed into a group known

as polycyclic organic matter (POM), and a subset of compounds called polynuclear aromatic

hydrocarbons (PNA or PAH). Polycyclic organic matter is more prevalent in the emissions from coal

combustion because of the more complex structure of coal.

1.1.3.6 Trace MetalsTrace metals are also emitted during coal combustion. The quantity of any given metal emitted,

in general, depends on:

- the physical and chemical properties of the metal itself;

- the concentration of the metal in the coal;

- the combustion conditions; and
9/98 External Combustion Sources 1.1-5

- the type of particulate control device used, and its collection efficiency as a function of

particle size.

Some trace metals become concentrated in certain particle streams from a combustor (e.g.,

bottom ash, collector ash, and flue gas particulate) while others do not.10 Various classification schemes

have been developed to describe this partitioning behavior.10-12 These classification schemes generally

distinguish between:

- Class 1: Elements that are approximately equally concentrated in the fly ash and bottom

ash, or show little or no small particle enrichment. Examples include manganese,

beryllium, cobalt, and chromium.

- Class 2: Elements that are enriched in fly ash relative to bottom ash, or show increasing

enrichment with decreasing particle size. Examples include arsenic, cadmium, lead, and

antimony.

- Class 3: Elements which are emitted in the gas phase (primarily mercury and, in some

cases, selenium).

Control of Class 1 metals is directly related to control of total particulate matter emissions, while control

of Class 2 metals depends on collection of fine particulate. Because of variability in particulate control

device efficiencies, emission rates of these metals can vary substantially. Because of the volatility of

Class 3 metals, particulate controls have only a limited impact on emissions of these metals.

1.1.3.7 Acid GasesIn addition to SO2 and NOx emissions, combustion of coal also results in emissions of chlorine

and fluorine, primarily in the form of hydrogen chloride (HCl) and hydrogen fluoride (HF). Lesser

amounts of chlorine gas and fluorine gas are also emitted. A portion of the chlorine and fluorine in the

fuel may be absorbed onto fly ash or bottom ash. Both HCl and HF are water soluble and are readily

controlled by acid gas scrubbing systems.

1.1.3.8 Fugitive Emissions - 

Fugitive emissions are defined as pollutants which escape from an industrial process due to

leakage, materials handling, inadequate operational control, transfer, or storage. The fly ash handling

operations in most modern utility and industrial combustion sources consist of pneumatic systems or

enclosed and hooded systems which are vented through small fabric filters or other dust control devices. 

The fugitive PM emissions from these systems are therefore minimal. Fugitive particulate emissions can

sometimes occur during fly ash transfer operations from silos to trucks or rail cars.

1.1.3.9 Greenhouse Gases13-18 -

Carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions are all produced

during coal combustion. Nearly all of the fuel carbon (99 percent) in coal is converted to CO2 during the

combustion process. This conversion is relatively independent of firing configuration. Although the

formation of CO acts to reduce CO2 emissions, the amount of CO produced is insignificant compared to

the amount of CO2 produced. The majority of the fuel carbon not converted to CO2 is entrained in

bottom ash. CO2 emissions for coal vary with carbon content, and carbon content varies between the

classes of bituminous and subbituminous coals. Further, carbon content also varies within each class of

coal based on the geographical location of the mine.

Formation of N2O during the combustion process is governed by a complex series of reactions

and its formation is dependent upon many factors. Formation of N2O is minimized when combustion
1.1-6 EMISSION FACTORS 9/98

temperatures are kept high (above 1575oF) and excess air is kept to a minimum (less than 1 percent). 

N2O emissions for coal combustion are not significant except for fluidized bed combustion (FBC), where

the emissions are typically two orders of magnitude higher than all other types of coal firing due to areas

of low temperature combustion in the fuel bed. 

 Methane emissions vary with the type of coal being fired and firing configuration, but are

highest during periods of incomplete combustion, such as the start-up or shut-down cycle for coal-fired

boilers. Typically, conditions that favor formation of N2O also favor emissions of CH4.

1.1.4 Controls4

Control techniques for criteria pollutants from coal combustion may be classified into three

broad categories: fuel treatment/substitution, combustion modification, and postcombustion control. 

Emissions of noncriteria pollutants such as particulate phase metals have been controlled through the use

of post combustion controls designed for criteria pollutants. Fuel treatment primarily reduces SO2 and

includes coal cleaning using physical, chemical, or biological processes; fuel substitution involves

burning a cleaner fuel. Combustion modification includes any physical or operational change in the

furnace or boiler and is applied primarily for NOx control purposes, although for small units, some

reduction in PM emissions may be available through improved combustion practice. Postcombustion

control employs a device after the combustion of the fuel and is applied to control emissions of PM, SO2

, and NOx for coal combustion.

1.1.4.1 Particulate Matter Control4

 -

The principal control techniques for PM are combustion modifications (applicable to small

stoker-fired boilers) and postcombustion methods (applicable to most boiler types and sizes). 

Uncontrolled PM emissions from small stoker-fired and hand-feed combustion sources can be minimized

by employing good combustion practices such as operating within the recommended load ranges,

controlling the rate of load changes, and ensuring steady, uniform fuel feed. Proper design and operation

of the combustion air delivery systems can also minimize PM emissions. The postcombustion control of

PM emissions from coal-fired combustion sources can be accomplished by using one or more or the

following particulate control devices:

C Electrostatic precipitator (ESP),

C Fabric filter (or baghouse),

C Wet scrubber,

C Cyclone or multiclone collector, or

C Side stream separator.

Electrostatic precipitation technology is applicable to a variety of coal combustion sources. 

Because of their modular design, ESPs can be applied to a wide range of system sizes and should have no

adverse effect on combustion system performance. The operating parameters that influence ESP

performance include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and

precipitator voltage and current. Other factors that determine ESP collection efficiency are collection

plate area, gas flow velocity, and cleaning cycle. Data for ESPs applied to coal-fired sources show

fractional collection efficiencies greater than 99 percent for fine (less than 0.1 micrometer) and coarse

particles (greater than 10 micrometers). These data show a reduction in collection efficiency for particle

diameters between 0.1 and 10 micrometers.

Fabric filtration has been widely applied to coal combustion sources since the early 1970s and

consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main

shell structure incorporating dust hoppers. The particulate removal efficiency of fabric filters is
9/98 External Combustion Sources 1.1-7

dependent on a variety of particle and operational characteristics. Particle characteristics that affect the

collection efficiency include particle size distribution, particle cohesion characteristics, and particle

electrical resistivity. Operational parameters that affect fabric filter collection efficiency include

air-to-cloth ratio, operating pressure loss, cleaning sequence, interval between cleanings, cleaning

method, and cleaning intensity. In addition, the particle collection efficiency and size distribution can be

affected by certain fabric properties (e. g., structure of fabric, fiber composition, and bag properties). 

Collection efficiencies of fabric filters can be as high as 99.9 percent. 

Wet scrubbers, including venturi and flooded disc scrubbers, tray or tower units, turbulent

contact absorbers, or high-pressure spray impingement scrubbers are applicable for PM as well as SO2

control on coal-fired combustion sources. Scrubber collection efficiency depends on particle size

distribution, gas side pressure drop through the scrubber, and water (or scrubbing liquor) pressure, and

can range between 95 and 99 percent for a 2-micron particle.

Cyclone separators can be installed singly, in series, or grouped as in a multicyclone or

multiclone collector. These devices are referred to as mechanical collectors and are often used as a

precollector upstream of an ESP, fabric filter, or wet scrubber so that these devices can be specified for

lower particle loadings to reduce capital and/or operating costs. The collection efficiency of a

mechanical collector depends strongly on the effective aerodynamic particle diameter. Although these

devices will reduce PM emissions from coal combustion, they are relatively ineffective for collection of

particles less than 10 micron (PM-10). The typical overall collection efficiency for mechanical collectors

ranges from 90 to 95 percent.

The side-stream separator combines a multicyclone and a small pulse-jet baghouse to more

efficiently collect small-diameter particles that are difficult to capture by a mechanical collector alone. 

Most applications to date for side-stream separators have been on small stoker boilers.

Atmospheric fluidized bed combustion (AFBC) boilers may tax conventional particulate control

systems. The particulate mass concentration exiting AFBC boilers is typically 2 to 4 times higher than

pulverized coal boilers. AFBC particles are also, on average, smaller in size, and irregularly shaped with

higher surface area and porosity relative to pulverized coal ashes. The effect is a higher pressure drop. 

The AFBC ash is more difficult to collect in ESPs than pulverized coal ash because AFBC ash has a

higher electrical resistivity and the use of multiclones for recycling, inherent with the AFBC process,

tends to reduce exit gas stream particulate size.

1.1.4.2 Sulfur Oxides Control4

 -

Several techniques are used to reduce SOx emissions from coal combustion. Table 1.1-1 presents

the techniques most frequently used. One way is to switch to lower sulfur coals, since SOx emissions are

proportional to the sulfur content of the coal. This alternative may not be possible where lower sulfur

coal is not readily available or where a different grade of coal cannot be satisfactorily fired. In some

cases, various coal cleaning processes may be employed to reduce the fuel sulfur content. Physical coal

cleaning removes mineral sulfur such as pyrite but is not effective in removing organic sulfur. Chemical

cleaning and solvent refining processes are being developed to remove organic sulfur.

Post combustion flue gas desulfurization (FGD) techniques can remove SO2 formed during

combustion by using an alkaline reagent to absorb SO2 in the flue gas. Flue gases can be treated using

wet, dry, or semi-dry desulfurization processes of either the throwaway type (in which all waste streams

are discarded) or the recovery/regenerable type (in which the SO2 absorbent is regenerated and reused). 

To date, wet systems are the most commonly applied. Wet systems generally use alkali slurries as the

SO2 absorbent medium and can be designed to remove greater than 90 percent of the incoming SO2. 

Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the commercially
1.1-8 EMISSION FACTORS 9/98

proven wet FGD systems. The effectiveness of these devices depends not only on control device design

but also on operating variables. Particulate reduction of more than 99 percent is possible with wet

scrubbers, but fly ash is often collected by upstream ESPs or baghouses, to avoid erosion of the

desulfurization equipment and possible interference with FGD process reactions.18 Also, the volume of

scrubber sludge is reduced with separate fly ash removal, and contamination of the reagents and

by-products is prevented. 

The lime and limestone wet scrubbing process uses a slurry of calcium oxide or limestone to

absorb SO2 in a wet scrubber. Control efficiencies in excess of 91 percent for lime and 94 percent for

limestone over extended periods are possible. Sodium scrubbing processes generally employ a wet

scrubbing solution of sodium hydroxide or sodium carbonate to absorb SO2 from the flue gas. Sodium

scrubbers are generally limited to smaller sources because of high reagent costs and can have SO2

removal efficiencies of up to 96.2 percent. The double or dual alkali system uses a clear sodium alkali

solution for SO2 removal followed by a regeneration step using lime or limestone to recover the sodium

alkali and produce a calcium sulfite and sulfate sludge. SO2 removal efficiencies of 90 to 96 percent are

possible.

1.1.4.3 Nitrogen Oxide Controls4

 -

Several techniques are used to reduce NOx emissions from coal combustion. These techniques

are summarized in Table 1.1-2. The primary techniques can be classified into one of two fundamentally

different methods—combustion controls and postcombustion controls. Combustion controls reduce NOx

by suppressing NOx formation during the combustion process, while postcombustion controls reduce NOx

emission after their formation. Combustion controls are the most widely used method of controlling NOx

formation in all types of boilers and include low excess air (LEA), burners out of service (BOOS), biased

burner firing, overfire air (OFA), low NOx burners (LNBs), and reburn. Postcombustion control methods

are selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR). Combustion and

postcombustion controls can be used separately or combined to achieve greater NOx reduction from

fluidized bed combustors in boilers. 

Operating at LEA involves reducing the amount of combustion air to the lowest possible level

while maintaining efficient and environmentally compliant boiler operation. NOx formation is inhibited

because less oxygen is available in the combustion zone. BOOS involves withholding fuel flow to all or

part of the top row of burners so that only air is allowed to pass through. This method simulates air

staging, or OFA conditions, and limits NOx formation by lowering the oxygen level in the burner area. 

Biased burner firing involves more fuel-rich firing in the lower rows of burners than in the upper row of

burners. This method provides a form of air staging and limits NOx formation by limiting the amount of

oxygen in the firing zone. These methods may change the normal operation of the boiler and the

effectiveness is boiler-specific. Implementation of these techniques may also reduce operational

flexibility; however, they may reduce NOx by 10 to 20 percent from uncontrolled levels.

OFA is a technique in which a percentage of the total combustion air is diverted from the burners

and injected through ports above the top burner level. OFA limits NOx by 

(1) suppressing thermal NOx by partially delaying and extending the combustion process resulting in less

intense combustion and cooler flame temperatures and (2) suppressing fuel NOx formation by reducing

the concentration of air in the combustion zone where volatile fuel nitrogen is evolved. OFA can be

applied for various boiler types including tangential and wall-fired, turbo, and stoker boilers and can

reduce NOx by 20 to 30 percent from uncontrolled levels.

LNBs limit NOx formation by controlling the stoichiometric and temperature profiles of the

combustion process in each burner zone. The unique design of features of an LNB may create (1) a

reduced oxygen level in the combustion zone to limit fuel NOx formation, (2) a reduced flame
9/98 External Combustion Sources 1.1-9

temperature that limits thermal NOx formation, and/or (3) a reduced residence time at peak temperature

which also limits thermal NOx formation.

LNBs are applicable to tangential and wall-fired boilers of various sizes but are not applicable to

other boiler types such as cyclone furnaces or stokers. They have been used as a retrofit NOx control for

existing boilers and can achieve approximately 35 to 55 percent reduction from uncontrolled levels. 

They are also used in new boilers to meet New Source Performance Standards (NSPS) limits. LNBs can

be combined with OFA to achieve even greater NOx reduction (40 to 60 percent reduction from

uncontrolled levels).

Reburn is a combustion hardware modification in which the NOx produced in the main

combustion zone is reduced in a second combustion zone downstream. This technique involves

withholding up to 40 percent (at full load) of the heat input to the main combustion zone and introducing

that heat input above the top row of burners to create a reburn zone. Reburn fuel (natural gas, oil, or

pulverized coal) is injected with either air or flue gas to create a fuel-rich zone that reduces the NOx

created in the main combustion zone to nitrogen and water vapor. The fuel-rich combustion gases from

the reburn zone are completely combusted by injecting overfire air above the reburn zone. Reburn may

be applicable to many boiler types firing coal as the primary fuel, including tangential, wall-fired, and

cyclone boilers. However, the application and effectiveness are site-specific because each boiler is

originally designed to achieve specific steam conditions and capacity which may be altered due to reburn. 

Commercial experience is limited; however, this limited experience does indicate NOx reduction of 50 to

60 percent from uncontrolled levels may be achieved. 

SNCR is a postcombustion technique that involves injecting ammonia (NH3) or urea into specific

temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with NOx in the

flue gas to produce nitrogen and water. The effectiveness of SNCR depends on the temperature where

reagents are injected; mixing of the reagent in the flue gas; residence time of the reagent within the

required temperature window; ratio of reagent to NOx; and the sulfur content of the fuel that may create

sulfur compounds that deposit in downstream equipment. There is not as much commercial experience

to base effectiveness on a wide range of boiler types; however, in limited applications, NOx reductions of

25 to 40 percent have been achieved.

SCR is another postcombustion technique that involves injecting NH3 into the flue gas in the

presence of a catalyst to reduce NOx to nitrogen and then water. The SCR reactor can be located at

various positions in the process including before an air heater and particulate control device, or

downstream of the air heater, particulate control device, and flue gas desulfurization systems. The 

performance of SCR is influenced by flue gas temperature, fuel sulfur content, ammonia-to-NOx ratio,

inlet NOx concentration, space velocity, and catalyst condition. Although there is currently very limited

application of SCR in the U.S. on coal-fired boilers, NOx reductions of 75 to 86 percent have been

realized on a few pilot systems.

1.1.5 Emission Factors

Emission factors for SOx, NOx, and CO are presented in Table 1.1-3. Tables in this section

present emission factors on both a weight basis (lb/ton) and an energy basis (lb/Btu). To convert from

lb/ton to lb/MMBtu, divide by a heating value of 26.0 MMBtu/ton. Because of the inherently low NOX

emission characteristics of FBCs and the potential for in-bed SO2 capture by calcium-based sorbents,

uncontrolled emission factors for this source category were not developed in the same sense as with other

source categories. For NOx emissions, the data collected from test reports were considered to be baseline

(uncontrolled) if no additional add-on NOx control system (such as ammonia injection) was operated. 
1.1-10 EMISSION FACTORS 9/98

For SO2 emissions, a correlation was developed from reported data on FBCs to relate SO2 emissions to

the coal sulfur content and the calcium-to-sulfur ratio in the bed.

Filterable particulate matter and particulate matter less than, or equal to, 10 micrometers in

diameter (PM-10) emission factors are presented in Table 1.1-4. Condensable particulate matter

emission factors are presented in Table 1.1.5. Cumulative particle size distributions and particulate sizespecific emission factors are given in Tables 1.1-6, 1.1-7, 1.1-8, 1.1-9, 1.1-10, and 1.1-11. Particulate

size-specific emission factors are also presented graphically in Figures 1.1-1, 1.1-2, 1.1-3, 1.1-4, 1.1-5,

and 1.1-6.

Controlled emission factors for PCDD/PCDF and PAHs are provided in Tables 1.1-12 and

1.1-13, respectively. Controlled emission factors for other organic compounds are presented in Table

1.1-14. Emission factors for hydrogen chloride and hydrogen fluoride are presented in Table 1.1-15.

Table 1.1-16 presents emission factor equations for nine trace metals from controlled and

uncontrolled boilers. Table 1.1-17 presents uncontrolled emission factors for seven of the same metals,

along with mercury, POM and formaldehyde. Table 1.1-18 presents controlled emission factors for 13

trace metals and includes the metals found in Tables 1.1-16 and 1.1-17. The emission factor equations in

Table 1.1-16 are based on statistical correlations among measured trace element concentrations in coal,

measured fractions of ash in coal, and measured particulate matter emission factors. Because these are

the major parameters affecting trace metals emissions from coal combustion, it is recommended that the

emission factor equations be used when the inputs to the equations are available. If the inputs to the

emission factor equations are not available for a pollutant, then the emission factors provided in Table

1.1-17 and 1.1-18 for the pollutant should be used.

Greenhouse gas emission factors, including CH4, non-methane organic compounds (NMOC), and

N2O are provided in Table 1.1-19. In addition, Table 1.1-20 provides emission factors for CO2.

1.1.6 Updates Since the Fifth Edition

The Fifth Edition was released in January 1995. Revisions to this section since that date are

summarized below. For further detail, consult the memoranda describing each supplement or the

background report for this section. These and other documents can be found on the EFIG home page

(http://www.epa.gov/oar/oaqps/efig/).
9/98 External Combustion Sources 1.1-11

Supplement A, February 1996

C SCC’s were corrected from 1-01-002-17, 1-02-002-17, and 1-03-002-17, to 1-01-002-18,

1-02-002-18, and 1-03-002-18 in the tables with SOx, NOx, CO, and PM/PM10 emission

factors. 

C For SOx factors, clarifications were added to the table footnotes to clarify that “S” is a

weight percent and not a fraction. Similar clarification was added to the footnote for the

CO2 factor.

C For fluidized bed combustors (bubbling bed and circulating bed), the PM10 factors were

replaced with footnote "m." The revised footnote "m" directs the user to the emission

factor for spreader stoker with multiple cyclones and no flyash reinjection.

C In the table with filterable PM factors, the misspelling of "filterable" was corrected.

C In the cumulative particle size distribution table, text was added to the table footnotes to

clarify that “A” is a weight percent and not a fraction.

C In the cumulative particle size distribution for spreader stokers, all of the factors were

corrected.

C The N2O emission factor for bubbling bed was changed from 5.9 lb/ton to 5.5 lb/ton.

Supplement B, October 1996

C Text was added concerning coal rank/classification, firing practices, emissions, and

controls.

C The table for NOx control technologies was revised to include controls for all types of

coal-fired boilers.

C SOx, NOx, and CO emission factors were added for cell burners.

C The PM table was revised to recommend using spreader stoker PM factors for FBC units.

C Tables were added for new emission factors for polychlorinated toxics, polynuclear

aromatics, organic toxics, acid gas toxics, trace metal toxics, and controlled toxics.

C N2O emission factors were added.

C Default CO2 emission factors were added.

Supplement E, September 1998

C The term “Filterable” was added to the PM-10 column heading of Table 1.1-4.
1.1-12 EMISSION FACTORS 9/98

C Reference to condensable particulate matter was deleted from footnote b of 

Table 1.1-4.

C Emission factors for condensable particulate matter were added (Table 1.1-5).

C Table 1.1-7 was revised to correct a typographical errors in the ESP column.

C The zeros in Table 1.1-8 appeared to be in error. Engineering judgement was used to

determine a conservative estimate.

C NOx emission factors were updated based on data from the Acid Rain program.
9/98 External Combustion Sources 1.1-13

Table 1.1-1. POSTCOMBUSTION SO2 CONTROLS FOR COAL COMBUSTION SOURCES

Control Technology Process

Typical Control

Efficiencies Remarks

Wet scrubber

Spray drying

Furnace injection

Duct injection

Lime/limestone

Sodium carbonate

Magnesium oxide/

 hydroxide

Dual alkali

Calcium hydroxide

 slurry, vaporizes in

 spray vessel

Dry calcium

 carbonate/hydrate

 injection in upper

 furnace cavity

Dry sorbent injection

 into duct, sometimes

 combined with water

 spray

80 - 95+%

80 - 98%

80 - 95+%

90 - 96%

70 - 90%

25 - 50%

25 - 50+%

Applicable to high sulfur

fuels, wet sludge product

5-430 million Btu/hr

typical application range, 

high reagent costs

Can be regenerated

Uses lime to regenerate

sodium-based scrubbing

liquor

Applicable to low and

medium sulfur fuels, 

produces dry product

Commercialized in Europe,

several U. S. demonstration

projects are completed

Several research and

development, and

demonstration projects

underway, not yet

commercially available in 

the United States.
1.1-14 EMISSION FACTORS 9/98 Table 1.1-2. NOx CONTROL OPTIONS FOR COAL-FIRED BOILERSa Control Technique Description of Technique Applicable Boiler Designs NOx Reduction Potentialb (%) Commercial Availability/R & D Status Commen

Combustion Modifications Load reduction Reduction of coal and air Stokers Minimal Available Applicable to stokers that can r

increasing excess air; may causefficiency; NOx reduction varie

reduction. Operational modifications (BOOS, LEA, BF, or combination) Rearrangement of air or fuel in the main combustion zone Pulverized coal boilers (some designs); Stokers (LEA only) 10 - 20 Available Must have sufficient operationa

NOx reduction potential withou

performance. Overfire Air Injection of air above main combustion zone Pulverized coal boilers and stokers 20 - 30 Available Must have sufficient furnace he

burners in order to retrofit this boilers. Low NOx Burners New burner designs controlling air- fuel mixing Pulverized coal boilers 35 - 55 Available Available in new boiler design

existing boilers. LNB with OFA Combination of new burner designs and injection of air above main combustion zone Pulverized coal boilers 40 - 60 Available Available in new boiler design

existing boilers with sufficient top row of burners. Reburn Injection of reburn fuel and completion air above main combustion zone Pulverized coal boilers, cyclone furnaces 50 - 60 Commercially available but not widely demonstrated Reburn fuel can be natural gas, 

coal. Must have sufficient furnthis technology to existing boil
9/98 External Combustion Sources 1.1-15 Table 1.1-2 (cont.). Control Technique Description of Technique Applicable Boiler Designs NOx Reduction Potentialb (%) Commercial Availability/R & D Status Commen

Post-Combustion Modifications SNCR Injection of NH3 or urea in the convective pass Pulverized coal boilers, cyclone furnaces, stokers, and fluidized bed boilers 30 - 60 Commercially available but not widely demonstrated Applicable to new boilers or as 

must have sufficient residence titemperature (1,750E±90EF); elasystem; possible load restrictionair preheater fouling by ammoni

SCR Injection of NH3 in combination with catalyst material Pulverized coal boilers, cyclone furnaces 75 - 85 Commercially offered, but not yet demonstrated Applicable to new boilers or as a 

provided there is sufficient spaclow-sulfur fuel and low fly ash aSCR can be used on high-sulfurequipped with an upstream FGD 

LNB with SNCR Combination of new burner designs and injection of NH3 or urea Pulverized coal boilers 50-80 Commercially offered, but not widely demonstrated as a combined technology Same as LNB and SNCR alone. LNB with OFA and SCR Combination of new burner design, injection of air above combustion zone, and injection of NH3 or urea Pulverized coal boiler 85-95 Commercially offered, but not widely demonstrated as a combined technology Same as LNB, OFA, and SCR a

a References 20-21. b NOx reduction potential from uncontrolled levels.
1.1-16 EMISSION FACTORS 9/98 Table 1.1-3. EMISSION FACTORS FOR SOx, NOx, AND CO FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTIONa Firing Configuration SCC SOxb NOxc 

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton) EMISSION FACTOR RATING Emissi

Facto

(lb/ton

PC, dry bottom, wall-firedf, bituminous Pre-NSPSg 1-01-002-02 1-02-002-02 1-03-002-06 38S A 22 A 0.5 

PC, dry bottom, wall-firedf, bituminous Pre-NSPSg with low-NOx burner 1-01-002-02 1-02-002-02 1-03-002-06 38S A 11 A 0.5 

PC, dry bottom, wall-firedf, bituminous NSPSg 1-01-002-02 1-02-002-02 1-03-002-06 38S A 12 A 0.5 

PC, dry bottom, wall-firedf, sub-bituminous Pre-NSPSg 1-01-002-22 1-02-002-22 1-03-002-22 35S A 12 C 0.5 PC, dry bottom, wall firedf, sub-bituminous NSPSg 1-01-002-22 1-02-002-22 1-03-002-22 35S A 7.4 A 0.5 

PC, dry bottom, cell burnerh fired, bituminous 1-01-002-15 38S A 31 A 0.5 

PC, dry bottom, cell burner fired, sub-bituminous 1-01-002-35 35S A 14 E 0.5 
9/98 External Combustion Sources 1.1-17 Table 1.1-3 (cont.). Firing Configuration SCC SOxb NOxc 

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton) EMISSION FACTOR RATING Emiss

Fact

(lb/to

PC, dry bottom, tangentially fired, bituminous, Pre-NSPSg 1-01-002-12 1-02-002-12 1-03-002-16 38S A 15 A 0.5 

PC, dry bottom, tangentially fired, bituminous, Pre-NSPSg with low-NOx burner 1-01-002-12 1-02-002-12 1-03-002-16 38S A 9.7 A 0.5 

PC, dry bottom, tangentially fired, bituminous, NSPSg 1-01-002-12 1-02-002-12 1-03-002-16 38S 10 A 0.5 

PC, dry bottom, tangentially fired, sub-bituminous, Pre- NSPSg 1-01-002-26 1-02-002-26 1-03-002-26 35S A 8.4 A 0.5 

PC, dry bottom, tangentially fired, sub-bituminous, NSPSg 1-01-002-26 1-02-002-26 1-03-002-26 35S A 7.2 A 0.5 PC, wet bottom, wall-firedf, bituminous, Pre-NSPSg 1-01-002-01 1-02-002-01 1-03-002-05 38S A 31 D 0.5 PC, wet bottom, tangentially fired, bituminous, NSPSg 1-01-002-11 38S A 14 E 0.5 

PC, wet bottom, wall-fired sub-bituminous 1-01-002-21 1-02B002-21 1-03-002-21 35S A 24 E 0.5 
1.1-18 EMISSION FACTORS 9/98 Table 1.1-3 (cont.). Firing Configuration SCC SOxb NOxc 

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton) EMISSION FACTOR RATING Emiss

Fact

(lb/to

Cyclone Furnace, bituminous 1-01-002-03 1-02-002-03 1-03-002-03 38S A 33 A 0.5 

Cyclone Furnance, sub- bituminous 1-01-002-23 1-02-002-23 1-03-002-23 35S A 17 C 0.5 

Spreader stoker, bituminous 1-01-002-04 1-02-002-04 1-03-002-09 38S B 11 B 5 Spreader Stoker, sub-bituminous 1-01-002-24 1-02-002-24 1-03-002-24 35S B 8.8 B 5 Overfeed stokeri 1-01-002-05/25 1-02-002-05/25 1-03-002-07/25 38S (35S) B 7.5 A 6 

Underfeed stoker 1-02-002-06 1-03-002-08 31S B 9.5 A 11 Hand-fed units 1-03-002-14 31S D 9.1 E 275 
9/98 External Combustion Sources 1.1-19 Table 1.1-3 (cont.). Firing Configuration SCC SOxb NOxc 

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton EMISSION FACTOR RATING Emission Factor (lb/ton) 

FBC, circulating bed 1-01-002-18 1-02-002-18 1-03-002-18 Cj E 5.0 D 18 

FBC, bubbling bed 1-01-002-17 1-02-002-17 1-03-002-17 Cj E 15.2 D 18 

a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. SCC = 

Code. To convert from lb/ton to kg/Mg, multiply by 0.5. b Expressed as SO2, including SO2, SO3, and gaseous sulfates. Factors in parentheses should be used to estimate gaseous S

subbituminous coal. In all cases, S is weight % sulfur content of coal as fired. Emission factor would be calculated by mweight percent sulfur in the coal by the numerical value preceding S. For example, if fuel is 1.2% sulfur, then S = 1.2. Obituminous coal, 95% of fuel sulfur is emitted as SO2, and only about 0.7% of fuel sulfur is emitted as SO3 and gaseous s

small percent of fuel sulfur is emitted as particulate sulfate (References 22-23). Small quantities of sulfur are also retainWith subbituminous coal, about 10% more fuel sulfur is retained in the bottom ash and particulate because of the more acoal ash. Conversion to gaseous sulfate appears about the same as for bituminous coal.
1.1-20 EMISSION FACTORS 9/98

Table 1.1-3. (cont.)

c Expressed as NO2. Generally, 95 volume % or more of NOx present in combustion exhaust will be in the form of NO, the r

To express factors as NO, multiply factors by 0.66. All factors represent emissions at baseline operation (i. e., 60 to 110% l

measures).

d Nominal values achievable under normal operating conditions. Values 1 or 2 orders of magnitude higher can occur w

complete.

e Emission factors for CO2 emissions from coal combustion should be calculated using lb CO2/ton coal = 72.6C, where C 

content of the coal. For example, if carbon content is 85%, then C equals 85.

f Wall-fired includes front and rear wall-fired units, as well as opposed wall-fired units.g Pre-NSPS boilers are not subject to any NSPS. NSPS boilers are subject to Subpart D or Subpart Da. Subpart D boilers 

after August 17, 1971 and with a heat input rate greater than 250 million Btu per hour (MMBtu/hr). Subpart Da boilers are bSeptember 18, 1978 and with a heat input rate greater than 250 MMBtu/hr.

h References 24-27.i Includes traveling grate, vibrating grate, and chain grate stokers.j SO2 emission factors for fluidized bed combustion are a function of fuel sulfur content and calcium-to-sulfur ratio. For 

circulating bed design, use: lb SO2/ton coal = 39.6(S)(Ca/S)-1.9. In this equation, S is the weight percent sulfur in the fue

calcium-to-sulfur ratio in the bed. This equation may be used when the Ca/S is between 1.5 and 7. When no calcium-basethe bed material is inert with respect to sulfur capture, the emission factor for underfeed stokers should be used to estimate 

this case, the emission factor ratings are E for both bubbling and circulating units.
9/98 External Combustion Sources 1.1-21 Table 1.1-4. UNCONTROLLED EMISSION FACTORS FOR PM AND PM-10 FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTIONa Firing Configuration SCC Filterable PMb Filtera

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Facto

(lb/ton) 

PC-fired, dry bottom, wall-fired 1-01-002-02/22 1-02-002-02/22 1-03-002-06/22 10A A 2.3A 

PC-fired, dry bottom, tangentially fired 1-01-002-12/26 1-02-002-12/26 1-03-002-16/26 10A B 2.3Ac 

PC-fired, wet bottom 1-01-002-01/21 1-02-002-01/21 1-03-002-05/21 7Ad D 2.6A 

Cyclone furnace 1-01-002-03/23 1-02-002-03/23 1-03-002-03/23 2Ad E 0.26A 

Spreader stoker 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 66e B 13.2 

Spreader stoker, with multiple cyclones, and reinjection 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 17 B 12.4 Spreader stoker, with multiple cyclones, no reinjection 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 12 A 7.8 
1.1-22 EMISSION FACTORS 9/98 Table 1.1-4 (cont.). Firing Configuration SCC Filterable PMb Filterab

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton) 

Overfeed stokerf 1-01-002-05/25 1-02-002-05/25 1-03-002-07/25 16g C 6.0 

Overfeed stoker, with multiple cyclonesf 1-01-002-05/25 1-02-002-05/25 1-03-002-07/25 9h C 5.0 Underfeed stoker 1-02-002-06 1-03-002-08 15j D 6.2 

Underfeed stoker, with multiple cyclone 1-02-002-06 1-03-002-08 11h D 6.2j 

Hand-fed units 1-03-002-14 15 E 6.2k FBC, bubbling bed 1-01-002-17 1-02-002-17 1-03-002-17 m E m FBC, circulating bed 1-01-002-18 1-02-002-18 1-03-002-18 m E m 

a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. To conve

kg/Mg, multiply by 0.5. SCC = Source Classification Code.
9/98 External Combustion Sources 1.1-23 Table 1.1-4 (cont.). b Based on EPA Method 5 (front half catch) as described in Reference 28. Where particulate is expressed in terms of coal a

is determined by multiplying weight % ash content of coal (as fired) by the numerical value preceding the A. For examplash is fired in a PC-fired, dry bottom unit, the PM emission factor would be 10 x 8, or 80 lb/ton. c No data found; emission factor for PC-fired dry bottom boilers used. d Uncontrolled particulate emissions, when no fly ash reinjection is employed. When control device is installed, and collecreinjected to boiler, particulate from boiler reaching control equipment can increase up to a factor of 2. e Accounts for fly ash settling in an economizer, air heater, or breaching upstream of control device or stack. (Particulate doutlet typically will be twice this level.) Factor should be applied even when fly ash is reinjected to boiler from air heater hoppers. f Includes traveling grate, vibrating grate, and chain grate stokers. g Accounts for fly ash settling in breaching or stack base. Particulate loadings directly at boiler outlet typically can be 50% 

h See Reference 4 for discussion of apparently low multiple cyclone control efficiencies, regarding uncontrolled emissions. j Accounts for fly ash settling in breaching downstream of boiler outlet. k No data found; emission factor for underfeed stoker used. m No data found; use emission factor for spreader stoker with multiple cyclones and reinjection.
1.1-24 EMISSION FACTORS 9/98 Table 1.1-5. CONDENSABLE PARTICULATE MATTER EMISSION FACTORS FOR BITUMINOUS AND SUBBIT

COMBUSTIONa Firing Configurationb Controlsc SCC CPM - TOTd, e CPM - IORd, e 

Emission Factor (lb/MMBtu) EMISSION FACTOR RATING Emission Factor (lb/MMBtu) EMISSION FACTOR RATING E

(lb

All pulverized coal-fired boilers All PM controls (without FGD controls) 1-01-002-01/21 1-01-002-02/22 1-01-002-12/26 1-02-002-01/21 1-02-002-02/22 1-02-002-12/26 1-03-002-05/06 1-03-002-16 1-03-002-21/22 1-03-002-26 0.1S-0.03f,g B 80% of CPM- TOT emission factore E 20% 

TOT facto

All pulverized coal-fired boilers All PM controls combined with an FGD control 1-01-002-01/21 1-01-002-02/22 1-01-002-12/26 1-02-002-01/21 1-02-002-02/22 1-02-002-12/26 1-03-002-05/06 1-03-002-16 1-03-002-21/22 1-03-002-26 0.02h E ND ND Spreader stoker, travelling grate overfeed stoker, underfeed stoker All PM controls, or Uncontrolled 1-01-002-04/24 1-01-002-05/25 1-02-002-04/24 1-02-002-05/25 1-02-002-06 1-03-002-07/08 1-03-002-09/11 1-03-002-16 1-03-002-24/25 0.04i C 80% of CPM- TOT emission factorg E 20% 

TOT facto
9/98 External Combustion Sources 1.1-25 Table 1.1-5 (cont.). a All condensable PM is assumed to be less than 1.0 micron in diameter. b No data are available for cyclone boilers (SCCs 1-01-002-03/23, 1-02-002-03/23, 1-03-002-23) or for atmospheric fluidized bed comb

(SCCs 1-01B002-17, 1-02-002-17, 1-03-002-17). For cyclone boilers, use the factors provided for pulverized coal-fired boilers and ap

devices. For AFBC boilers, use the factors provided for pulverized coal-fired boilers with PM and FGD controls. c FGD = flue gas desulfurization. d CPM-TOT = total condensable particulate matter. CPM-IOR = inorganic condensable particulate matter. CPM-ORG = organic condensable particulate matter. ND = No data. e Factors should be multiplied by fuel rate on a heat input basis (MMBtu), as fired. To convert to lb/ton of bituminous coal, multiply by 

convert to lb/ton of subbituminous coal, multiply by 20 MMBtu/ton. f S = coal sulfur percent by weight, as fired. For example, if the sulfur percent is 1.04, then S = 1.04. If the coal sulfur percent is 0.4 or emission factor of 0.01 lb/MMBtu rather than the emission equation. g References 78-94. h References 95 and 96. i References 97-104.
1.1-26 EMISSION FACTORS 9/98 Table 1.1-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS AND SUBBITUMINOU

Particle Sizeb (Fm) Cumulative Mass % # Stated Size Cumulative Emission Factorc (lb/ton

Uncontrolled Controlled Uncontrolledd Controllede Multiple Cyclones Scrubber ESP Baghouse Multiple Cyclonesf Scrubberg ESP

15 32 54 81 79 97 3.2A 1.08A 0.48A 0.010 23 29 71 67 92 2.3A 0.58A 0.42A 0.0

6 17 14 62 50 77 1.7A 0.28A 0.38A 0.0

2.5 6 3 51 29 53 0.6A 0.06A 0.3A 0.0

1.25 2 1 35 17 31 0.2A 0.02A 0.22A 0.0

1.00 2 1 31 14 25 0.2A 0.02A 0.18A 0.0

0.625 1 1 20 12 14 0.10A 0.02A 0.12A 0.0

TOTAL 100 100 100 100 100 10A 2A 0.6A 0.0

a Reference 33. Applicable Source Classification Codes are 1-01-002-02, 1-02-002-02, 1-03-002-06, 1-01-002-12, 1-02-00

16. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission Factors are lb of pollutant per ton of coal combusted, as Electrostatic precipitator. b Expressed as aerodynamic equivalent diameter. c A = coal ash weight percent, as fired. For example, if coal ash weight is 8.2%, then A = 8.2. d EMISSION FACTOR RATING = C. e Estimated control efficiency for multiple cyclones is 80%; for scrubber, 94%; for ESP, 99.2%; and for baghouse, 99.8%. f EMISSION FACTOR RATING = E. g EMISSION FACTOR RATING = D.
9/98 External Combustion Sources 1.1-27

Table 1.1-7. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND

SIZE-SPECIFIC EMISSION FACTORS FOR WET BOTTOM BOILERS BURNING PULVERIZED

BITUMINOUS COALa

EMISSION FACTOR RATING: E

Particle Sizeb

(Fm)

Cumulative Mass % # Stated Size

Cumulative Emission Factorc

(lb/ton)

Controlled Controlledd

Uncontrolled

Multiple

Cyclones ESP Uncontrolled

Multiple 

Cyclones ESP

15 40 99 83 2.8A 1.38A 0.046A

10 37 93 75 2.6A 1.3A 0.042A

6 33 84 63 2.32A 1.18A 0.036A

2.5 21 61 40 1.48A 0.86A 0.022A

1.25 6 31 17 0.42A 0.44A 0.01A

1.00 4 19 8 0.28A 0.26A 0.004A

0.625 2 —e —e 0.14A —e —e

TOTAL 100 100 100 7.0A 1.4A 0.056A a Reference 33. Applicable Source Classification Codes are 1-01-002-01, 1-02-002-01, and 1-03-002-05. 

To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of pollutant per ton of coal

combusted as fired. ESP = Electrostatic precipitator.

b Expressed as aerodynamic equivalent diameter. c A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.

d Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%. e Insufficient data.
1.1-28 EMISSION FACTORS 9/98

Table 1.1-8. CUMULATIVE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR

CYCLONE FURNACES BURNING BITUMINOUS COALa

EMISSION FACTOR RATING: E

Particle

Sizeb

(Fm)

Cumulative Mass % # Stated Size

Cumulative Emission Factorc

(lb/ton)

Controlled Controlledd

Uncontrolled

Multiple

Cyclones ESP Uncontrolled

Multiple 

Cyclones ESP

15 33 95 90 0.66A 0.114A 0.013A

10 13 94 68 0.26A 0.112A 0.011A

6 8 93 56 0.16A 0.112A 0.009A

2.5 5.5 92 36 0.11Ae 0.11A 0.006A

1.25 5 85 22 0.10Ae 0.10A 0.004A

1.00 5 82 17 0.10Ae 0.10A 0.003A

0.625 0 —f —f 0 —f —f

TOTAL 100 100 100 2A 0.12A 0.016A

a Reference 33. Applicable Source Classification Codes are 1-01-002-03, 1-02-002-03, and 1-03-002-03. 

To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal

combusted, as fired.

b Expressed as aerodynamic equivalent diameter. c A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.

d Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%. e These values are estimates based on data from controlled source.

f Insufficient data.
9/98 External Combustion Sources 1.1-29 Table 1.1-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR SPREADER STOKERS BURNING BITUMINOUS COALa Particle Sizeb (Fm) Cumulative Mass % # Stated Size Cumulative Emission Factor (lb/ton) Uncontrolled Controlled Uncontrollede Controlled Multiple Cyclonesc Multiple Cyclonesd ESP Baghouse Multiple Cyclonesc,f Multiple Cyclonesd,e ESPf,

15 28 86 74 97 72 18.5 14.6 8.8 0.46 

10 20 73 65 90 60 13.2 12 7.8 0.44 

6 14 51 52 82 46 9.2 8.6 6.2 0.40 

2.5 7 8 27 61 26 4.6 1.4 3.2 0.30 

1.25 5 2 16 46 18 3.3 0.4 2.0 0.22 

1.00 5 2 14 41 15 3.3 0.4 1.6 0.20 

0.625 4 1 9 Ch 7 2.6 0.2 1.0 Ch 

 TOTAL 100 100 100 100 100 66.0 17.0 12.0 0.48 

a Reference 33. Applicable Source Classification Codes are 1-01-002-04, 1-02-002-04, 1-03-002-09. To convert from lb/t

multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted, as fired. b Expressed as aerodynamic equivalent diameter. c With flyash reinjection. d Without flyash reinjection. e EMISSION FACTOR RATING = C. f EMISSION FACTOR RATING = E. g Estimated control efficiency for ESP is 99.22%; and for baghouse, 99.8%. h Insufficient data.
1.1-30 EMISSION FACTORS 9/98

Table 1.1-10. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION

FACTORS FOR OVERFEED STOKERS BURNING 

BITUMINOUS COALa

Particle

Sizeb

(Fm)

 Cumulative Mass % 

# Stated Size

Cumulative Emission Factor 

(lb/ton)

Uncontrolled

Multiple

Cyclones

Controlled

Uncontrolled

Multiple Cyclones

Controlledc

Emission

Factor

EMISSION

FACTOR

RATING

Emission

Factor

EMISSION

FACTOR

RATING

15 49 60 7.8 C 5.4 E

10 37 55 6.0 C 5.0 E

6 24 49 3.8 C 4.4 E

2.5 14 43 2.2 C 3.8 E

1.25 13 39 2.0 C 3.6 E

1.00 12 39 2.0 C 3.6 E

0.625 —d 16 —d C 1.4 E

TOTAL 100 100 16.0 C 9.0 E a Reference 33. Applicable Source Classification Codes are 1-01-002-05, 1-02-002-05, and 1-03-002-07. 

To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal

combusted, as fired.

b Expressed as aerodynamic equivalent diameter. c Estimated control efficiency for multiple cyclones is 80%. 

d Insufficient data.
9/98 External Combustion Sources 1.1-31

Table 1.1-11. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND

SIZE-SPECIFIC EMISSION FACTORS FOR UNDERFEED STOKERS BURNING 

BITUMINOUS COALa

EMISSION FACTOR RATING: C

Particle Sizeb (μm)

Cumulative Mass %

# Stated Size

Uncontrolled Cumulative Emission Factorc

(lb/ton)

15 50 7.6

10 41 6.2

6 32 4.8

2.5 25 3.8

1.25 22 3.4

1.00 21 3.2

0.625 18 2.7

TOTAL 100 15.0 a Reference 33. Applicable Source Classification Codes are 1-02-002-06 and 1-03-002-08. To convert

from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of pollutant per ton of coal combusted,

as fired.

b Expressed as aerodynamic equivalent diameter. c May also be used for uncontrolled hand-fired units.
1.1-32 EMISSION FACTORS 9/98

Table 1.1-12 EMISSION FACTORS FOR POLYCHLORINATED

DIBENZO-P-DIOXINS AND POLYCHLORINATED DIBENZOFURANS FROM CONTROLLED

BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION

Controls FGD-SDA with FFa ESP or FFb

Congener

Emission Factorc

(lb/ton)

EMISSION

FACTOR

RATING

Emission Factorc

(lb/ton)

EMISSION

FACTOR

RATING

2,3,7,8-TCDD No data --- 1.43E-11 E

Total TCDD 3.93E-10 E 9.28E-11 D

Total PeCDD 7.06E-10 E 4.47E-11 D

Total HxCDD 3.00E-09 E 2.87E-11 D

Total HpCDD 1.00E-08 E 8.34E-11 D

Total OCDD 2.87E-08 E 4.16E-10 D

Total PCDDd 4.28E-08 E 6.66E-10 D

2,3,7,8-TCDF No data --- 5.10E-11 D

Total TCDF 2.49E-09 E 4.04E-10 D

Total PeCDF 4.84E-09 E 3.53E-10 D

Total HxCDF 1.27E-08 E 1.92E-10 D

Total HpCDF 4.39E-08 E 7.68E-11 D

Total OCDF 1.37E-07 E 6.63E-11 D

Total PCDFd 2.01E-07 E 1.09E-09 D

TOTAL PCDD/PCDF 2.44E-07 E 1.76E-09 D a Reference 34. Factors apply to boilers equipped with both flue gas desulfurization spray dryer

absorber (FGD-SDA) and a fabric filter (FF). SCCs = pulverized coal-fired, dry bottom boilers,

1-01-002-02/22, 1-02-002-02/22, and 1-03-002-06/22.

b References 35-37. Factors apply to boilers equipped with an electrostatic precipitator (ESP) or a fabric

filter. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22,

1-03-002-06/22; and, cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and 1-03-002-03/23. c Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by

0.5. Emissions are lb of pollutant per ton of coal combusted.

d Total PCDD is the sum of Total TCDD through Total OCDD. Total PCDF is the sum of Total TCDF

through Total OCDF.
9/98 External Combustion Sources 1.1-33

Table 1.1-13 EMISSION FACTORS FOR POLYNUCLEAR AROMATIC

HYDROCARBONS (PAH) FROM CONTROLLED COAL COMBUSTIONa

Pollutant

Emission Factorb

(lb/ton)

EMISSION FACTOR

RATING

Biphenyl 1.7E-06 D

Acenaphthene 5.1E-07 B

Acenaphthylene 2.5E-07 B

Anthracene 2.1E-07 B

Benzo(a)anthracene 8.0E-08 B

Benzo(a)pyrene 3.8E-08 D

Benzo(b,j,k)fluoranthene 1.1E-07 B

Benzo(g,h,i)perylene 2.7E-08 D

Chrysene 1.0E-07 C

Fluoranthene 7.1E-07 B

Fluorene 9.1E-07 B

Indeno(1,2,3-cd)pyrene 6.1E-08 C

Naphthalene 1.3E-05 C

Phenanthrene 2.7E-06 B

Pyrene 3.3E-07 B

5-Methyl chrysene 2.2E-08 D a References 35-45. Factors were developed from emissions data from six sites firing bituminous coal,

four sites firing subbituminous coal, and from one site firing lignite. Factors apply to boilers utilizing

both wet limestone scrubbers or spray dryers with an electrostatic precipitator (ESP) or fabric filter

(FF). The factors also apply to boilers utilizing only an ESP or FF. Bituminous/subbituminous SCCs =

pulverized coal-fired dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06; pulverized

coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; and,

cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and 1-03-002-03/23.

b Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by

0.5. Emissions are lb of pollutant per ton of coal combusted.
1.1-34 EMISSION FACTORS 9/98

Table 1.1-14 EMISSION FACTORS FOR VARIOUS ORGANIC COMPOUNDS

FROM CONTROLLED COAL COMBUSTIONa

Pollutantb Emission Factorc

(lb/ton)

EMISSION FACTOR

RATING

Acetaldehyde 5.7E-04 C

Acetophenone 1.5E-05 D

Acrolein 2.9E-04 D

Benzene 1.3E-03 A

Benzyl chloride 7.0E-04 D

Bis(2-ethylhexyl)phthalate (DEHP) 7.3E-05 D

Bromoform 3.9E-05 E

Carbon disulfide 1.3E-04 D

2-Chloroacetophenone 7.0E-06 E

Chlorobenzene 2.2E-05 D

Chloroform 5.9E-05 D

Cumene 5.3E-06 E

Cyanide 2.5E-03 D

2,4-Dinitrotoluene 2.8E-07 D

Dimethyl sulfate 4.8E-05 E

Ethyl benzene 9.4E-05 D

Ethyl chloride 4.2E-05 D

Ethylene dichloride 4.0E-05 E

Ethylene dibromide 1.2E-06 E

Formaldehyde 2.4E-04 A

Hexane 6.7E-05 D

Isophorone 5.8E-04 D

Methyl bromide 1.6E-04 D

Methyl chloride 5.3E-04 D

Methyl ethyl ketone 3.9E-04 D

Methyl hydrazine 1.7E-04 E

Methyl methacrylate 2.0E-05 E
9/98 External Combustion Sources 1.1-35

Table 1.1-14 (cont.).

Pollutantb Emission Factorc

(lb/ton)

EMISSION FACTOR

RATING

Methyl tert butyl ether 3.5E-05 E

Methylene chloride 2.9E-04 D

Phenol 1.6E-05 D

Propionaldehyde 3.8E-04 D

Tetrachloroethylene 4.3E-05 D

Toluene 2.4E-04 A

1,1,1-Trichloroethane 2.0E-05 E

Styrene 2.5E-05 D

Xylenes 3.7E-05 C

Vinyl acetate 7.6E-06 E a References 35-53. Factors were developed from emissions data from ten sites firing bituminous coal,

eight sites firing subbituminous coal, and from one site firing lignite. The emission factors are

applicable to boilers using both wet limestone scrubbers or spray dryers and an electrostatic

precipitator (ESP) or fabric filter (FF). In addition, the factors apply to boilers utilizing only an ESP or

FF. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22,

1-03-002-06/22; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26,

1-02-002-12/26, 1-03-002-16/26; cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23;

and, atmospheric fluidized bed combustors, circulating bed, 1-01-002-18/38, 1-02-002-18, and

1-03-002-18.

b Pollutants sampled for but not detected in any sampling run include: Carbon tetrachloride- 2 sites;

1,3-Dichloropropylene- 2 sites; N-nitrosodimethylamine- 2 sites; Ethylidene dichloride- 2 sites;

Hexachlorobutadiene- 1 site; Hexachloroethane- 1 site; Propylene dichloride- 2 sites;

1,1,2,2-Tetrachloroethane- 2 sites; 1,1,2-Trichloroethane- 2 sites; Vinyl chloride- 2 sites; and,

Hexachlorobenzene- 2 sites. c Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by

0.5.
1.1-36 EMISSION FACTORS 9/98 Table 1.1-15. EMISSION FACTORS FOR HYDROGEN CHLORIDE (HCI) AND HYDROGEN FLUORIDE (H

COAL COMBUSTIONa EMISSION FACTOR RATING: B Firing Configuration SCC HCl 

Emission Factor (lb/ton) Emissio

PC-fired, dry bottom 1-01-002-02/22 1-02-002-02/22 1-03-002-06/22 1.2 

PC-fired, dry bottom, tangential 1-01-002-12/26 1-02-002-12/26 1-03-002-16/26 1.2 PC-fired, wet bottom 1-01-002-01/21 1-02-002-01/21 1-03-002-05/21 1.2 Cyclone Furnace 1-01-002-03/23 1-02-002-03/23 1-03-002-03/23 1.2 

Spreader Stoker 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 1.2 

Overfeed Stoker 1-01-002-05/25 1-02-002-05/25 1-03-002-07/25 1.2 

Underfeed Stoker 1-02-002-06 1-03-002-08 1.2 

FBC, Bubbling Bed 1-01-002-17 1-02-002-17 1-03-002-17 1.2 

FBC, Circulating Bed 1-01-002-18/38 1-02-002-18 1-03-002-18 1.2 

Hand-fired 1-03-002-14 1.2 

a Reference 54. The emission factors were developed from bituminous coal, subbituminous coal, and lignite emissions data

lb/ton to kg/Mg, multiply by 0.5. The factors apply to both controlled and uncontrolled sources.
9/98 External Combustion Sources 1.1-37

Table 1.1-16. EMISSION FACTOR EQUATIONS FOR TRACE ELEMENTS FROM COAL

COMBUSTIONa

EMISSION FACTOR EQUATION RATING: Ab

Pollutant

Emission Equation

(lb/1012 Btu)c

Antimony 0.92 * (C/A * PM)0.63

Arsenic 3.1 * (C/A * PM)0.85

Beryllium 1.2 * (C/A * PM)1.1

Cadmium 3.3 * (C/A * PM)0.5

Chromium 3.7 * (C/A * PM)0.58

Cobalt 1.7 * (C/A * PM)0.69

Lead 3.4 * (C/A * PM)0.80

Manganese 3.8 * (C/A * PM)0.60

Nickel 4.4 * (C/A * PM)0.48

a Reference 55. The equations were developed from emissions data from bituminous coal combustion,

subbituminous coal combustion, and from lignite combustion. The equations may be used to generate

factors for both controlled and uncontrolled boilers. The emission factor equations are applicable to all

typical firing configurations for electric generation (utility), industrial, and commercial/industrial

boilers firing bituminous coal, subbituminous coal, and lignite. Thus, all SCCs for these boilers are

assigned to the factors.

b AP-42 criteria for rating emission factors were used to rate the equations. c The factors produced by the equations should be applied to heat input. To convert from lb/1012 Btu to

kg/joules, multiply by 4.31 x 10-16.

C = concentration of metal in the coal, parts per million by weight (ppmwt).

A = weight fraction of ash in the coal. For example, 10% ash is 0.1 ash fraction.

PM = Site-specific emission factor for total particulate matter, lb/106

 Btu.
1.1-38 EMISSION FACTORS 9/98 Table 1.1-17. EMISSION FACTORS FOR TRACE ELEMENTS, POM, AND HCOH FROM UNCONTROLLED BIT

SUBBITUMINOUS COAL COMBUSTIONa EMISSION FACTOR RATING: E Firing Configuration (SCC) Emission Factor, lb/1012 Btu As Be Cd Cr Pbb Mn Hg Ni 

Pulverized coal, configuration unknown (no SCC) ND ND ND 1922 ND ND ND ND 

Pulverized coal, wet bottom (1-01-002-01/21, 1-02-002-01/21, 1-03-002-05/21) 538 81 44-70 1020- 1570 507 808-2980 16 840-1290 Pulverized coal, dry bottom (1-01-002-02/22, 1-02-002-06/22, 1-03-002-06/22) 684 81 44.4 1250-157 0 507 228-2980 16 1030- 1290 

Pulverized coal, dry bottom, tangential (1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26) ND ND ND ND ND ND ND ND Cyclone furnace (1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23) 115 <81 28 212-1502 507 228-1300 16 174-1290 Stoker, configuration unknown (no SCC) ND 73 ND 19-300 ND 2170 16 775-1290 Spreader stoker (1-01-002-04/24, 1-02-002-04/24, 1-03-002-09/24) 264-542 ND 21-43 942-1570 507 ND ND ND 

Overfeed stoker, traveling grate (1-01-002-05/25, 1-02-002-05/25, 1-03-002-07/25) 542-1030 ND 43-82 ND 507 ND ND ND 

a References 56-61. The emission factors in this table represent the ranges of factors reported in the literature. If only 1 da

it is still reported in this table. To convert from lb/1012 Btu to pg/J, multiply by 0.43. SCC = Source Classification Code. 

b Lead emission factors were taken directly from an EPA background document for support of the National Ambient Air Qc Based on 2 units; 133 x 106 Btu/hr and 1550 x 106 Btu/hr. d Based on 1 unit; 59 x 106 Btu/hr.
9/98 External Combustion Sources 1.1-39

Table 1.1-18 EMISSION FACTORS FOR TRACE METALS FROM

CONTROLLED COAL COMBUSTIONa

Pollutant Emission Factor (lb/ton)b EMISSION FACTOR RATING

Antimony 1.8E-05 A

Arsenic 4.1E-04 A

Beryllium 2.1E-05 A

Cadmium 5.1E-05 A

Chromium 2.6E-04 A

Chromium (VI) 7.9E-05 D

Cobalt 1.0E-04 A

Lead 4.2E-04 A

Magnesium 1.1E-02 A

Manganese 4.9E-04 A

Mercury 8.3E-05 A

Nickel 2.8E-04 A

Selenium 1.3E-03 A a References 35-53, 62-70. The emission factors were developed from emissions data at eleven facilities

firing bituminous coal, fifteen facilities firing subbituminous coal, and from two facilities firing lignite. 

The factors apply to boilers utilizing either venturi scrubbers, spray dryer absorbers, or wet limestone

scrubbers with an electrostatic precipitator (ESP) or Fabric Filter (FF). In addition, the factors apply

to boilers using only an ESP, FF, or venturi scrubber. SCCs = pulverized coal-fired, dry bottom

boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06/22; pulverized coal, dry bottom,

tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; cyclone boilers,

1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23; and, atmospheric fluidized bed combustors,

circulating bed, 1-01-002-18/38, 1-02-002-18, and 1-03-002-18.

b Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by

0.5. 
1.1-40 EMISSION FACTORS 9/98 Table 1.1-19. EMISSION FACTORS FOR CH4, TNMOC, AND N2O FROM BITUMINOUS AND SUBBITUMIN

COMBUSTIONa Firing Configuration SCC CH4b TNMOCb,c 

Emission Factor (lb/ton) EMISSION FACTOR RATING Emission Factor (lb/ton) EMISSION FACTOR RATING Emi

Fac

(lb/

PC-fired, dry bottom, wall fired 1-01-002-02/22 1-02-002-02/22 1-03-002-06/22 0.04 B 0.06 B PC-fired, dry bottom, tangentially fired 1-01-002-12/26 1-02-002-12/26 1-03-002-16/26 0.04 B 0.06 B PC-fired, wet bottom 1-01-002-01/21 1-02-002-01/21 1-03-002-05/21 0.05 B 0.04 B 

Cyclone furnace 1-01-002-03/23 1-02-002-03/23 1-03-002-03/23 0.01 B 0.11 B 

Spreader stoker 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 0.06 B 0.05 B 

Spreader stoker, with multiple cyclones, and reinjection 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 0.06 B 0.05 B 

Spreader stoker, with multiple cyclones, no reinjection 1-01-002-04/24 1-02-002-04/24 1-03-002-09/24 0.06 B 0.05 B 
9/98 External Combustion Sources 1.1-41 Table 1.1-19 (cont.). Firing Configuration SCC CH4

b TNMOCb,c

Emission

Factor

(lb/ton)

EMISSION

FACTOR

RATING

Emission

Factor

(lb/ton)

EMISSION

FACTOR

RATING

Emi

Fa

(lb/

Overfeed stokerg 1-01-002-05/25

1-02-002-05/251-03-002-07/25

0.06 B 0.05 B 

Overfeed stoker, with multiple cyclonesg

1-01-002-05/251-02-002-05/251-03-002-07/25

0.06 B 0.05 B 

Underfeed stoker 1-02-002-06

1-03-002-08

 0.8 B 1.3 B 

Underfeed stoker, with multiple cyclone

1-02-002-061-03-002-08

0.8 B 1.3 B 

Hand-fed units 1-03-002-14 5 E 10

E 

FBC, bubbling bed 1-01-002-17

1-02-002-171-03-002-17

0.06h E 0.05h E 

FBC, circulating bed 1-01-002-18

1-02-002-181-03-002-18

0.06 E 0.05 E 

a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. SCC = Source Classif

convert from lb/ton to kg/Mg, multiply by 0.5. b Reference 32. Nominal values achievable under normal operating conditions; values 1 or 2 orders of magnitude higher can occur when 

complete. c TNMOC are expressed as C2 to C16 alkane equivalents (Reference 71). Because of limited data, the effects of firing configuration on T

factors could not be distinguished. As a result, all data were averaged collectively to develop a single average emission factor for pulv

cyclones, spreaders, and overfeed stokers. d References 14-15. e No data found; emission factor for pulverized coal-fired dry bottom boilers used. f No data found; emission factor for spreader-stoker boilers used. g Includes traveling grate, vibrating grate, and chain grate stokers. h No data found; emission factor for circulating fluidized bed used.
1.1-42 EMISSION FACTORS 9/98

44 ton CO2

12 ton C

x 0.99 x 2000

lb CO2

ton CO2

x

1

100% ' 72.6

lb CO2

ton %C

Table 1.1-20. DEFAULT CO2 EMISSION FACTORS FOR U. S. COALSa

EMISSION FACTOR RATING: C

Coal Type Average %Cb Conversion Factorc

Emission Factord

(lb/ton coal)

Subbituminous 66.3 72.6 4810

High-volatile bituminous 75.9 72.6 5510

Medium-volatile bituminous 83.2 72.6 6040

Low-volatile bituminous 86.1 72.6 6250 a This table should be used only when an ultimate analysis is not available. If the ultimate analysis is

available, CO2 emissions should be calculated by multiplying the %carbon (%C) by 72.6 This resultant

factor would receive a quality rating of “B”.

b An average of the values given in References 2,76-77. Each of these references listed average carbon

contents for each coal type (dry basis) based on extensive sampling of U.S. coals. c Based on the following equation:

Where:

44 = molecular weight of CO2,

12 = molecular weight of carbon, and

0.99 = fraction of fuel oxidized during combustion (Reference 16).

d To convert from lb/ton to kg/Mg, multiply by 0.5.
9/98 External Combustion Sources 1.1-43

Figure 1.1-1. Cumulative size-specific emission factors for an example dry bottom boiler 

burning pulverized bituminous coal.

Figure 1.1-2. Cumulative size-specific emission factors for an example wet bottom boiler burning

pulverized bituminous coal.
1.1-44 EMISSION FACTORS 9/98

Figure 1.1-3. Cumulative size-specific emission factors for an example cyclone furnace 

burning bituminous coal.

Figure 1.1-4. Cumulative size-specific emission factors for an example spreader stoker burning

bituminous coal.
9/98 External Combustion Sources 1.1-45

Figure 1.1-5. Cumulative size-specific emission factors for an example overfeed stoker burning

bituminous coal.

Figure 1.1-6. Cumulative size-specific emission factors for an example underfeed stoker 

burning bituminous coal.
1.1-46 EMISSION FACTORS 9/98

References For Section 1.1

1. Bartok, B., Sarofina, A. F. (eds), Fossil Fuel Combustion, A Source Book, John Wiley & Sons,

Inc., 1991, p. 239.

2. Steam: It Generation And Use, 38th Edition, Babcock and Wilcox, New York, 1975.

3. Combustion. Fossil Power Systems. Third Edition. Published by Combustion Engineering, Inc. 

Windsor, CT., 1981.

4. Emission Factor Documentation For AP-42 Section 1.1 — Bituminous and Subbituminous Coal

Combustiont, U. S. Environmental Protection Agency, Research Triangle Park, NC, April 1993.

5. Control Techniques For Nitrogen Oxides Emissions From Stationary Sources, 2nd

Edition, EPA-450/1-78-001, U. S. Environmental Protection Agency, Research Triangle

Park, NC, January 1978.

6. Review Of NOx Emission Factors For Stationary Fossil Fuel Combustion Sources,

EPA-450/4-79-021, U. S. Environmental Protection Agency, Research Triangle Park,

NC, September 1979.

7. K. J. Lim, et al., Technology Assessment Report For Industrial Boiler Applications: 

NOx Combustion Modification, EPA-600/7-79-178f, U. S. Environmental Protection

Agency, Research Triangle Park, NC, December 1979.

8. Particulate Polycyclic Organic Matter, National Academy of Sciences, Washington, DC, 1972.

9. Vapor Phase Organic Pollutants- Volatile Hydrocarbons and Oxidation Products, National

Academy of Sciences, Washington, DC, 1976.

10. D. H. Klein, et al., "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power

Plants", Environmental Science and Technology, 9:973-979,1975. 

11. D. G. Coles, et al., "Chemical Studies of Stack Fly Ash from a Coal-Fired Power Plant",

Environmental Science and Technology, 13:455-459, 1979.

12. S. Baig, et al., Conventional Combustion Environmental Assessment, EPA Contract 

No. 68-02-3138, U. S. Environmental Protection Agency, Research Triangle Park, NC, 1981.

13. L. P. Nelson, et al., Global Combustion Sources of Nitrous Oxide Emissions, Research Project

2333-4 Interim Report, Sacramento: Radian Corporation, 1991.

14. R. L. Peer, et al., Characterization of Nitrous Oxide Emission Sources, U. S. Environmental

Protection Agency, Office of Research and Development, Research Triangle Park, NC, 1995.

15. S. D. Piccot, et al., Emissions and Cost Estimates for Globally Significant Anthropogenic

Combustion Sources of NOx, N2O, CH4, CO, and CO2, U. S. Environmental Protection Agency,

Office of Research and Development, Research Triangle Park, NC, 1990.
9/98 External Combustion Sources 1.1-47

16. G. Marland and R. M. Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For

Estimation and Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research

Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN, 1983.

17. G. Marland and R. M. Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For

Estimation and Results For 1950-1982, Tellus, 36B: 232-261.

18. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the

Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of

1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.

19. Control Techniques For Sulfur Dioxide Emissions From Stationary Sources, 2nd

Edition, EPA-450/3-81-004, U. S. Environmental Protection Agency, Research Triangle

Park, NC, April 1981.

20. Alternative Control Techniques Document--NOx Emissions From Utility Boilers, EPA-453/R-94-

023, March 1994, pp. 2-15, 2-18, 5-103.

21. Emission Factor Documentation For AP-42, Section 1.1, Bituminous and Subbituminous Coal

Combustion, Prepared by Acurex Environmental Corp., Edward Aul & Associates, Inc.,

E. H. Pechan And Associates, Inc., EPA Contract No. 68-D0-11210, April 1993.

22. Carlo Castaldini, and Meredith Angwin, Boiler Design And Operating Variables

Affecting Uncontrolled Sulfur Emissions From Pulverized Coal Fired Steam

Generators, EPA-450/3-77-047, U. S. Environmental Protection Agency, Research

Triangle Park, NC, December 1977.

23. K. Cushing, et al., "Fabric Filtration Experience Downstream From Atmospheric

Fluidized Bed Combustion Boilers", Presented at the Ninth Particulate Control

Symposium, October 1991. 

24. Susan Stamey-Hall, Evaluation of Nitrogen Oxide Emissions Data from TVA Coal-Fired Boilers,

EPA-600/R-92-242, U. S. Environmental Protection Agency, Research Triangle Park, NC,

December 1992.

25. Joel Vatsky and Timothy W. Sweeney, Development of an Ultra-Low Nox Pulverizer Coal

Burner, Presented at the EPA/EPRI 1991 Joint Symposium on Combustion Nox Control, March

25-28, 1991, Washington, DC.

26. T. L. Lu, R. L. Lungren, and A. Kokkinos, Performance of a Large Cell-Burner Utility Boiler

Retrofitted with Foster Wheeler Low-NOx Burners, Presented at the EPA/EPRI 1991 Joint

Symposium on Combustion NOx Control, March 25-28, 1991, Washington, DC.

27. Alternative Control Techniques Document — NOx Emissions from Utility Boilers, EPA-453/

R-94-023, U. S. Environmental Protection Agency, Research Triangle Park, NC, March 1994.

28. Standards Of Performance For New Stationary Sources, 36 FR 24876,

December 23, 1971.
1.1-48 EMISSION FACTORS 9/98

29. Field Tests Of Industrial Stoker Coal Fired Boilers For Emission Control And

Efficiency Improvement - Sites L1 — 17, EPA-600/7-81-020a, U. S. Environmental

Protection Agency, Washington, DC, February 1981.

30. Application Of Combustion Modifications To Control Pollutant Emissions From

Industrial Boilers — Phase I, EPA-650/2-74-078a, U. S. Environmental Protection

Agency, Washington, DC, October 1974.

31. Source Sampling Residential Fireplaces For Emission Factor Development,

EPA-50/3-6-010, U. S. Environmental Protection Agency, Research Triangle Park, NC,

November 1875.

32. Atmospheric Emissions From Coal Combustion: An Inventory Guide, 999-AP-24, U. S.

Environmental Protection Agency, Washington, DC, April 1966.

33. Inhalable Particulate Source Category Report For External Combustion Sources,

EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA, January

1985.

34. Results of the March 28, 1990 Dioxin Emission Performance Test on Unit 3 at the NSP Sherco

Plant in Becker, Minnesota. Interpoll Laboratories, Inc., Circle Pines, Minnesota. July 11, 1990.

35. Field Chemical Emissions Monitoring Project: Site 22 Emissions Report. Radian Corporation,

Austin, Texas. February, 1994.

36. Toxics Assessment Report. Illinois Power Company. Baldwin Power Station- Unit 2. Baldwin,

Illinois. Volumes I- Main Report. Roy F. Weston, Inc. West Chester, Pennsylvania. December,

1993.

37. Toxics Assessment Report. Minnesota Power Company Boswell Energy Center- Unit 2. 

Cohasset, Minnesota. Volume 1-Main Report. Roy F. Weston, Inc. West Chester,

Pennsylvania. December, 1993. (EPRI Report)

38. Field Chemical Emissions Monitoring Project: Site 11 Emissions Monitoring. Radian

Corporation, Austin, Texas. October, 1992. (EPRI Report)

39. Field Chemical Emissions Monitoring Project: Site 21 Emissions Monitoring. Radian

Corporation, Austin, Texas. August, 1993. (EPRI Report)

40. Field Chemical Emissions Monitoring Project: Site 111 Emissions Report. Radian Corporation,

Austin, Texas. May, 1993. (EPRI Report)

41. Field Chemical Emissions Monitoring Project: Site 115 Emissions Report. Radian Corporation,

Austin, Texas. November, 1994. (EPRI Report)

42. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant-Niles Station

No. 2. Volumes One, Two, and Three. Battelle, Columbus, Ohio. December 29, 1993.

43. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing an

ESP/Wet FGD System. Volumes One, Two, and Three. Battelle, Columbus, Ohio. December

1993.
9/98 External Combustion Sources 1.1-49

44. Assessment of Toxic Emissions From a Coal Fired Power Plant Utilizing an ESP. Final ReportRevision 1. Energy and Environmental Research Corporation, Irvine, California. December 23,

1993.

45. 500-MW Demonstration of Advanced Wall-Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers. Radian Corporation, Austin, Texas.

46. Results of the November 7, 1991 Air Toxic Emission Study on the Nos. 3, 4, 5 & 6 Boilers at the

NSP High Bridge Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992.

47. Results of the December 1991 Air Toxic Emission Study on Units 6 & 7 at the NSP Riverside

Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. February 28, 1992.

48. Field Chemical Emissions Monitoring Project: Site 10 Emissions Monitoring. Radian

Corporation, Austin, Texas. October, 1992. (EPRI Report)

49. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring. Radian

Corporation, Austin, Texas. November, 1992. (EPRI Report)

50. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring. Radian

Corporation, Austin, Texas. October, 1992. (EPRI Report)

51. Field Chemical Emissions Monitoring Project: Site 101 Emissions Report. Radian Corporation,

Austin, Texas. October, 1994. (EPRI Report)

52. Field Chemical Emissions Monitoring Project: Site 114 Report. Radian Corporation, Austin,

Texas. May, 1994. (EPRI Report)

53. Field Chemical Emissions Monitoring Report: Site 122. Final Report, Task 1 Third Draft. EPRI

RP9028-10. Southern Research Institute, Birmingham, Alabama. May, 1995. (EPRI Report)

54. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP Inventory, EPA600/7-85-041, U. S. Environmental Protection Agency, October 1985.

55. Electric Utility Trace Substances Synthesis Report, Volume 1, Report TR-104614, Electric Power

Research Institute, Palo Alto, CA, November 1994.

56. Locating And Estimating Air Emissions From Sources Of Chromium, EPA-450/4-84-007g, U. S.

Environmental Protection Agency, July 1984.

57. Locating And Estimating Air Emissions From Sources Of Formaldehyde, (Revised),

EPA-450/4-91-012, U. S. Environmental Protection Agency, March 1991.

58. Estimating Air Toxics Emissions From Coal And Oil Combustion Sources, EPA-450/2-89-001,

Radian Corporation, Project Officer: Dallas W. Safriet, Research Triangle Park, NC, April 1989.

59. Canadian Coal-Fired Plants, Phase I: Final Report And Appendices, Report for the Canadian

Electrical Association, R&D, Montreal, Quebec, Contract Number 001G194, Report by Battelle,

Pacific Northwest Laboratories, Richland, WA.
1.1-50 EMISSION FACTORS 9/98

60. R. Meij, Auteru dr., The Fate Of Trace Elements At Coal-Fired Plants, Report No. 2561-MOC

92-3641, Rapport te bestellen bij; bibliotheek N.V. KEMA, February 13, 1992.

61. Locating And Estimating Air Emissions From Sources Of Manganese, EPA-450/4-84-007h,

September 1985.

62. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 & 2, and Unit 3

Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota. Interpoll Laboratories, Inc.,

Circle Pines, Minnesota. October 30, 1991.

63. Results of the November 5, 1991 Air Toxic Emission Study on the No. 1, 3 & 4 Boilers at the

NSP Black Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992.

64. Results of the January 1992 Air Toxic Emission Study on the No. 2 Boiler at the NSP Black Dog

Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. May 4, 1992.

65. Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2 at the

Sherburne County Generating Station in Becker, Minnesota. Interpoll Laboratories, Inc., Circle

Pines, Minnesota. July, 1990.

66. Results of the May 1, 1990 Trace Metal Characterization Study on Units 1 and 2 at the

Sherburne County Generating Station. Interpoll Laboratories, Inc., Circle Pines, Minnesota. 

July 18, 1990.

67. Results of the March 1990 Trace Metal Characterization Study on Unit 3 at the Sherburne

County Generating Station. Interpoll Laboratories, Circle Pines, Minnesota. June 7, 1990.

68. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring. Radian

Corporation, Austin, Texas. April, 1993. (EPRI Report)

69. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring. Radian

Corporation, Austin, Texas. March, 1994. (EPRI Report)

70. Characterizing Toxic Emissions from a Coal-Fired Power Plant Demonstrating the AFGD ICCT

Project and a Plant Utilizing a Dry Scrubber /Baghhouse System. Final Draft Report. 

Springerville Generating Station Unit No. 2. Southern Research Insititute, Birmingham,

Alabama. December, 1993.

71. Emissions Of Reactive Volatile Organic Compounds From Utility Boilers,

EPA-600/7-80-111, U. S. Environmental Protection Agency, Washington, DC,

May 1980.

72. EPA/IFP European Workshop On The Emission Of Nitrous Oxide For Fuel Combustion, EPA

Contract No. 68-02-4701, Ruiel-Malmaison, France, June 1-2, 1988.

73. R. Clayton, et al., NOx Field Study, EPA-600/2-89-006, U. S. Environmental Protection Agency,

Research Triangle Park, NC, February 1989.

74. L. E. Amand, and S. Anderson, "Emissions of Nitrous Oxide from Fluidized Bed Boilers",

Presented at the Tenth International Conference on Fluidized Bed Combustor, San Francisco,

CA, 1989.
9/98 External Combustion Sources 1.1-51

75. Alternative Control Techniques Document--NOx Emissions From Utility Boilers,

EPA-453/R-94-023, Office of Air Quality Standards, Research Triangle Park, NC, 1994.

76. Alliance Technologies Corporation, Evaluation of Significant Anthropogenic Sources of

Radiatively Important Trace Gases, U. S. Environmental Protection Agency, Office of Research

and Development, Research Triangle Park, NC, 1990.

77. R. A. Winschel, Richard, "The Relationship of Carbon Dioxide Emissions with Coal Rank and

Sulfur Content," Journal of the Air and Waste Management Association, Vol. 40, no. 6, pp. 861-

865, June 1990.

78. Public Service Electric and Gas Company Mercer Generating Station Unit No. 2 Emission

Compliance Test Program. November 1994.

79. Particulate Emission Study Performed for Madison Gas and Electric Company at the Blount

Street Station Units 7, 8, 9 Inlets/Outlets. Mostardi-Platt Associates, Inc. December 6, 1994.

80. Particulate Emission Study Performed for Marshfield Electric and Water Department at the

Wildwood Station Marshfield Wisconsin Boiler 5 Stack. Mostardi-Platt Associates, Inc. 

January 23-25, 1990.

81. Report on Particulate, SO2, and NOx Compliance Testing. Dairyland Power Cooperative J.P.

Madgett Stack. Alma, Wisconsin. CAE. January 6, 1995.

82. Particulate Emissions Test Results. Portland General Electric Coal-fired Power Plant. 

Boardman, Oregon. SAIC, Inc. January 25, 1994.

83. Report on Compliance Testing Performed at Marshfield Electric and Water Department

Wildwood Station Unit 5, Marshfield, Wisconsin. Clean Air Engineering, December 11, 1989.

84. Portland General Electric Company Boardman Coal Plant. Unit #1 Coal-fired Boiler. 

Boardman, Oregon. August 24-27,1995.

85. Particulate Emission Compliance Study Performed for Portland General Electric at the Boardman

Plant Unit 1 Stack. Boardman, Oregon. September 19, 1996.

86. Emissions Source Test Report. Portland General Electric Coal-Fired Power Plant. Boardman,

Oregon. OMNI Environmental Services, Inc. October 17, 1990.

87. Source Emissions Test Report Compliance. Portland General Electric Coal-Fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services. January 29, 1991.

88. Source Test Report. Particulate Emissions. Portland General Electric Coal-Fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services, Inc. January 14, 1991.

89. Emissions Source Test Rpeort. Portland General Electric Coal-Fired Power Plant. Boardman,

Oregon. OMNI Environmental Services, Inc. April 3, 1991.

90. Source Emissions Test Report. Portland General Electric Coal-Fired Power Plant. Boardman,

Oregon. OMNI Environmental Services, Inc. January 21, 1992.
1.1-52 EMISSION FACTORS 9/98

91. Particulate Emissions Test Results. Portland General Electric Coal-fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services, Inc. April 4, 1992.

92. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services, Inc. September 9, 1992.

93. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services, Inc. November 6, 1992.

94. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. 

Boardman, Oregon. OMNI Environmental Services, Inc. January 26, 1993.

95. Stationary Source Sampling Report. Keystone Cogeneration Facility. Keystone Cogeneration

Facility. Logan Township, NJ. November 1994.

96. Source Emissions Survey of City Public Service Board J.K. Spruce Unit Number 1 Stack. 

METCO Environmental. December 1992.

97. Report of Particulate Emission Testing on the Number 1 Boiler at Associated Milk Products

Incorporated Located in Jim Falls, Wisconsin. Environmental Services of American, Inc. 

November 1994. 

98. Appletone Papers, Inc. Boiler Emission Test at Appleton, WI. May 11 and 12, 1993. Badger

Laboratories and Engineering.

99. Appleton Papers, Inc. Boiler Emission Test Report at Appleton, WI. Badger Laboratories and

Engineering. October 11, 1993.

100. Results of a Source Emission Compliance Test on Boiler #2 at the Hills Farm Heating Plant,

Madison, Wisconsin. MMT Environmental Services, Inc. January 22, 1993.

101. Results of a Source Emission Compliance Test on Boiler #2 at the Hills Farm Heating Plant,

Madison, Wisconsin. MMT Environmental Services, Inc. March 2, 1995.

102. Report to Mosinee Paper Company for Particulate Matter Emission Testing. No. 6 Boiler at

Mosinee, Wisconsin. May 18, 19, and 20, 1993.

103. Report to Milwaukee County for Particulate Matter Emission Test Boiler No. 21. Environmental

Technology and Engineering Corporation. November 5, 1991.

104. Report on Compliance Testing Conducted at Oscar Mayer Foods Corporation, Madison,

Wisconsin. Clean Air Engineering. July 21, 1989.