EP A/600/A-96/009
Preliminary Inventory of Hazardous Air Pollutant Emissions
from Electric Utility Boilers in the United States
Eric S. Ringler
Southern Research Institute
P.O. Box 13825
Research Triangle Park, NO 27709-3825
Julian W. Jones
U.S. Environmental Protection Agency
Air Pollution Prevention and Control Division (MD-62)
Research Triangle Park, North Carolina 27711
ABSTRACT
The Clean Air Act Amendments of 1990 (CAAA) dramatically increased the number and type
of sources subject to potential regulation. Title III of the CAAA identifies 189 hazardous air
pollutants (HAPs) and indicates that many sources emitting these compounds may ultimately be
required to meet strict industry-specific Maximum Achievable Control Technology (MACT)
emissions standards. Fossil fuel (i.e., coal, oil, natural gas) combustion generates a variety of organic
HAPs and a number of toxic metals (e.g., mercury, chromium, arsenic). Since utility boilers
consume a large proportion of the total fossil fuel used in the U.S., including most of the coal, they
may be a significant source of HAPs.
EPA's Air Pollution Prevention and Control Division (APPCD) has been conducting research
to identify and characterize HAP emissions from significant sources, including fossil fuel combustion
in electric utility boilers. This paper summarizes an effort undertaken to develop an inventory of
HAP emissions from these boilers. Several approaches toward developing and utilizing suitable
emission factors are examined, and a HAP inventory is presented that is based on the most current,
comprehensive, and quality assured test data available. Analyses are presented that compare results
and assess the significance of emissions estimates based on the various approaches examined.
INTRODUCTION
The Clean Air Act Amendments of 1990 (CAAA) dramatically increased the number and type
of sources subject to potential regulation. Title III of the CAAA identifies 189 hazardous air
pollutants (HAPs) and indicates that sources liberating significant quantities of these compounds may
ultimately be required to meet strict industry-specific Maximum Achievable Control Technology
(MACT) emissions standards. Fossil fuel (i.e., coal, oil, natural gas) combustion generates a variety
of organic HAPs and a number of toxic metals (e.g., mercury, chromium, and arsenic). Since utility
boilers consume a large proportion of the total fossil fuel used in the U.S., including most of the
coal, they may be a significant source of HAPs.
EPA's Air Pollution Prevention and Control Division (APPCD) has been conducting research
to identify and characterize HAP emissions from significant sources, including fossil fuel combustion
in electric utility boilers. This paper summarizes an effort undertaken to develop a state-level
inventory of HAP emissions from these boilers. The effort was conducted in three phases, each
succeeding phase involving more recent, detailed data and information than its predecessor.
SUMMARY OF FIRST TWO PHASES
The first phase of APPCD's effort was to develop a preliminary inventory based on emission
factors adapted from published EPA sources. An activity data base was developed based on the
Department of Energy's (DOE's) EIA Form 767 data base for 1991. Because of the large number of
boiler firing types and control device types represented in the EIA-767 data, some aggregation of

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these was necessary to arrive at a reasonable number of model categories for which emission factors
were to be developed. This was accomplished by combining boiler and control device types with
similar emissions characteristics. The final list of boiler categories is given in Table 1. Then, a
literature survey was completed to identify the most complete and appropriate sources of EPA-
published emission factors.1"10 These emission factors were then applied to the activity data to
develop an initial HAP emissions inventory.
A critical review of the emissions inventory resulting from the first phase of the effort
suggested that its completeness and accuracy were compromised by the limited availability of
representative and reliable emission factors. In addition, experience with measurements of emissions
from coal combustion at power plants suggested that some of the emissions estimates generated using
the published EPA emission factors were unreasonable. Finally, the effects of FGD systems on HAP
emissions had not been addressed, because none of the published EPA emission factors included
these effects.
The second phase of the effort was a systematic characterization of inorganic HAP emissions
due to coal combustion, based on a detailed analysis of the fate of trace elements contained in coal.
Trace element data were obtained from the U.S. Geological Survey (USGS) data on coal quality
(COALQUAL) in geologic deposits throughout the U.S.
Median concentrations of coals in the data base were used as the starting point in estimating
HAP emission factors. Coal cleaning, which reduces sulfur and ash from the coal, also reduces the
concentrations of toxic elements. The "as-mined" concentrations obtained from the USGS data base
were reduced to account for coal cleaning according to the average elemental reductions reported in
the literature.11
During combustion, toxic elements are partitioned into three fractions: bottom ash, fly ash,
and vapor. Elements with low vapor pressures are generally found in the bottom ash and fly ash,
with little or no vapor fraction. Elements with moderate vapor pressures tend to concentrate in the
fly ash due fo vaporization in the combustion zone with subsequent condensation as the flue gas is
cooled in the heat exchanger. This condensation effect tends to increase the concentration of these
elements in the small particle size range; this phenomenon is termed "enrichment." Elements with
relatively high vapor pressures can have a significant vapor fraction at exhaust temperatures, with
only minor fractions in the fly ash. Elemental partitioning data for pulverized coal and cyclone
boilers were obtained from the literature.12 Uncontrolled emission factors can be estimated based on
the fuel concentration data and the sum of the fly ash and vapor fractions.
Although particulate matter (PM) control devices [e.g., electrostatic precipitators (ESPs)] can
reduce the emissions of toxic elements that are emitted as fly ash, these controls have little or no
effect on the vapor fraction. Flue gas desulfurization (FGD) can reduce both the fly ash fraction and
the vapor fraction of many elements. Information on the fractional removal efficiency of PM
control devices was obtained from the literature.13 These removal efficiencies were used to estimate
the removal of toxic elements in the fly ash. Controlled emission factors for these devices were then
estimated based on the sum of the controlled fly ash and the vapor fraction. In addition, these
particulate control devices will have little to no effect on gaseous pollutants such as hydrogen
chloride (HC1) and formaldehyde.
Two categories of FGD systems exist: wet scrubbers and dry scrubbers. The operational
characteristics of these two categories of FGD systems are significantly different. However,
insufficient HAP emissions data exist to adequately differentiate between the two technologies." In
addition, dry scrubbers are currently used at only 20 of the facilities included in the preliminary
inventory, while wet scrubbers are used at 168 facilities. As such, the available HAP removal
efficiency data for wet scrubbers were used to estimate emission factors for facilities equipped with
either FGD system.
By applying the adjustments for the technologies just described, emission factors for 20
inorganic HAPs from coal combustion were calculated based on average fuel concentrations. The
average fuel concentrations were partitioned into bottorj/fehi fly ash, HdpGP. Jlifi-fly iJjli WS
2

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further partitioned into a series of size fractions between 0 and 30 micrometers. An uncontrolled
emission factor was derived based on the sum of the fly ash and vapor fractions. Size-specific
control efficiencies were then used to account for HAP removal in common control devices.
This approach yielded a more complete set of emission factors (specific to pollutant, boiler
type, control type, and fuel) than were attainable in the first phase of this effort (using EPA-
published emission factors), and also addressed the effect of FGD systems on HAP emissions.
PRELIMINARY INVENTORY DEVELOPMENT USING TEST DATA
Emission Factor Development
While the first two phases of this study were underway, the Electric Power Research Institute
(EPRI) and DOE were conducting field measurements programs to improve available data on power
plant emissions of toxic substances. These programs included an extensive array of measurements of
airborne emissions at 43 sites selected to be representative of toxic emissions from the U.S. utility
industry as a whole. The measurements protocols were carefully researched and documented,
consistent and quality assured so that the resulting data represent the most reliable, current, and
complete set of direct measurements of HAP emissions from utility boilers available to date. EPRI
also made use of USGS data on trace element concentrations occurring in coal to develop
relationships between coal concentrations and measurements of emissions of particulate inorganic
HAPs.15
The EPRI/DOE data became available after the first two phases of the effort were complete.
The third phase adapted the EPRI/DOE test data and emissions relationships to produce a preliminary
emissions inventory. The approach was designed to yield emission factors for the model boiler
configurations (i.e., boiler type, fuel, and control device) derived in the first phase effort from those
present in the 1991 DOE Form EIA-767 activity data. This approach is thus representative of real
world plant "configurations and operating conditions, while providing a reasonable summary level of
aggregation.
It must be emphasized that this inventory and the associated emission factors were developed
as part of a research effort to assess alternative approaches for characterizing HAP emissions from
the utility industry. The inventory and emission factors are currently under review by EPA
regulatory personnel and therefore do not represent EPA policy or guidance. As such, the inventory
should be viewed as preliminary.
The first step in developing the preliminary inventory was to develop emission factors from
the test data using suitable averaging techniques. Although the EPRI/DOE test data represented
nearly all of the most significant model boiler configurations, only a few configurations were
represented with a sufficient number of tests to provide robust average emission factors. EPRI used
two general approaches in an attempt to derive the most representative possible emission factors from
the test data. First, for non-volatile inorganic HAP (trace element) emissions from coal -fired boilers,
EPRI developed correlations of test values (in pounds per million British thermal units) with plant-
specific trace element concentrations and PM emissions. Second, for volatile inorganic HAPs,
organic HAPs, and radionuclide emissions from coal-, oil-, and gas-fired boilers, EPRI pooled the
available test data into more general categories to provide a more robust data set for determining
average emission values.
The overall rationale, approach, and statistical methodologies that EPRI used in developing
emission factors were reviewed and were found to be satisfactory. Therefore, EPRI's results were
adopted as a basis for the preliminary inventory. While EPRI applied the emission factors and
correlations on a plant-specific basis, in this study they were applied to model boiler categories.
To obtain emission factors for trace element emissions from coal-fired boilers, the EPRI
correlations were applied using representative inputs for each model boiler configuration. The
average PM input was obtained from PM emissions data reported on EIA Form 767. Average ash
values for each configuration were similarly obtained. Trace element concentration inputs specific to
3

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coal rank (bituminous, subbituminous, and lignite) were taken as median values for major coal-
producing regions in the country based on the USGS COALQUAL data reported by EPRI.
The COALQUAL data base represents trace element concentrations in geologic deposits of
coal, but does not necessarily represent the quality of coal that is consumed by utility boilers. EPRI
screened the COALQUAL data to obtain results that better represent coal that would be supplied to
electric utilities. Note also that, in EPRI's inventory, trace element concentration data were used that
were specific to the coal supply region likely to supply a given plant with fuel. This level of
refinement was not applied in this study because emission estimates were aggregated for model
configurations and not specific plants.
Emissions were calculated for 19 HAPs, including 9 inorganic HAPs, 4 volatile inorganic
HAPs, 5 organic HAPs (including equivalents for total PAH and dioxins/furans), and radionuclides.
Specific HAP species are listed below.
Inorganic HAPs
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Volatile Inorganic HAPs
Mercury (Hg)
Selenium (Se)
Hydrogen chloride (HC1)
Hydrogen fluoride (HF)
Organic HAPg
Benzene (QH6)
Toluene (C6H5CH3)
Formaldehyde (HCHO)
Polycyclic aromatic hydrocarbons (PAHs) — Benzo(a)pyrene equivalents
Dioxins/Furans — 2,3.7,8-TCDD equivalents
These HAPs have been identified in power plant stack emissions and have known toxicity
factors that can be employed in carrying out a health risk assessment.
Preliminary Inventory Estimates of 1991 U.S. Electric Utility Boiler HAP Emissions
In 1991, it is estimated that U.S. fossil fueled power plants emitted 1,708 tons* of combined
HAPs, excluding HC1 and hydrogen fluoride (HF). Coal-fired boilers made up about 72 percent of
these emissions, followed by oil at about 24 percent and gas at 4 percent. HC1 emissions totaled
115,076 tons, and HF emissions totaled 33,373 tons. Coal-fired boilers made up 99 percent of the
HC1 and HF emissions, with oil making up the remainder. HAP emissions are summarized in Table
2. These values represent total emissions from all fuels (coal, oil, and gas) consumed by a given
boiler, as opposed to emissions associated with the primary fuel only. Many boilers use more than
one fuel; e.g., a primary coal-fired boiler may use natural gas during start-up and may use some oil
on occasion as makeup fuel. Note that emissions of HC1 and HF overwhelm emissions of all other
HAPs combined. This is due to the relative abundance of naturally occurring chlorine and fluorine
in coal as well as the relative ineffectiveness of PM control devices in reducing vapor-phase
emissions.
Of the total HAP emissions for all fuels combined, selenium, nickel, and manganese are
emitted in the greatest quantities at 28, 26, and 15 percent of total emissions, respectively (excluding
HC1 and HF). Together, these three HAPs make up about 70 percent of the total. The selenium and
manganese emissions are almost wholly from coal combustion, while nickel emissions are mostly
from oil combustion. Chromium, arsenic, formaldehyde, and lead, which are primarily from coal
combustion, are the next most abundant emissions, each with 4 to 6 percent of the total. The bulk of
the formaldehyde emissions are due to natural gas combustion, but with significant contributions
* 1 ton = 0.907 kg
4

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from coal and oil. Emissions of all these seven HAPs make up over 90 percent of the total
emissions.
Mercury, cobalt, benzene, and toluene are the next most abundant HAPs. Mercury and
benzene emissions are primarily associated with coal, cobalt with coal and oil, and toluene with gas,
coal, and oil. The remaining HAPs make up less than 1 percent of the total emissions. With the
exception of formaldehyde, organics make up a small part of total HAP emissions (less than 5
percent) from coal and oil combustion. Note, however, that toxicity may be a more important
consideration than the absolute magnitude of the emissions; e.g., relatively small emissions of
dioxins/furans may be of greater concern than emissions of HAPs present in greater abundance.
Table 3 gives fuel-specific annual emissions in pounds of HAP emitted per plant. It is clear
from the results in the table that, if HC1 and HF emissions are excluded, most plants would likely not
be classified as a major source of HAP emissions per Section 112 of the CAAA, based on either the
10-ton limit for any single HAP or the 25-ton limit for combined emissions. Excluding HC1 and HF,
total annual HAP emissions from coal-, oil-, and gas-fired plants average about 2.7 tons, slightly
greater than about 3.5 tons, and about 0.04 tons, respectively.
On the other hand, the Section 112 limits are easily exceeded for HC1 and/or HF emissions at
coal- and oil-fired plants. Average per-plant HC1 emissions are on the order of 250 tons per year for
coal-fired plants and 12 tons per year for oil-fired plants. Average per-plant HF emissions are about
73 tons per year for coal-fired plants. Factors for HF emissions from oil-fired plants could not be
determined based on available data. Similarly, for gas-fired plants, data were unavailable to estimate
emission factors for HF and HC1. Note that, if the classification is applied at the boiler rather than
the plant level, many boilers would be below the 10-ton limit for HC1 and/or HF.
Note also that the emissions in Table 3 are based on the primary fuel consumed by a plant;
i.e., emissions associated with combustion of secondary fuels is neglected. This does not seriously
impact the representativeness of the per-plant estimates since the vast majority of the heat input at
most plants is from the primary fuel. This is especially true since secondary fuels are normally oil or
gas, and generally lower HAP emission rates are associated with these fuels.
COMPARATIVE ANALYSIS OF RESULTS OF THE THREE PHASES
A comparison was made of emission factors developed under: (1) the first phase of the effort,
or those previously published by EPA (denoted herein as EPA); (2) the second phase of the effort,
or the trace element fate analysis (TEFA); and (3) the third phase of the effort, or the preliminary
inventory (PI). For the comparison, only the most common boiler/fuel/control configurations and
those which are significant because of their ability to reduce HAP emissions (i.e., those with FGD
systems) were included. Note, however, that these configurations made up over 90 percent of the
total heat input to the utility industry in 1991.
To simplify the analysis of this extensive array of data, a systematic approach was utilized,
consisting of (1) broad, order of magnitude comparisons, (2) more restrictive comparisons to
determine whether factors agreed within a factor of 2, and (3) analysis of trends toward one method
over- or under-predicting another. Finally, total HAP emissions estimates based on the PI approach
were compared with estimates based on the published EPA factors. Unfortunately, because of space
limitations, all of these emission factors cannot be listed herein.
Order of Magnitude Comparisons
EPA emission factors for coal-fired boilers generally did not agree well with PI or TEFA
emission factors. Less than one-third of the EPA emission factors were within the same order of
magnitude as the PI emission factors. Similarly, only about one-third of the EPA emission factors
are within the same order of magnitude as the TEFA emission factors. Emission factors for arsenic,
beryllium, lead, mercury, and selenium tended to agree better than those for other HAPs in both
cases. For oil- fired boilers, the agreement between EPA and PI factors was much better. About 75
5

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percent of the factors are within the same order of magnitude, and agreement is relatively consistent
across different HAPs.
Agreement between PI and TEFA emission factors is generally good. Nearly 90 percent of
the factors are within the same order of magnitude, and agreement is consistent among all HAPs.
Emission factors for combined fabric filter (FF) and FGD controls generally did not agree as well as
for other configurations. Note that this comparison did not include oil- and gas-fired boilers, and
also did not include organics since TEFA factors were not developed for these fuels and HAPs.
Factor of 2 Comparisons
In this more restrictive test, few EPA emission factors compared well with PI or TEFA
emission factors. Less than 10 percent of EPA emission factors for coal-fired boilers were within a
factor of 2 of either PI or TEFA emission factors. Mercury emission factors showed the best
agreement, with some agreement for arsenic, lead, and selenium. For oil-fired boilers, less than 20
percent of EPA factors were within a factor of 2 of the PI emission factors. These included factors
for arsenic, chromium, manganese, and nickel.
About 40 percent of the PI and TEFA factors agreed within a factor of 2. These represent all
of the HAPs where data were available for comparison. This level of agreement was also fairly
consistent across fuel/control configurations. The agreement increased to 65 percent when the test
was relaxed to a factor of 5.
Trends
EPA factors were nearly always higher than PI or TEFA factors. Less than 15 percent of PI
or TEFA factors are higher than the EPA factors. This may reflect a degree of conservatism in the
literature-based values, which are predominantly based on engineering estimates, as opposed to
source test data. Since most of the EPA factors differed from the PI and TEFA factors by more than
an order of magnitude, this level of conservatism was generally on the order of a factor of 10.
Overall, there is no clear trend for PI factors to be higher or lower than TEFA factors. About
half of the PI factors were higher, and about half were lower. However, there were notable trends
for some fuel/control configurations, and for some HAPs. PI factors for subbituminous coal with
ESP control, and lignite coal with ESP, ESP/FGD, and ESP/FF control tended to be less than TEFA
factors. In addition, PI factors for cobalt, fluorine, and radionuclides tended to be less than the
TEFA factors. PI factors for other configurations and HAPs tend to be neutral or higher than TEFA
factors. Given the complexity of the emission factor development processes for these two
approaches, it is difficult to determine the exact reasons for these trends. Both approaches make use
of trace element concentrations in coal, and the same average trace element concentration values
were used in each case. The fundamental difference in the two techniques is the use of emissions
relationships based on PM emissions and test data for the PI method versus pure engineering analysis
in the TEFA method.
Inventory Estimates
Table 4 compares inventory estimates for HAP emissions (tons per year, in 1991) based on
the PI and EPA factors. The EPA factors yielded a significant overestimate of total U.S. HAP
emissions. Total PI emissions (excluding HC1 and HF) are 1708 tons, while total EPA emissions are
14,619 tons. The totals are dominated by HAP emissions due to coal combustion. Thus, total PI
emissions for coal are less than 10 percent of the total EPA emissions. However, for oil combustion,
PI emissions exceed EPA emissions (407 versus 191 tons, respectively). This is largely due to the
bigger PI estimate for nickel. For natural gas combustion, PI emissions were also in excess of EPA
emissions; however, this was largely due to the fact that gas emission factors for many HAPs were
unavailable in the EPA data. Inventory estimates were not generated based on the TEFA factors;
however, total TEFA emissions would be of the same order as the PI estimates based on the general
level of agreement in the emission factors for the two methods.
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UNCERTAINTY OF EMISSION ESTIMATES IN THE PRELIMINARY INVENTORY
Significant uncertainty is generally associated with inventory efforts of this kind. Inventory
efforts are complex and typically rest on a large number of assumptions, and emissions test data are
typically highly variable. Based on a very general assessment of the uncertainty in the PI inventory,
it appears that the emission factors and emissions estimates may be accurate to within a factor of
about 3 to 5, depending on the specific HAP and control configuration. Uncertainty for HAPs with
very small emissions (e.g., PAH and dioxins/furans) is larger due to the greater measurement
uncertainties. These estimates are based on variability in the test data combined with consideration
of the effects of different approaches to developing and applying emission factors to an inventory.
Comparing emission factors developed under the TEFA and PI approaches appears to support
these estimates of overall uncertainty in the inventories. These two approaches are methodologically
independent; the PI approach being based on test data, and the TEFA approach being based on
engineering analysis. The fact that emission factors developed under these two approaches agree
within a factor of about 2 to 5 suggests that both approaches are essentially valid and that the
uncertainty factor of about a factor of 3 to 5 may not be far off the mark.
CONCLUSIONS
Previously published EPA emission factors for HAP emissions from electric utility boilers are
not generally representative and show poor agreement with analysis of USGS coal quality data and
recent field test results. Specifically, only about one-third of the EPA emission factors were of the
same order of magnitude as factors developed by the other methods. Agreement was somewhat
better (for some boiler/fuel/control device configurations) for arsenic, beryllium, lead, mercury, and
selenium. For oil-fired boilers, some agreement was also obtained for nickel, manganese, and
chromium.
This study provides some useful insights concerning the quality and representativeness of
several varying approaches for developing a HAP emissions inventory for utility boilers. The
preliminary inventory provides reasonably consistent emission factors and emission estimates, with a
reasonable level of uncertainty. The inventory and other results of this effort have been provided by
APPCD to EPA's Office of Air Quality Planning and Standards (OAQPS) for possible use in future
publications of emission factors and/or other uses they may deem appropriate.
REFERENCES
1.	Compilation of Air Pollutant Emission Factors, 4th Edition and Supplements, AP-42, U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, 1992.
2.	Crosswalk/Air Toxic Emission Factor (XATEF) Database, Version 1.2, U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park,
NC, 1992.
3.	Pope, A.A., PA. Cruse, and C.C. Most, Toxic Air Pollutant Emission Factors - A
Compilation for Selected Air Toxic Compounds and Sources, EPA-450/2-88-006a (NTIS
PB89-135644), U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, NC, October 1988.
4.	SPEC J ATE Database, Version 1.5, U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Research Triangle Park, NC, 1992.
5.	Cruse, P.A., Locating and Estimating Air Emissions from Sources of Benzene, EPA-450/4-84-
007q (NTIS PB88-196175), U.S. Environmental Protection Agency, Office of Air Quality
Planning and Standards, Research Triangle Park, NC, March 1988.
7

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6.	Locating and Estimating Air Emissions from Sources of Chromium, EPA-450/4-84-007g
(NTIS PB85-106474), U.S. Environmental Protection Agency, Office of Air Quality Planning
and Standards, Research Triangle Park, NC, July 1984.
7.	Vaught, Locating and Estimating Air Emissions from Sources of Formaldehyde (Revised),
EPA-450/4-91-012 (NTIS PB91-181842), U.S. Environmental Protection Agency, Office of
Air Quality Planning and Standards, Research Triangle Park, NC, March 1991.
8.	Locating and Estimating Air Emissions from Sources of Polycyclic Organic Matter (POM),
EPA-450/4-84-007p (NTIS PB88-149059), U.S. Environmental Protection Agency, Office of
Air Quality Planning and Standards, Research Triangle Park, NC, September 1987.
9.	. Sink, M.K., Control Technologies for Hazardous Air Pollutants, EPA/625/6-91/014 (NTIS
PB92-141373), U.S. Environmental Protection Agency, Center for Environmental Research
Information, Cincinnati, OH, June 1991.
10.	Brooks, G., Estimating Air Toxics Emissions from Coal and Oil Combustion Sources, EPA-
450/2-89-001 (NTIS PB89-194229), U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Research Triangle Park, NC, April 1989.
11.	Akers, D.J., R.L. Dospoy, C.E. Raleigh, and B. Toole-O'Neil, "The Effects of Coal Cleaning
on Predicting Air Toxics Emissions," presented at Electric Power Research Institute-sponsored
conference on "The Effects of Coal Quality on Power Plants," Charleston, SC, August 1994.
12.	Rizeq, R.G., D.W. Han sell, and W.R. Seeker, "Predictions of Metals Emissions and
Partitioning in Coal-Fired Combustion Systems," presented at Electric Power Research
Institute-sponsored conference on "Trace Element Transformations in Coal -Fired Power
Systems - Trace Elements Workshop," Scottsdale, AZ , April 1993.
13.	Debarred, J.L., and R.S. Dahlin, "A Performance Estimation Procedure For Utility Fly Ash
Precipitators," EPRI Project 629-5, Electric Power Research Institute, Palo Alto, CA, October
1986.
14.	Meij, R., "Trace Element Behavior in Coal-Fired Power Plants," presented at Electric Power
Research Institute-sponsored conference on "Trace Element Transformations in Coal -Fired
Power Systems — Trace Elements Workshop," Scottsdale, AZ, April 1993.
15.	Electric Utility Trace Substances Synthesis Report, EPRI TR-1046-14, Project 3081, Electric
Power Research Institute, Palo Alto, CA, November 1994.
8

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Table 1. Boiler Configurations Represented in EIA-767
Emission Control
Total j
Primary i
Total Heat Input

j:
| Fuel
Type
Boiler
PM
FGD
Plants:
Plants!
Boilers
10" 12 Btu*i
Percent
EPRI/DOE Tests
ICOAL
BIT
PC
ESP
FGD
391
39!
65
1,554!
7.83'
3?
iCOAL
BIT
PC
ESP
UN
247;
247 j
682
6,995 i
35-24 I
13:
iCOAL
BIT
PC
FF
FGD
3 I
3!
4
149!
0751
1!'
ICOAL
BIT
PC
FF
UN
71
7 j
22
160!
0.81 |
Ii
COAL
BIT
PC
MC
FGD
1
1 ;
3
22 j
0.11 j

COAL
BIT
PC
VS
FGD
3
3:
6
971
0.49 |
'
COAL
BIT
CY
ESP
FGD
2j
2j
4
88 ]
0.44;
1 i;
ICOAL
BIT
CY
ESP
UN
17 i
17!
30
388!
1,96!
6 :
COAL
BIT
CY
FF
UN
1!
1!
2
11 I
0.06!

COAL
LIG
PC
ESP
FGD
10 j
10;
14
636!
3.20 j
2;:
COAL
LIG
PC
ESP
UN
12!
12!
23
237!
1.20!
2'!
COAL
LIG
PC
FF
FGD
2 I
2-;
3
70!
0.35;

COAL
L!G
PC
FF
UN
1 i
1!
2
19!
0.10:

ICOAL
LIG
PC
VS
UN
1I
1:
1
26
0.13!

iCOAL j LIG jCY
ESP
FGD
1 ;
1
1
34 i
0.17;
„
jCOAL I LIG ICY
ESP
UN
4 I
4:
4
76 i
0.39;

COAL
LIG jCY
FF
FGD
1!
1 i
1
24;
0.12:

|COAL iSUB
PC
ESP !FGD
19'
19j
34
977;
4.92!
1'
iCOAL |SUB
PC
ESP I UN
101 !
101'
199
2,969'
14.961
2;:
iCOAL !SUB
PC
FF I FGD
121
12'
14
387!
1.95!
3!
COAL ISUB
PC
FF I UN
12:
12!
23
299 i
1.50!
5!
ICOAL [SUB
PC
VS jFGD
7!
7!
16
361 I
1.82;

COAL
SUB ICY
ESP
FGD
2:
2:
3
72!
0.36:

iCOAL ISUB jCY |ESP jUN
25|
25.
42
382;
1.92!
1;
|COAL !SUB
CY |MC jUN
1 !
1 i
1
4-
0.02!

iCOAL
SUB
CY jVS
FGD
1;
1'
1
28:
0.14;

! OIL
j DIS i
ESP
i FGD
59!
i 95!
7|
0.03 S
-
j.OIL
IDIS '
ESP
I UN
258!
661 |
129!
0.65!
3
'OIL
I DIS !
FF
Ifgd i
11 !
! 14|
1 :
0.00 j

!;OIL
IDIS !
FF
! UN !
10!
! 28 i
1i
0.00!

j;OIL
idis ;
MC
iFGD !
2 I
i ej
1 j
0,00 i

i OIL
i dis ;
MC
lUN :
21 |
! 36I
139 j
0.70;

jiOIL
IDIS j
UN
UN
155 i
! 3251
251
1.26!
15
;:OIL
bis
VS
;FGD
9,
14'
1;
O.OO:

SOIL
1 DIS j
VS
| UN
11
i 1;
0!
0,00

||OIL
RES !
ESP
Ifgd ,
1!
2!
0'
0.001

liOIL
Ires ;
ESP
| UN i
151
! 38|
279;
1.40:

SOIL
!res !
MC
i UN
12!
25;
196!
0.99!

SOIL
: RES !
UN
; UN
53,
; 91!
147;
0.74!
*
I-:
EGAS
; GAS ;
UN
!un
404'
10101
2,636 i
13 28
9 .
ilFuel Types
!iBIT Bituminous Coal
!;LIG Lignite Coal
iSUB Subbituminous Coal
|DIS Distillate Oil
jl RES Residual Oil
jjBoiler Types
j!PC Pulverized Coal Boiler
!!CY Cyclone Boiler

Emissions Control
ESP Electrostatic Precipitator
FF Fabric Filter
MC Multiclone
VS Venturi Scrubber
FGD Flue Gas Desulfurization (Wet or Dry Scrubber)
UN Uncontrolled
PM Particulate Matter
*1 Btu = 1.056 kJ

9

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Table 2. Summary of 1991 Emissions (tons,* except as noted)

Coal
Oil
Gas
All Fuel
Antimony
3.3


3.3
Arsenic
90.8
2.71
030
93.8
Beryllium
6.7
0.10
0.0066
6.9
Cadmium
0.7
0.64
0.053
1.4
Chlorine (HC1)
1136953
138037

115075.8
Chromium
102.3
2.56
1.45
106.3
Cobalt
232
18.20
0.11
41.5
Fluorine (HF)
33372.5


33372,5
Lead
68.5
3.44
0.53
72.5
Manganese
247.9
639
0.53
254.8
Mercury
58.7
0.26
0.0011
59.0
Nickel
86.2
354.12
3.16
443.5
Selenium
481.2
1.15
0.013
482.4
-




Benzene
30.5
0.63
1.05
32.2
Dioxin/Furan
1.6e-05
4.8e-06
1.6e-06
2.2e-05
Formaldehyde
24.1
11.50
44.81
80.4
PAH
1.4e-02
2.2e-03

1.7e-02
Toluene
11.2
5.69
13.18
30.1





Radionuclides (Ci)
21.2
0.06

21.3





Total (excluding radionuclides)
148303.3
1788.0
65.2
150156.5
Total (tpy) - less HC1/HF
1235.5
407.4
65.2
1708.1





No. of Boilers
1200
1336
1010
2090
No. of Plants
456
523
404
756
* 1 ton = 90? kg
10

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Table 3. Average Plant Emissions (pounds* per plant per year, except as noted)

Coal
Oil
Gas
Antimony
1429


Arsenic
396.75
45.96
03867
Beryllium
29.47
1.67
0.0084
Cadmium
3.10
10.86
0.0672
Chlorine (HC1)
498653.64
23459.12

Chromium
445.99
43.45
1.8492
Cobalt
101.18
309.19
0.1345
Fluorine (HF)
146109.24


Lead
297.94
58.49
0.6725
Manganese
1076.87
108.63
0.6725
Mercury
257.13
4.50
0.0013
Nickel
376.58
6016.60
4.0347
Selenium
2110.43
19.55
0.0168
-



Benzene
133.9
10.8
13000
Dioxin/Furan
7.0e-05
S.le-05
2.0e-06
Formaldehyde
105.7
195.5
57.2000
PAH
6.3e-02
3.7e-02

Toluene
493
96.8
16.8000




Radionuclides (Ci)
4.71e-02
5.76e-04





Total (excluding radionuclides)
650161-5
30381.1
83.1
Total (tpy) - less HCI/HF
5398.7
6922.0
83.1




No. of Primary Fuel Plants
450
102
283
No, of Primary Fuel Boilers
1189
241
660
* 1 pound = 0.454 kg
11

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jTable 4. Comparison of PI and EPA Total Emissions (tons'
per year)



i:
Fuel
Coal
Oil

1
1
Gas

f
HAP
PI
EPA |
PI: EPA
PI i
EPA I
PI:EPA 1
PI
EPA 1PI:EPA j
Antimony
31 NA*1
NA
na!
i
NA
NA !
[Arsenic
91
392 i
0 23
2.71
1.61
1.65!
0.301 NA
!
Beryllium
7
28 i
0,24
0.1 i
0.6 i
0,18 (
001
NA
;•
i Cadmium
1
31 I
0,02
0.6!
7.5!
0.091
0.05
NA

[Chlorine (HCI)
113,695
NA

1,380.61
NA
I
NA
NA
!•
(Chromium
102
3,384 !
0,031 2.6!
7.1!
0.36 i
1.451 NA

j Cobalt
23
NA1

18.21
NA
I
0.11
NA

1 Fluorine (HF)
33,373
NA1

NA
na!
I
NA
NA
(
Lead
69
348 j
0,20
3.4!
9.01
0.381
0.53
NA

Manganese
248
5,756 i
0.04
6.4 :
3.4 i
1.86 i
0.53
NA
Mercury
59
801
0,74
0 3 i
1.5!
0.181
0.001
NA
Nickel
86
2,647 |
0.03
354.1 I
153.3:
2.31 i
3.16
NA
I Selenium
481
2141
2.25
1.2:
4,5]
0.26;
0.01
NA


1Benzene
31
NA
0.6!
NA
f
1.05
NA

iDioxWFuran
1.61E-05
NA
4.77E-06 j
NA
I
1.58E-06
NA

Formaldehyde
24
NA

11.5 i
NA
I
44.81
NA

PAH
1.45E-02
135 i
1.07E-04
2.19E-03!
2.38!
9.18E-04 i
0
NA

Toluene
11
1,379 i
0.01
5.7 j
NA
i
13.18
35.14:
0.38

: Total HAP {less HCI/HF)
1,200
12,8791
0,09
390 i
1891
2.07:
7
0!

Total HCI/HF
147,068
NA

1,381 ;
NA
I
0
NA

* 1 ton = 907 kg









i" NA - Not Available









12

-------
MDMDT dtd T3 ni7o TECHNICAL REPORT DATA
JN it lvlrC Jb_ rt X r 1U 1 o (Please read Instructions on the reverse before completing)
—
1. REPORT NO. 2.
EP A/600/A-96/009
3. REC
4. TITLE AND SUBTITLE
Preliminary Inventory of Hazardous Air Pollutant
Emissions from Electric Utility Boilers in the
United States
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7, AUTHOR(S)
E. S, Ringler (SoRI) and J. W. Jones
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Southern Research Institute
P. 0. Box 13825
Research Triangle Park, North Carolina 27709-3825
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-0062, Tasks 0-011,
1-030, and 2-042
12, SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVEREO
Published paper; 3/93-7/95
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary NOTES APPCD project officer is Julian W. Jones. Mail Drop 62. 919/
541-2489. EPA/AWMA Emissions Inventory Conference, Research Triangle Park,
NC. 10/11-13/95.
16. abstract-jhe paper summarizes an EPA effort undertaken to develop an inventory of
hazardous air pollutant (HAP) emissions from fossil fuel combustion in electric
utility boilers. It examines several approaches toward developing and utilizing suit-
able emission factors, and presents a HAP inventory that is based on the most cur-
rent, comprehensive, and quality assured test data available. It presents analyses
that compare results and assess the significance of emissions estimates based on the
various approaches examined. The Clean Air Act Amendments (CAAA) dramatically
increased the number and type of sources subject to potential regulation. Title III of
the CAAA identifies 189 HAPs and indicates that many sources emitting these com-
pounds may ultimately be required to meet strict industry-specific Maximum Achie-
vable Control Technology (MACT) emissions standards. Fossil fuel (i.e., coal, oil,
natural gas) combustion generates a variety of organic HAPs and a number of toxic
metals (e.g., mercury, chromium, arsenic). Since utility boilers consume a large
proportion of the total fossil fuel used in the U. S., including most of the coal, they
may be a significant source of HAPs.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution Combustion
Inventories
Emission
Electric Utilities
Boilers
Fossil Fuels
Pollution Control
Stationary Sources
Hazardous Air Pollu-
tants (HAPs)
13B 21B
15E
14G
13 A
21D
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)'
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)

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