SEPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/2^81-079
November 1981
Air
Analysis of State
and Federal Sulfur Dioxide
Emission Regulations
for Combustion Sources
-------
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available - in limited quantities - from the Library Services Office (MD-35)
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711; or, for a fee, from the National Technical Information
Service, 5285 Port Royal Road, Springfield, Virginia 22161.
Publication No. EPA-450/2-81-079
-------
Acknowledgments
The authors wish to acknowledge the assistance made through review
and comment on drafts of this report by Mr. G. Tom Helms, Chief of the
Control Programs Operations Branch, EPA, and the staffs of the Air Branches,
EPA Regions I-X, and the Emission Standards and Engineering Division,
Research Triangle Park, North Carolina.
-------
Table of Contents
Page
1.0 Introduction 1
2.0 Summary 3
3.0 Regulation of Sulfur Dioxide Emissions from Combustion
of Fuels 23
3.1 Potential Emissions of Sulfur Dioxide from Fuel
Combustion 24
3.2 State Sulfur Dioxide Emission Regulations 25
3.3 New Source Performance Standards 31
4.0 Control of S0? Emissions 33
^ i
4.1 Natural Low Sulfur Fuels 33
4.2 Physical Coal Cleaning 33
4.3 Oil Cleaning 34
4.4 Flue Gas Desulfurization 34
5.0 Individual State's SIP Regulations 37
References 135
Appendix A A-l
Appendix B B-l
Appendix C C-l
-------
Section 1
INTRODUCTION
State Implementation Plan (SIP) regulations and Federal new source
performance standards (NSPS) pertaining to sulfur dioxide (S02) emissions
from fuel combustion have been compiled and summarized in this report.
The report is intended to be a general reference for industry, environ-
mental groups, and the general public. State regulations which were
submitted to the Environmental Protection Agency (EPA) and have been
approved as part of the SIP as of December 31, 1980 are included.
Appendix C also lists Federal Register notices of subsequent SIP
revisions that affect S02 emission requirements. Regulations applicable
specifically to incineration of solid waste or to processes which
include fuel combustion (cement kiln, lime calciner, etc.) were not
included in this compilation. The source categories to which the
regulations presented herein apply are broadly defined as indirect and
direct heat exchangers, and primarily steam generators (boilers).
This report will also serve as a quick reference for estimating S02
emission rates, assessing ranges of SOp control, and quantifying the
relative stringency of emission limits. It was developed to serve as a
starting point for broad control strategy evaluations and is not intended
to be a precise reference for individual compliance determinations.
Users are cautioned to contact the appropriate State and/or local air
pollution control agency and EPA Regional Office to verify the specific
SOp emission limit that is applicable to an individual source.
Sulfur dioxide regulations vary greatly among the States and even
within an individual State. They have become more specific to boiler
size, fuel type, and geographic location in recent years. This report
attempts to present this variety of emission limits in the simplest
tabular format possible. Also, we have attempted to present all the
important factors which influence the determination of compliance with
an emission limit. Compliance factors, such as actual or rated heat
input, test method, and length of time over which emissions are averaged
greatly influence the stringency of the limit.
-------
-------
Section 2
SUMMARY
When establishing sulfur dioxide (SOp) emission limits for fuel
combustion installations, each State's goal was attainment and mainte-
nance of the national ambient air quality standards (NAAQS) for S02-
The form, stringency, and applicability of regulations often depend upon
many parameters such as boiler age, fuel type, facility size and method
of determination (actual or design heat input), and geographical location.
These parameters are delineated by State in Table 1. In New York State,
for example, it is necessary to determine the location (city or county)
of the source, whether it is existing or new (construction after 3/15/73),
the size of the boiler as determined by its actual heat input rate
(Btu/hr), and the type of fuel burned (distillate oil, residual oil or
solid fuel). The regulation is a limit on the sulfur emission rate
(pounds sulfur/million Btu heat input) or the sulfur content of the
fuel. In the State of Washington, on the other hand, all fuel com-
bustion sources can emit no more than 1000 ppm SOp by volume. The
location, size or age of the facility, and type of fuel are not factors
in determining the emission limit.
For comparison purposes, the most representative SIP emission
limits for each State are presented in common units of pounds sulfur
dioxide per million Btu heat input (Ib SO^/ mm Btu) in Table 2 for
residual oil and Table 3 for solid fossil fuels. The most representa-
tive emission limits were taken as those that would be applicable over
the greatest portion of the State. (Section 5 of this report presents a
more detailed breakdown of SO^ limits applicable in different areas of
each State.) In some cases, an emission limit greater than that allowed
under the Federal new source performance standards (NSPS) is listed.
This higher limit is shown because it could apply to a wider variety of
sources than those defined in 40 CFR 60.40 and 60.40a. However, it
should be understood that the NSPS would supersede less stringent SIP
limits when a source falls under both regulations.
-------
Overall review of the information contained in Tables 2 and 3
reveals the following. First, within a specific State there is generally
little variation in allowable emissions due to facility size (mm Btu/hr).
This means that the majority of the States require the same degree of
SCL control for existing sources regardless of boiler size. Exceptions
to this rule are States such as Kentucky and Nevada, who specify limits
by equations. Second, emission limits for residual oil are more
stringent than those for coal in a number of States such as New Hampshire,
Maine, New York, Maryland, Pennsylvania, Georgia, Kentucky, Illinois,
Michigan, Minnesota, Ohio, Oklahoma, Texas, Iowa, Colorado, Utah, and
Hawaii. Other States do not differentiate between fuel types. Finally,
most existing source SO^ regulations are designed to be met by burning
naturally low sulfur fuel rather than requiring flue gas scrubbing
systems.
Figures 1 and 2 are histograms describing the numbers of States
requiring specific levels of S02 control. Figure 1 presents the limits
which would apply to a boiler burning 250 mm Btu/hr of residual oil.
Such a boiler burning oil with 3 percent sulfur would, for example, emit
about 3.2 Ibs SOp/mm Btu and meet the applicable emission limit in
only 9 States. Thus, oil with less than 3 percent sulfur is required to
meet most State standards.
Figure 2 presents the limits which would apply to a boiler burning
250 mm Btu/hr of coal. Since half of the States (25) have limits of
less than 3 Ibs S02/mm Btu, an average sulfur content of less than
2 percent would be required to meet the emission limit.
Approximate ranges of controlled and uncontrolled S02 emissions are
presented in Figure 3. This chart shows that bituminous coal with
3.0 percent average sulfur and a heating value of 11,500 Btu/hr would
emit about 5 Ibs S02/mm Btu and could meet (on a monthly or annual
-------
average) the S02 emission limit in about 5 States (Missouri, Illinois,
Kentucky, Iowa, and Indiana). This same coal could be physically
cleaned to reduce the emission rate (Ibs SO^/mm Btu) 24 to 50 percent.
On a long-term basis, it could then meet the standards of up to 19
States. Various flue gas desulfurization ;(FGD) systems could be used to
reduce SOg emissions 90 percent and allow that facility to meet the
standards of most States.
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Table 1. SIP SO- EMISSION LIMITATIONS IN THE UNITED STATES (BY EPA REGIONS)
(Applicable to fuel combustion sources)
EPA
Region
1
2
3
4
State
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
lew Jersey
New York
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Alabama
Attain
NAAQS for
so2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Fuel
Type
X
X
X
X
X
X
X
X
X
X
X
Emission
Rate
X
X
X
x •
X
X
X
X
X
X
X
X
Emission
Concentration
Heat Input
Actual
X
X
X
X
X
Design
X
X
X
X
X
X
X
X
X
X
Facility
Size
X
X
X
X
X
X
X
,. — .....
Date Construction Commenced
New
Source
X
X
X
X
Existing
Source
X
X
X
X
"I," ".. . 7
Classification
County
X
X
X
X
X
X
X
X
City
X
X
X
X
Area
X
X
X
X
X
X
X
X
en
a Excluding New Source Performance Standards criteria.
-------
Table 1. CONTINUED
EPA
Region
4
(cont,
5
6
State
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Arkansas
Attain
NAAQS for
so2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Fuel
Type
X
X
X
X
X
X
X
X
X
Emission
Rate
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Emission
Concentration
Heat Input
Actual
X
X
X
Design
X
X
X
X
X
X
X
X
X
X
Facility
Size
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Date Construction Commenced
New
Source
X
X
X
X
X
X
X
X
Existing
Source
X
X
X
X
X
X
X
X
X '
Classification
County
X
X
X
X
X
City
X
Area
X
X
X
X
a Excluding New Source Performance Standards criteria.
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Table 1. CONTINUED
EPA
Region
6
(cont
7
8
State
Louisiana
New Mexico
Oklahoma
Texas
Iowa
Kansas
Missouri
Nebraska
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Attain
NAAQS for
so2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Fuel
Type
X
X
X
X
X
X
Emission
Rate
X
X
X
X
X
X
X
X
X
X
X
X
X
Emission
Concentration
X
X
Heat Input
Actual
X
X
X
X
X
Design
X
X
X
X
X
X
X
X
X
X
Facility
Size
X
X
X
X
X
X
X
Date Construction Commenced
New
Source
X
X
X
X
X
X
X
Existing
Source
X
X
X
X
X
X
X
X
Classification
County
X
X
City
X
Area
X
co
Excluding New Source Performance Standards criteria.
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Table 1. CONCLUDED
EPA
Region
9
10
State
Arizona
California
Hawaii
Nevada
Alaska
Idaho
Oregon
Washington
Attain
NAAQS for
so2
X
X
X
X
X
X
X
X
Fuel
Type
X
X
X
X
X
Emission
Rate
X
X
X
X
Emission
Concentration
X
X
Heat Input
Actual
X
X
X
X
X
Design
X
X
X
X
Facility
Size
X
X
Date Construction Commenced
New
Source
X
X
X
Existing
Source
X
X
X
Classification
County
X
City
Area
X
* Excluding New Source Performance Standards criteria.
b Each Air Pollution Control District has individual criteria for fuel burning regulations. For summary purposes, "typical" criteria is specified.
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Table 2. REPRESENTATIVE STATE SULFUR DIOXIDE EMISSIONS LIMITATIONS FOR
FACILITIES BURNING #5 OR #6 FUEL OIL (Ibs. S02/MMBtu)
EPA
Region State
1 Connecticut: existing
new
Ma inea'J: exist ing
new
Massachusetts1*'0"3: existing
new
New Hampshire9"3: exist ing
new
Rhode Island3: existing
new
Vermont: existing
new
2 New Jersey *J:exi sting
new
New York3: existing
new
3 Del awarea'b'J: existing
new
Maryland9' 'J: existing
new
Pennsylvania*3: existing
new
VirginiaJ: existing
new
Washington, D.C.9"3: existing
new
West Virginia0: existing
new
Facil
10
0.55
0.55
2.7
2.7
1.1
1.1
2.1
2.1
1.1
1.1
3.48?
3.48a
1.05
1.05
2.1
2.1
1.8
1.8
N.A.J
N.A.d
4.0
4.0
2.64
2.64
1.05
1.05
1.6
1.6
ity Size
100
0.55
0.55
2.7
2.7
1.1
1.1
2.1
2.1
1.1
1.1
3.48?
3.48a
1.05
1.05
2.1
2.1
1.8
1.8
2.1
2.1
4.0
4.0
2.64
2.64
1.05
1.05
1.6
1.6
(MMBtu/hr.
250
0.55
0.55
2.7
2.7
1.1
1.1
2.1
2.1
1.1
1.1
3.48a
3.48a
1.05
1.05
2.1
2.1
1.8
1.8
2.1
2.1
4.0
4.0
2.64
2.64
1.05
1.05
1.6
1.6
heat
1,000
0.55
0.55
2.7
2.7
1.1
1.1
2.1
2.1
1.1
1.1
0.8
0.8
1.05
1.05
2.1
0.77
1.8
1.8
2.1
2.1
4.0
4.0
2.64
2.64
1.05
1.05
1.6
1.6
input)
10,000
0.55
0.55
2.7
2.7
1.1
1.1
2.1
2.1
1.1
1.1
0.8
0.8
1.05
1.05
2.1
0.77
1.8
1.8
2.1
2.1
4.0
4.0
2.64
2.64
1.05
1.05
1.6
1.6
(continued)
10
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Table 2. Continued
EPA
Region State
4 Alabama1: existing
new
Florida6: existing
new
Georgia 'J: existing
new
Kentucky : existing
new
Mississippi^: existing
new
North Caroling: existing
new
South Carolina5: existing
new
Tennessee6*3: existing
new
5 Illinois'3: existing
new
Indiana5: existing
new
Michigan13 : exi s t i ng
new
Minnesotae»J:exi sting
new
Ohi coexisting
new
Wisconsin6: existing
new
Faci
10
4.0
4.0
N-A.H
N.A.d
2.6
2.6
6.0.
N.A.d
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.d
1.0
6.0
6.0
1.7
1.7
2.0
2.0
N.A.d
1.6
N.A.d
N.A.d
lity Size
100
4.0
4.0
N.A d
N.A.d
3.1
3.1
4.49
1.17
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.d
1.0
6.0
6.0
1.7
1.7
2.0
2.0
1.6
1.6
N.A d
N.A.d
(MMBtu/hr.
250
4.0
4.0
N.A.JJ
N.A.d
3.1
3.1
4.0
0.8
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.d
1.0
6.0
6.0
1.7
1.7
2.0
2.0
1.6
1.6
N.A.J
N.A.d
heat
1,000
4.0
4.0
2.75
N.A.8
3.1
3.1
4.0.
N.A.h
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.d
1.0
6.0
6.0
1.1
1.1
2.0
2.0
1.6
1.6
N.A.d
0.8
input)
10,000
4.0
4.0
2.75
N.A.d
3.1
3.1
4.0.
N.A.h
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.d
1.0
6.0
6.0
1.1
1.1
2.0
2.0
1.6
1.6
N.A.d
0.8
(continued)
11
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Table 2. Continued
EPA
Region State
6 Arkansas : existing
new
Loui si ana1 'J: existing
new
New Mexico: existing
new
Oklahoma: existing
new
Texas6'1 ^: existing
new
7 lowar1: existing
new
Kansas-1: existing
new
Missouri3: existing
new
Nebraska3: existing
new
8 Colorado: existing
new
Montanac>J: existing
new
North Dakota : existing
new
South DakotaJ: existing
new
Utahc'j:exi sting
new
Wyomi ng : existing
new
Facil
10
N.A.Jj
N.A.d
4.6
4.6
N.A d
N.A.d
0.8
0.8
0.94
0.94
2.5
2.5
3.0°
3.0C
12.9
12.9
2.5
2.5
1.5
0.8
2.0
2.0
3.0
3.0
3.0
3.0
1.7
1.7
N.A.d
N.A.d
(continued)
12
ity Size
100
N.A A
N.A.d
4.6
4.6
N.A.d
N.A.d
0.8
0.8
0.94
0.94
2.5
2.5
3.0C
3.0C
12.9
12.9
2.5
2.5
1.5
0.8
2.0
2.0
3.0
3.0
3.0
3.0
1.7
1.7
N.A d
N.A.d
CMMBtu/hr
250
N.A d
N.A.d
4.6
4.6
N.A d
N.A.d
0.8
0.8
0.94
0.94
2.5
2.5
3.0C
3.0C
12.9
12.9
2.5
2.5
1.5
0.3
2.0
2.0
3.0
3.0
3.0
3.0
1.7
1.7
N.A d
N.A.d
. heat
1,000
N.A d
N.A.d
4.6
4.6
N.A.d
N.A.d
0.8
0.8
0.94
0.94
2.5
2.5
3-°c
3.0C
12.9
12.9
2.5
2.5
0.8
0.3
2.0
2.0
3.0
3.0
3.0
3.0
1.7
1.7
N.A.d
0.8
input)
10,000
N.A.5
N.A.d
4.6
4.6
N.A d
N.A.d
0.8
0.8
0.94
0.94
2.5
2.5
s.oj;
3.0C
12.9
12.9
2.5
2.5
0.8
0.3
2.0
2.0
3.0
3.0
3.0
3.0
1.7
1.7
N.A.d
0.8
-------
Table 2. Continued
EPA
Region
9
10
State
Arizona: existing
new
California3'5: existing
new
Hawaiia>J:existing
new
Nevada0'^: existing
new
Alaska1 J: existing
new
Idahoa>j: existing
new
Oregon3*3: existing
new
Washi ngton1 **: exi sti ng
new
Facility
10
2.2
0.8
0.53
0.53
2.1
2.1
1.4
1.4
1.14
1.14
1.35
1.35
1.85
1.85
2.29
2.29
Size
100
2.2
0.8
0.53
0.53
2.1
2.1
1.4
1.4
1.14
1.14
1.85
1.85
1.85
1.85
2.29
2.29
(MMBtu/hr.
250
2.2
0.3
0.53
0.53
2.1
2.1
0.8
0.8
1.14
1.14
1.85
1.85
1.85
1.85
2.29
2.29
heat
1,000
2.2
0.3
0.53
0.53
2.1
2.1
0.8
0.8
1.14
1.14
1.85
1.85
1.85
1.85
2.29
2.29
input)
10,000
2.2
0.3
0.53
0.53
2.1
2.1
0.8
0.8
1.14
1.14
1.85
1.85
1.85
1.85
2.29
2.29
Emissions limitation was expressed in percent sulfur content of the fuel. Conversion
to Ibs. SO?/MMBtu was based on the assumptions of 100 percent conversion of sulfur
to sulfur aioxide, and a heating value of 19,000 Btu/lb (residual oil). The
following equation calculates the equivalent emission rate:
Emission Rate (Ibs. S02/MMBtu) = (
°
Heatngae (Btu/lb
)
X %S <2 lbs' S02/lb*
Emissions limitations were not expressed for the entire state. The median value
was selected for comparison.
c Emissions limitation was expressed in lbs. S/MMBtu. The following equation
calculates the equivalent emission rate:
Emission Rate (lbs. S02/MMBtu) = 2 X (lbs. S/MMBtu)
Refers to "Not Applicable" for comparison purposes. Either emissions were not
regulated in that state or other reason specified.
13
-------
Table 2. Concluded
e Emissions limitations were for individual sources and counties. The value shown
represents only limitations which apply to the entire state.
The state regulation limits both fuel sulfur content and the S02 emission rate
depending on stack height. However, only the limits on fuel suifur content are
included" in the SIP-
^ Emissions limitations are based on effective stack height for entire plant
(equation).
Emissions limitations are based on federal regulations. See Appendix A and
Appendix B.
t
Emissions limitation was expressed in parts per million (ppm). Conversion to
Ibs. SOp/MMBtu was based on the assumptions that F factors (dry basis) were
9,820 d5cf/MMBtu (coal) and 9,220 dscf/MMBtu (oil), and a 6 percent oxygen
content in the flue gas. The following equations calculate the equivalent
emission rate at standard temperature (20 C or 68 F) and pressure (760 mm Hg
or 29.92 in. Hg):
C = 1.660 X 10"7 (X ppm)
r _ r r f 20.9
I
•- " 'd ]_ 20.9-percent
where: E = pollutant emissions (Ibs. S02/MMBtu)
C = pollutant concentration (Ibsf S02/dscf)
F. = dry basis F factor, which is the ratio of the volume of dry
flue gases generated to the calorific value of the fuel
combusted.
J New source performance standards (40 CFR 60.40 and 60.40a) supersede less
stringent State emission limits when applicable to a new combustion source.
14
-------
Table 3. REPRESENTATIVE STATE SULFUR DIOXIDE EMISSIONS LIMITATIONS FOR
FACILITIES BURNING SOLID FOSSIL FUEL (Ibs. SOg/MMBtu)
EPA
Region State
1 Connecticut: existing
new
Mainea'4 existing
new
Massachusetts *c: existing
new
New Hampshi re J : exi sti nga
new
Rhode Island: existing
new
Vermont: existing
new
2 New Jersey : existing
new
New York3: existing
new
3 Del aware3 ^ existing
new
Mary! and '^existing
new
Pennsylvania : existing
new
Virginiaf3 : existing
new
Washington, D.C.a'J: existing
new
West Virginia3: existing
new
Facility
10
0.55
0.55
4.13
4.13
1.1
1.1
5.3
3.0
1.1
1.1
3.3
3,3
0.3
0.3
N.A.J
N.A.d
1.65
1.65
N.A-H
N.A.d
4.8
4.8
2.64
2.64
1.-65
1,65 '
1.6
1.6
(continued)
Size
100
0.55
0.55
4.13
4.13
1.1
1.1
5.3
3.0
1.1
1.1
3,3
3.3
0.3
0.3
4*13
4.13
1.65
1.65
3.5
3.5
4.8
4.8
2.64
2.64
1.65
1»65
1.6
1.6
(MMBtu/hr.
250
0.55
0.55
4.13
4.13
1.1
1.1
5.3
3.0
1.1
1.1
3.3
3.3
0.3
0.3
4.13
4.13
1.65
1.65
3.5
3.5
4.8
4.8
2.64
2.64
1.65
1,65
1.6
1.6
heat
1,000
0.55
0.55
4.13
4.13
1.1
1.1
5.3
3.0
1.1
1.1
1.2
1.2
0.3
0.3
4.13
1.04
1.65
1,65
3.5
3.5
4.8
4.8
2.64
2.64
1.65
1.65
1.6
1.6
input)
10,000
0.55
0.55
4.13
4.13
1.1
1.1
5.3
3.0
1.1
1.1
1.2
1.2
0.3
0.3
4,13
1.04
1.65
1.65
3.5
3.5
4.8
4.8
2.64
2.64
1.65
1.65
1.6
1.6
15
-------
Table 3. Continued
EPA
Region State
4 AlabamaJ: existing
new
Florida6: existing
new
Georgia existing
new
Kentucky; existing
new
Mississippi13 : existing
new
North Carol inaj: existing
new
South Carol inaj: existing
new
Tennesseee'J:exi sting
new
5 Illinois: existing
new
IndianaJ: existing
new
Mi chiganj: existing
new
Q -i
Minnesota' '.existing
new
Ohio '3:exi sting
new
Wisconsin9: existing
new
/ j
Facility Size
10
4.0
4.0
N.A.J
N.A.d
4.35
4.35
9.0
5.0
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
6.8
1.8
6.0
6.0
2.4
2.4
4.0
4.0
3.6
3.6
N.A d
N.A.d
100
4.0
4.0
N.A.J
N.A.d
5.22
5.22
6.73
1.8
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
6.8
1.8
6.0
6.0
2.4
2.4
4.0
4.0
3.6
3.6
N.A d
N.A.d
(MMBtu/hr.
250
4.0
4.0
N.A.d
N.A.d
5.22
5.22
6.0
1.20
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
6.8
1.8
6.0
6.0
2.4
2.4
4.0
4.0
3.6
3.6
N.A d
N.A.d
heat
1,000
4.0
4.0
6.12
N.A.fl
5.22
5.22
6.0
0.65
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.9
1.2
6.0
6.0
1.6
1.6
4.0
4.0
3.6
3.6
N.A.d
1.2
input)
10,000
4.0
4.0
6. 12
N.A.fl
5.22
5.22
6.0
0.23
N.A.d
4.8
2.3
2.3
3.5
3.5
5.0
5.0
N.A.9
1.2
6.0
6.0
1.6
1.6
4.0
4.0
3.6
3.6
N.A.d
1.2
16
-------
Table 3. Continued
EPA
Region State
6 Arkansas : existing
new
Louisiana 'J: exist ing
new
New Mexico: existing
new
Oklahoma: existing
new
Texas * : existing
new
7 Iowa: existing
new
Kansas1: existing
new
t
Missouri"3: existing
new
Nebraska-3: exist ing
new
8 Colorado: existing
new
Montana6"3: exi sting
new
North Dakota^: exi sting
new
South Dakota"3: existing
new
Utahc'J: exi sting
new
Wyoming: existing
new
facility Size
10
N. A. j
N.A.d
4.6
4.6
N.A.d
N.A.d
1.2
1.2
3.0
3.0
6.0
6.0
3.0^
3.0C
12.9
12.9
2.5
2.5
1.8
1.2
2.0
2.0
3.0
3.0
3.0
3.0
2.0
2.0
N.A.d
N.A.d
100
N.A.J
N.A.d
4.6
4.6
N.A.d
N.A.d
1.2
1.2
3.0
3.0
6.0
6.0
3.0^
3.0C
12.9
12.9
2.5
2.5
1.8
1.2
2.0
2.0
3.0
3.0
3.0
3.0
2.0
2.0
N.A.J
N.A.d
(MMBtu/hr
250
N. A. j
N.A.d
4.6
4.6
N.A.J
N.A.d
1.2
1.2
3.0
3.0
6.0
6.0
3'°c
3.0C
12.9
12.9
2.5
2.5
1.8
1.2
2.0
2.0
3.0
3.0
3.0
3.0
2.0
2.0
N.A.J
N.A.d
M
. heat
1,000
N. A. j
N.A.d
4.6
4.6
1.2
1.2
1.2
1.2
3.0
3.0
6.0.
N.A.d
3.0J;
3.0C
12.9
12.9
2.5
2.5
1.2
0.4
2.0
2.0
3.0
3.0
3.0
3.0
2.0
2.0
1.2
0.2
Input)
10,000
N.A d
N.A.d
4.6
4.6
1.2
1.2
1.2
1.2
3.0
3.0
6.0.
N.A.d
3'°c
3.0C
12.9
12.9
2.5
2.5
1.2
0.4
2.0
2.0
3.0
3.0
3.0
3.0
2.0
2.0
0.3
0.2
(continued)
17
-------
Table 3. Continued
EPA
Region
9
10
State
Arizona: existing
new
California3' : existing
new
Hawaiia'j:existing
new
Nevada0 : existing
new
Alaska1: existing
new
Waho_a'J: existing
new
Oregon "^existing
new
Washington1*3 : exi sti ng
new
Facility Size
10
1.0
0.8
0,83
0;83
3.3
3.3
1.4
1.4
1.14
1.14
1-.65
1.65
1.65
1.65
2.29
2.29
100
1.0
0.8
0.83
0,83
3.3
3.3
1.4
1.4
1.14
1.14
1.65
1.65
1.65
1.65
2.29
2.29
(MMBtu/hr.
250
1.0
0.8
0.83
0.83
3.3
3.3
1.2
1.2
1.14
1.14
1.65
1.65
1.65
1.65
2.29
2.29
heat
1,000
1.0
0.8
0.83
0.83
3,3
3.3
1.2
1.2
1.14
1.14
1.65
1.65
1.65
1.65
2.29
2.29
input)
10,000
1.0
0.8
0.83
0.83
3.3
3,3
1.2
1.2
1.14
1.14
1.65
1.65
1.65
1.65
2.29
2.29
Emissions limitation was expressed in percent sulfur content of the fuel. Conversion
to Ibs. S02/MMBtu was based on the assumptions of 95 percent conversion of sulfur
to sulfur aioxide, and a heating value of 11,500 Btu/lb (coal). The following
equation calculates the equivalent emission rate:
Emission Rate (Ibs. S02/MMBtu) = .95^^°°^°°° (Btu/lb)) X %S <2 lbs' S02/1b' S>
Emissions limitations were not expressed for the entire state. The median value
was selected for comparison.
c Emissions limitation was expressed in Ibs. S/MMBtu. The following equation
calculates the equivalent emission rate:
Emission Rate (Ibs. S02/MMBtu) = 2 X (Ibs. S/MMBtu)
Refers to "Not Applicable" for comparison purposes. Either emissions were not
regulated in that state or other reason specified.
18
-------
Table 3. Concluded
e Emissions limitations were for individual sources and counties. The value shown
represents only limitations which apply to the entire state.
* The state regulation limits both fuel sulfur content and the S02 emission rate
depending on stack height. However, only the limits on fuel sulfur content are
included in the SIP
9 Emissions limitations are based on effective stack height for entire plant
(equation).
Emissions limitations are based on federal regulations. See Appendix A and
Appendix B.
1 Emissions limitation was expressed in parts per million (ppm). Conversion to
Ibs. SO«/MMBtu was based on the assumptions that F factors (dry basis) were
9,820 dScf/MMBtu (coal) and 9,220 dscf/MMBtu (oil), and a 6 percent oxygen
content in the flue gas. The following eauations calculate the equivalent
emission rate at standard temperature (20 C or 68 F) and pressure (760 mm Hg
or 29.92 in. Hg):
C = 1.660 X 10"7 (X ppm)
Fd
f 20.9 ~\
I 20.9-percent 02J
where: E = pollutant emissions (Ibs. S02/MMBtu)
C = pollutant concentration (Ibsf S02/dscf)
Fd = dry basis F factor, which is the ratio of the volume of dry
flue gases generated to the calorific value of the fuel
combusted.
New source performance standards (40 CFR 60.40 and 60.40a) supersede less
stringent state emission limits when applicable to a new combustion source.
19
-------
20 r
°'5
2.0
3-° 4.0 5.0 6.0
Emission Rate, Ib. SQt/VM Btu
13.0
a
<0
° 10
IL
§
z
5
0 I
-
.
r
I * ' ' I
0.5 in
-
'
•) n
.« . /
'
'
11 *
\
'I ' SS,,,,
4-0 5.0
Emission Rate , Ib. SO../MM Btu
6.0
7.0
13.0
Figure 2.
All«abl. SOZ Emission Rate for an Existing
Btu/hr. Coal Fired Boiler.
20
-------
Uncontrolled Emissions
T3
n>
in
o
-t>
to
o
o
o
Physical Coal Cleaning (24%-50% reduction)
Dry Scrubbing FGD (75%-85% reduction)
111
Limestone FGD (70%-90% reduction)
Sodium, Double Alkali Lime, ,QM ocar . _ .
Limestone with Adipic Acid FGD 190%'95% Deduction)
0
Emission Rate, Ib S02/MM Btu
Figure 3. Ranges of S0? emission rates for a boiler fueled with
bituminous cOal: 11,500 Btu/lb., 3.0% S.
-------
22
-------
Section 3
REGULATION OF SULFUR DIOXIDE EMISSIONS FROM COMBUSTION OF FUELS
The Clean Air Act Amendments of 1970 (CAA) required each State to
prepare a plan indicating how the National Ambient Air Quality Standards
(NAAQS) for particulates, sulfur dioxide, oxides of nitrogen, and
carbon monoxide would be attained and/or maintained. States adopted
regulations limiting sulfur dioxide emissions from fuel combustion in
response to this requirement. These limits took the form of limits on
the percent sulfur (by weight) in fuels burned, pounds sulfur or sulfur
dioxide emitted per million (mm) Btu of heat input to the furnace, and
limits on the parts per million (ppm) concentration of sulfur dioxide in
the flue gas.
Individual State Implementation Plans have been revised several
times since 1970. These revisions have resulted in regulations becoming
more site-specific (dependent on the location of the source by county or
municipality rather than a Statewide regulation). Some States have
been able to show that the original limits on fuel sulfur content
adopted were more stringent than necessary to attain the NAAQS and are
in the process of relaxing those regulations.
The CAA required EPA to develop standards of performance for new
stationary sources also. In response to this requirement, EPA has
adopted "Standards of Performance for Fossil-Fuel Fired Steam Generators
for Which Construction is Commenced After August 17, 1971" and "Standards
of Performance for Electric Utility Steam Generating Units for Which
Construction is Commenced After September 18, 1978."
23
-------
3.1 - POTENTIAL EMISSIONS OF SULFUR DIOXIDE FROM FUEL COMBUSTION
Sulfur dioxide emissions from combustion of fuels are proportional
to the amount of sulfur in the fuel. In the case of fuel oil, it is
assumed that all the sulfur in the oil is oxidized during the combustion
process and emitted as sulfur dioxide. Estimates of SO,, emission
rates from fuel oil combustion can generally be made using the following
equations.
Residual oil - Ibs S02/mm Btu = 1.05 x % S in fuel
Distillate oil - Ibs S02/mm Btu = 1.0 x % S in fuel
These equations are based on the general assumptions that residual oils
have an approximate heating value of 150,000 Btu/gallon and distillate
2
oils have a value of 140,000 Btu/gallon. Thus, combustion of a 2.3
percent sulfur residual oil would have a resultant emission rate of
approximately 2.4 Ibs S02/mm Btu of heat input.
For the combustion of coal, about five percent of the coal's
sulfur remains in the bottom ash and thus 95 percent is emitted as
2
sulfur dioxide. To estimate the emission rate in Ibs SO^/mm Btu, one
only needs to know the percent sulfur and the heating value in Btu/lb.
The following procedure can then be used for estimation:
Ibs S02/mm Btu = CF x % S in coal
Where CF is -
Btu/lb CF
10,000
10,500
11,000
11,500
12,000
12,500
1.9
1.81
1.73
1.65
1.58
1.52
Thus, a coal of 3 percent sulfur content and a heating value of 11,500
Btu/lb would have an approximate SO^ emission rate of 5 Ibs/mm Btu.
24
-------
The normal range of sulfur dioxide emissions (Ib SCL/mm Btu) is
presented in Table 4. The range of emission rates was maximized by
assuming the lowest sulfur fuel had the highest heating value and the
highest sulfur fuel had the lowest heating value. There is no direct
correlation of sulfur content and heating value in nature, however.
It can be seen that a low sulfur (.01 percent) distillate oil could
yield as little of 0.01 Ib SOp/mm Btu of fuel burned while a high sulfur
(6.1 percent) bituminous coal could yield as much as 12 Ib SO^/mm Btu.
Although wood and bark have very low sulfur contents, they also have
low heating values; therefore, S02 emissions fall in the same range as
those from #1 or #2 fuel oil.
3.2 - STATE SULFUR DIOXIDE EMISSION REGULATIONS
Several approaches to regulating S02 emissions from fuel combustion
have been adopted by States in order to attain and maintain the NAAQS. The
regulations applicable in each State are delineated in Section 5 along with
notes on procedures such as test methods, averaging time, monitoring
and reporting requirements used to determine compliance.
Continuous monitoring of SO^ emissions is generally not required by
the SIPs. Some States require routine monitoring of fuel characteristics.
Often, however, monitoring and reporting requirements are left to the
discretion of the director of the air pollution control program.
American Society for Testing Materials (ASTM) methods are usually
specified for determining fuel sulfur content and heating value of the
fuel. Most States selected EPA Method 6 as the source test method for
determining flue gas emission concentrations. About 18 States left
specification of test methods to the director of the air pollution
control program.
The averaging time, or time period over which average S02 emissions
must fall below the allowable limit, is seldom specified in the State
regulations. Compliance as determined by stack test procedures is basically
instantaneous. That is, the average emission rate during the 1-3 hour stack
25
-------
Table 4
Range of Sulfur Contents, Heating Values and
Potential Sulfur Dioxide Emission Rates for Typical Fuels
Fuel
Pipeline Natural Gas
Wood - Typical
Bark - Typical
Distillate Oil3
#1
#2
#4
Residual Oil3
#5
#6
3
Anthracite Coal
3
Bituminous Coal
3
Subbituminous Coal
3
Lignite Coal
% Sulfur
(by weight)
Negligible
0.02
0.02
0.01-0.5
0.05-1.0
0.2-2.0
0.5-3.0
0.7-3.5
0.6-0.8
0.7-6.1
0.3-0.6
0.4-0.9
Heating Value
(Btu/lb as burned)
-
4560
4370
19,670-19,860
19,170-19,750
18,280-19,400
18,100-19,020
17,410-18,990
11,925-12,925
9,700-14,715
8,320-11,340
6,500-9,700
S02 Emissions
fb/mm Btu
-
0.1
0.1
0.01-0.5
0.05-1.0
0.2-2
0.5-3
0.7-4
0.9-1
0.9-12
0.5-1
0.8-3
26
-------
test must fall below the allowable limit. Averaging time is not,
generally, important when oil is burned because the sulfur content of
a given supply of oil is nearly constant. Averaging time becomes
•important, however, when burning coal because the sulfur content, even
from a single mine, may vary significantly. Therefore, when a coal is
said to have 2 percent sulfur content, that is usually the average of
many samples taken over the period of a month or even longer. This coal
could probably meet an emission limit of 3 Ib SCL/ mm Btu if compliance
is determined by averaging several emission measurements taken over a
30-day period. If emission measurements taken over a 24-hour period are
averaged, however, the emission rate could be higher if the sulfur
content of the coal burned during the period of testing was above the
long-term average.
A review of Section 5 indicates that State SOo emission regulations
generally limit the amount of S02 which can be emitted per million Btu heat
input to the furnace (Ib SOg/mm Btu) or the sulfur content of the fuels
which can be burned. The following paragraphs give examples of parameters
in different States that affect the stringency of emission limits
applicable to an individual source.
The New York State SIP, for example, contains very detailed limits on
fuel sulfur content. To determine the limit applicable to a particular
source, it is necessary to first know its location (county or municipality).
The total heat (Btu/hr) actually being burned in all furnaces at the
facility is the next important factor. A facility with 10 mm Btu/hr or less
is not regulated. In some areas of the State different limits apply to
facilities with total heat input greater than 250 mm Btu/hr. Limits are
different for existing sources (constructed before 3/15/73) and new
sources (constructed after 3/15/73), and for oil and solid fuel. Com-
pliance with the sulfur-in-fuel limits is determined by stack testing
(EPA Method 6) and fuel analysis to determine sulfur and ash content,
heating value and specific gravity (oil). The gross heat content and
27
-------
ash content of the fuel burned on a weekly basis must be monitored for
all facilities with a total heat input greater than 250 mm Btu/hr.
Continuous monitoring of stack S02 emissions is required for new
facilities with heat input greater than 250 mm Btu/hr.
Pennsylvania regulations limit sulfur-in-fuel and S02 emission rate
(Ib/mm Btu) depending on the location, the design fuel burning capacity
of each furnace and the type of fuel burned. The equation illustrated in
Figure 4 is applicable only to furnaces with heat input capacity greater
than or equal to 50 mm Btu/hr but less than 2000 mm Btu/hr and located in
the Allegheny County, Beaver Valley, Monongahela Valley air basin. The
allowable S02 emission rate for furnaces burning solid fossil fuels varies
with averaging time. For example, the measured emission rate must always
fall below 4.8 Ib S02/mm Btu in areas I and II (Section 5). Also, the average
of all readings for one day (24-hour period) must fall below 4.0 Ib/mm Btu
(except for two days per month) and the emission average over 30 days
must fall below 3.7 Ib/mm Btu.
In Virginia and Nevada the emission limits (Ibs S02/hr) are based on
equations (Figures 5 and 9) which are functions of the actual heat input
to a single furnace. Compliance is determined in Virginia by stack
testing using EPA Method 6 or another State-approved procedure (3 runs)
and in Nevada by stack testing using a method specified by the State in
the operating permit (2 runs).
Georgia limits the sulfur content of the fuel burned to <2.5 percent
for furnaces actually burning less than 100 mm Btu/hr and <3.0 percent
for furnaces burning 100 mm Btu/hr or greater of fuel. It also limits
the S02 emission rate (Ib S02/mm Btu) based on equations (Figures 6, 7,
and 8) which are functions of the furnace exhaust stack height. The
limits based on stack height are not part of the Georgia SIP, however.3
The EPA Region IV office "determined that the sulfur-in-fuel limit. . .
is sufficient standing alone to assure attainment and maintenance of
the national air quality standards for S02" (41 FR 35185, August 20, 1976).
Also, application of the stack height rules must be in accordance with
"Legal Interpretation and Guideline to Implementation of Recent Court
Decisions on the Subject of Stack Height Increase as a Means of Meeting
Federal Ambient Air Quality Standards" (41 FR 7450, February 18, 1976).
28
-------
<£>
O
3
O_
MOO
•900
1600
1400
1200
1000
no
coo
400
200
Equation: A • 1.7 E~0'14
A • Allovable SO, trillions (tb./lO* (tu)
E • Heat Input to the Coufcustlon Unit
(loStu/hr.)
0.55
0.60
0.65
0.70
0.75
0.80
o.es O.M
Allowable S02 Emissions, lb./106 Btu
0.95
1.0
Figure 4. Determination of SCL Emission Rate by Heat Input
VIRGINIA
u
<0
a.
1500
1400
1200
3 ""
1 800
400
200
to
01
Region 7 (liquid gaseous fuel
2.64 I for Regions :.2.3.4.5.« (ell *el t»es)
1.52 1C for Itoglon 7 (tolM fuel)
1.06 K for Region 7 (liquid *•«
fuel)
AlloMbleSO. Wiilom (Ife./hr.) . ,
Actwl Heat Input »t Munu CwKlt; (">
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800
Allowable S02 Emissions, Ib./hr.
Figure 5. Determination of SO- Emission Rate by Heat Input.
ro
•vo
GEORGIA
01
•r—
(U
o
•M
in
Heit Input < 10,000 i 106 Itu/hr.
it Input > 10,000 > 10° etu/hr.
Equations: E • 2.4 S for Heat Input < 10.000 « 10* >t"/hp-
E • 3.6 5 for Heat Input ?10.000 > Id6 8tu/hr.
E - Allwable SO, Ekisilons (Ib./hr.)
S - Stack Height(ft.)
i . i • I • I • 1
100
150
200
250
300
350
Allowable S0? Emissions, Ib./hr.
Figure 6. Determination of S02 Emission Rate for Stack Heights ^90 ft.
GEORGIA
300 r-
250
200
Heat Input <10.000 i ID6 etu/hr.
(U
:c
100
50
Heat Input ilO.OOO > 10*~liu/hr.
Equation: E • BOO fjgj)' for Meat Input <10.000 i 10* K«/hr.
E - 12,000 (j)* for Heat Input > 10.000 i lo'llu/tr.
E - Alienable SO, E*1»1om (Ib./nr.)
S • Stack Height (ft.)
2000
6000
8000 10.000 12.000
Allowable SO- Emissions, Ib./hr. -
Figure 7. Determination of S02 Emission Rate for Stack Weights
> 90 ft. but < 300 ft.
-------
GEORGIA
1000
900
000
700
«»
500
400
300
Heat Input •clO.OOO Btu,
Equations: E • 8000 (^55) for Heat Input <10.000 i 10° Itu/hr.
£ • 12.000 f^)* for Heat Input >10.000 > 10* Itu/hr.
E - Allowable SO, Emissions (Ib./hr.)
S • Stick Height (ft.)
40.000 50-°00 60.000
ZO.OOO - 40.000 - 60.000 - 80.000 ' lOO.OOO'
Allowable SOp Emissions, Ib./hr.
Figure 8. Determination of SO,, Emission Rate for Stack Heights >300 ft.
a.
c
3
4->
O
NEVADA
1000
900
800
700
600
$00
400
300
200
100
Equations: 1 • 0.7 « for Act ml Hut Input <250 i 106 Itli/hr. (ill furl type:)
T • 0.6 X for Actu.1 h>«t Inpvt > 250 > 10* Btu/hr. (solid fwl)
T - 0.4 X for ActMl Hcit Input >2SO i 10s Btu /hr. (Hqu)d fuel)
T - Allwible S EBl»tomJlb./nr.)
X • Actwl Hut Input (10s Itu/hr.)
HNt Input >?50 « 10* Btu/hr. (liquid fuel
Neit Input »2$0 > 106 Btu/hr.(toTId fuel)
at Input <2SO i 106 Btu/hr. (ill fuel types)
SO 100 150 200 2SO 300 ISO 400 450
Allowable S Emissions, Ib./hr.
550 600
Figure 9. Determination of Sulfur Emission Rate by Actual Heat Input.
CO
o
Equations: T - IJ.0284
T • 8.0189 j
KENTUCKY
co a»
TJ
Ol
Fuel)
(u,u1d «n
-------
Allowable emission rates (lb SOp/mm Btu) in Kentucky vary with the
location (county), facility size (total plant heat input) and type fuel
(solid or liquid). The emission rates are determined by equations
(Figures 10 and 11) for facilities larger than 10 mm Btu/hr and smaller
than 250 mm Btu/hr. Compliance is determined by stack testing using EPA
Method 6.
S02 emission concentrations in Louisiana, the State of Washington,
and Alaska are limited to <2000 ppm, <1000 ppm, and <500 ppm, respectively.
These limits apply in all locations, to all size furnaces and all fuels
in each case.
3.3 - NEW SOURCE PERFORMANCE STANDARDS
EPA has promulgated standards of performance for the following
two classes of steam generating units:
Affected Facility
Electric Utility Steam Generating
Units Capable of Combusting
>250 mm Btu/hr (which commenced
construction after 9/18/78)
Standard for Sulfur Dioxide
(a) Solid fuels or solid-derived fuels:
(i) Continental States: <1.2
lb S02/mm Btu and <10 percent
of the potential combustion
concentration of S02 or <30
percent of the potential com-
bustion concentration when emissions
are <0.60 lb S02/mm Btu.
(ii) Noncontinental States and
Territories: <1.2 lb S02/mm Btu
(b) Liquid or Gaseous Fuels:
(i) Continental States: <0.80
Ib S02/mm Btu and <10 percent
of the potential combustion
concentration or 100 percent of
the potential combustion con-
centration when emissions are
<0.20 lb S02/mm Btu.
31
-------
(ii) Noncontinental States and
Territories: <0.80 Ib S09/mm Btu
L- •
(c) Solid Solvent Refined Coal (SRC-I):
<1.2 Ib S02/mni Btu and <15 percent
of the potential combustion
concentration of S02.
(d) 100 percent anthracite coal, and
resource recovery facilities:
<1.2 Ib S02/mm Btu.
Fossil-Fuel Fired Steam Generating (a) Liquid fossil-fuel or liquid
Units >250 mm Btu/hr (which commenced fossil-fuel and wood residue:
construction after 8/17/71) <0.80 Ib S02/mm Btu.
(b) Solid fossil-fuel or solid fossil-
fuel and wood residue: <1.2 Ib
S02/mm Btu.
Subpart Da was designed to update (and supersede) Subpart D for
electric utility boilers in accordance with the 1977 Amendments to the CAA.
Compliance with this regulation is generally determined by continuously
monitoring S0? concentrations in the flue gas before and after a flue
gas desulfurization system (FGD) and calculating the arithmetic average
of all hourly emission rates (Ib S02/mm Btu) for 30 successive days of
normal operation.
Subpart D is applicable to all fossil-fuel fired steam generating
units and all fossil-fuel and wood residue fired steam generating units
capable of burning more than 250 mm Btu/hr of fuel, irrespective of the
use of the steam produced. Compliance with the emission limit is
determined by continuously monitoring the flue gas and calculating an
arithmetic average of the S02 emission rate (Ib S02/mm Btu) for three
contiguous one-hour periods.
Appendix A is a copy of sections of 40 CFR 60 pertaining to these
NSPS.
32
-------
Section 4
CONTROL OF SOg EMISSIONS
4.1 - NATURAL LOW SULFUR FUELS
State SOp emission limits have generally been met by burning fuels
with sulfur contents low enough to avoid exceeding the standard. The
demonstrated coal reserve base of the United States on January 1, 1974
was estimated at 437 billion tons. About half of this reserve base
can be assumed to be recoverable. About 46 percent of the reserve base
has an average sulfur content of 1 percent or less which could meet an
S02 emission limit of 1.5 Ib/mm Btu. Another 21 percent of the reserve
base has an average sulfur content between 1 and 3 percent. This coal
could be used to meet S02 limits between 1.5-5 Ib/mm Btu. The average
sulfur content of another 21 percent of the reserve base is greater than
3 percent and the remaining 12 percent of the reserve base has not been
classified.
4.2 - PHYSICAL COAL CLEANING
Physical coal cleaning can increase the amount of coal available to
meet a low S02 emission limit in the following ways. Sulfur in coal is
either chemically bonded with the carbon or in the form of pyrite.
About 50 percent of the pyritic sulfur can be removed by physically
cleaning the coal. This is accomplished by crushing the coal and
removing the pyrite by gravity separation. The total sulfur content of
the coal can be reduced 14-45 percent by physical cleaning. Since ash
is also removed by the washing process, the heating value of the coal
(Btu/lb) is increased. Therefore, the S02 emission potential per Btu of
fuel burned (Ib S02/mm Btu) can be reduced 24 to 50 percent.
In addition to reducing the S02 emission potential of a coal,
physical cleaning reduces the variability of the sulfur content and the
heating value. Therefore, the resulting coal should have a more constant
emission rate (Ib S02/mm Btu).
33
-------
4.3 - OIL CLEANING
The sulfur content of fuel oil can be substantially reduced by
hydrotreating or hydrodesulfurization. These are chemical processes
which involve contact of the oil with a catalyst and hydrogen to convert
the sulfur to gaseous hydrogen sulfide (F^S).
In a typical hydrotreating or hydrodesulfurization process, oil is
filtered to remove rust, coke and other suspended material. It is then
mixed with hydrogen, heated to 340 to 450°C (650° to 850°F), and passed
over one or more catalytic reaction beds. The most widely used catalysts
are composites made up of cobalt oxide, molybdenum oxide, and alumina,
where alumina is the support and the other agents are promoters. This
process can reduce the sulfur content of a 2 percent sulfur residual oil
feedstock by 50 percent, to 1 percent sulfur. To produce a lower sulfur
content product, additional catalytic reaction stages must be added. A
system with two catalytic reaction stages can produce a fuel of approximately
0.3 percent sulfur content from a 2 percent sulfur feedstock. A more
advanced process using three catalytic reactors can produce fuel oils
with sulfur contents as low as 0.1 percent.
4.4 - FLUE GAS DESULFURIZATION
To meet S02 limits below 1 Ib/mm Btu, it may be necessary to remove
S02 from the exhaust gas after combustion. This can be accomplished by
scrubbing the gas with chemical solutions, such as sodium hydroxide or
sodium carbonate (sodium and double alkali processes); calcium oxide or
calcium carbonate; (lime and limestone processes).
In each case a chemical reaction combines the S02 in the flue gas
with the reactant to form a precipitant which separates from the air
stream. Performance data from several operating facilities show the
following ranges of S02 removal efficiencies:
34
-------
Sodium scrubbing - 90-95 percent removal for facilities
burning coal or oil with up to 3 percent sulfur.
Double alkali - 90-95 percent removal for facilities burning coal
with up to 3.2 percent sulfur.
Lime - 88-95 percent removal for facilities burning coal with up
to 3.6 percent sulfur.
Limestone - 70-90 percent removal.
Limestone with 2500 ppm adipic acid - an average of 93 percent
removal was achieved for a facility burning coal with
up to 3.6 percent sulfur.
Dry scrubbing - 75 percent removal has beeen guaranteed for coal
with up to 3 percent sulfur. Eighty-five (85) percent
removal has been guaranteed for coal with 1 to 2
percent sulfur.
35
-------
36
-------
Section 5
INDIVIDUAL STATED SIP REGULATIONS
The S02 emission regulations applicable in each State are delineated
in the following pages. The States are presented alphabetically by EPA
Region number.
37
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 1
STATE: Connecticut
REGULATION: State Air Law 19-508-19
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Uncontrolled8, New & Existing,
Comply by 9/1/72
All
All fossil
<0.5% S, dry basis
determination
Statewide
controlled8, New & Existing,
Comply by 9/1/72
All
All fossil fuels with
>0.5* S
<0.55 Ibs. S02/MMBtu
la, 2a, 2b, 2c, 3d, 4a, 5b, 5d
Statewide
NSPS, New after
8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2a, 2b, 2c, 3a, 4a, 5a, Sb
CO
00
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr) or manufacturer's, whichever
b. unit actual or operating (MMBtu/hr) is greater
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a"!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: continuous SO- monitoring by Commissioner's request
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM D3176 (coal or solid)
ASTM 5W (residual or liquid) or D1552
ASTM D129 (distillate or liquid) or D1552
other:
c. other testing: stack testing by Commissioner's request
only if uncontrolled source has potential
to emit ^100 tons 50,,/yr.
arefers to source using or not using a stack-gas cleaning process,
controlled or uncontrolled, respectively.
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
a. specified in 40 CER Part 60 (see Appendix A)
b. state regulation: Section 19-508-4 (periodic reports); and
Section 19-508-7 (equipment malfunction)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 1
STATE: Maine
REGULATION: Title 38, Section 603
APPLICABILITY:
Area"
New/Existing
Compliance Date
FACILITY SIZE
(MHBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
1. 2. 3, 4
New & Existing
After 11/1/73
All
All fossil
<2.5% S
5, 6
New & Existing
After 6/1/75
All
All fossil
<2.5% S
7
New & Existing
After 11/1/75
All
All fossil
<1.5% S
7
New & Existing
After 11/1/85
All
All fossil
<1.0% S
le, 2c, 3d, 4d, 5b
Statewide
New after 8/17/71 or 9/18/78 (NSPS)
N.A.
>250
NSPS, See Appendix A
NSPS. See Appendix A
la, 2a, 3a, 4a, 5a
co
vo
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (MHBtu/hr)
c. total plant design rated (MHBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFH Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: specified by the Board
1—Central Maine; 2—Down east; 3—Aroostook county;
4—Northwest Maine; 5~Metropolitan Portland; 6—Outside
Portland Peninsula; 7~Inside Portland Peninsula.
4. AVERAGING TIME:
a!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Board
5. REPORTING:
Fspecified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 589 (monthly reports of total volume of blended
oils and averages. Also quantity of solid & liquid fuel Imported Into the
c. specified in 40 CFR Part 51 (see Appendix B) state.
d. specified by the Director
-------
Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 1
STATE: Massachusetts
REGULATION: 310 CMR 7.05
APPLICABILITY:
Area3
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
B
New & Existing
All
#2 fuel oil
<0.17
Tbs S/MMBtu
all other
fossil
<1.21
Tbs S/MMBtu
CM, MV, MBb, PV, SM
New & Existing
All
#2 fuel oil
<:0.17
Tbs S/MMBtu
all other
fossil
<0.55
Tbs S/MMBtu
MB (specific c1tiesd)
New & Existing
All
#2 fuel oil
<0.17
Tbs S/MMBtu
all other
fossil
<0.28
Tbs S/HMBtu
»
la, 2c, 3d, 4d, 5b, 5d
Statewide
NSPS, New after
8/17/71 or
9/18/78
>250
NSPS, See
Appendix A
NSPS, See
Appendix A
la, 2 a, 3a, 4a, 5a
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (HMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
c.
other:
other testing: specified by the Department (methods
and frequency of testing)
Footnotes: See page 2, Massachusetts
4. AVERAGING TIME:
¥!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Department
5. REPORTING:
a!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: 310 CMR 7.12. Annual report for sources emitting <100
tons S0,/yr. Semi-annual report for sources emitting >100 tons S0-/yr.
c. specified in 40 CER Part 51 (see Appendix B) i
d. specified by the Director
-------
EPA Region: 1 State: Massachusetts (continued)
Footnotes:
aB = Berkshire
CM = Central Massachusetts
MV = Merrimark Valley
MB = Metropolitan Boston
PV = Pioneer Valley
SM = Southeastern Massachusetts
All cities except those specified later.
cNot applicable.
Medford, Newton, Somerville, Walthon and Watertown.
eRefers to all size sources except that units having rated heat input capabilities >3 MMBtu/hr
cannot use residual fuel.
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 1
STATE: New Hampshire
REGULATION:
Air Pollution Control Commission No. 5,
Revision III
APPLICABILITY:
Area3
New/Existing
Other
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
Solid fossil
< 2.8 Ibs. S/MMBtu gross heat content*3
and
< 2.0 Ibs. S/MMBtu gross heat content,
T3 month average)
le, 2b, 2c, 3d, 4d, 5b
All
Gaseous fossil
<_ 5 gr. H2S/100 cu. ft.
1. HEAT INPUT DETERMINATION:
T,unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified for compliance purposes
3. MONITORING REQUIREMENTS:
a"!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified
2. TEST METHODS:
source testing:
fuel testing:
ASTM
ASIM
ASTM
(coal or solid)
(residual or liquid)
(distillate or liquid)
other: most recent ASTM method (at Agency's
request)
other testing: not specified 5.
Footnotes: See page 3, New Hampshire
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: tri-monthly weighted average of fuel S content
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: No. 5, Revision III, Section 5 (fuel analysis at
Agency's request)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
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Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 1
STATE: New Hampshire (continued)
REGULATION:
A1r Pollution Control Commission No. 5,
Revision III
APPLICABILITY:
Area"
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
#2 fuel oil
£ 0.4X S
#4 fuel oil
< 1.0% S
#5 a #6
fuel oil
< 2.0* S
Statewide
New after 4/15/80
All
Solid fossil
< 1.5S Ibs. S/MMBtu
gross heat content"
AVa
New and Existing
All
All fossil
£ 2.2S S
le, 2b, 2c, 3d. 4d. 5b
1. HEAT INPUT DETERMINATION:
iTunit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified for compliance purposes
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified
2. TEST METHODS:
a. source testing:
b. fuel testing:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing:
ASTM
ASTM ;
other!most recent ASTM method (at Agency's
request)
not specified
4. AVERAGING TIME:
a:specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: trl-monthly weighted average of fuel S content
Footnotes: See page 3, New Hampshire
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: No. 5, Revision III, Section 5 (fuel analysis at
Agency's request)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 3
_EPA Region: 1
State: New Hampshire
Footnotes:
aRefers to "Air Quality Control Region":
Androscoggin Valley AQCR.
Refers to maximum value.
AV = New Hampshire portion of
-------
S02 EMISSION LIMITATIONS FIOM FUEL BURNING INSTALLATION,
(SIP Regulations)
EPA REGION: 1
STATE: Rhode Island
REGULATION: Air Pollution Control Regulation No. 8
APPLICABILITY:
Area
New/Existing
Other
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All uncontrolled sources3
All
All fossil
Requires use of fuels with < 0.55
Ibs S/MMBtu (fuel heat release potential)
or
<_ 1.1 Ib S02/MMBtu
Statewide
New and Existing
All approved controlled sources
All
Any fossil fuel with >0.55 Ibs S/MMBtu (heat release potential).
<_ 1.1 Ibs S02/MMBtu actual heat input
la, 2b, 2c, 3d, 4d. 5b
-pa
en
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr) or manufacturer, whichever is
greater
b.
c. total plant design rated (MMBtu/hr
d. total plant actual or operating (MMBtu/hr)
e. other:
unit actual or operating (MMBtu/hr)
r)
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified
2.
TEST METHODS:
a. source testing:
b. fuel testing:
ASTM
ASTM
ASTM ~
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
collection for testing when specified
by the Director.
other testing:
specified by the Director when he has reason to believe
noncompliance.
Footnotes: See page 2, Rhode Island
AVERAGING TIME:
T.specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Director
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: (Annual reports on fuel usage, stack dimensions,
exhaust gas flow rate and temperature, generating capacities of
generators, air pollution control systems, type of emissions, and
pollution emitting equipment.
c. specified 1n 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
EPA region: 1 State: Rhode Island (continued)
Footnotes:
Refers to source using no stack gas cleaning device.
Refers to source using a stack gas cleaning process to reduce the SCU emissions
provided equivalent emissions do not exceed specified emission limitations.
GActual heat inputjieating value of fuel x quantity of fuel burned (ton/hr).
01
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S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION:
STATE: Vermont
REGULATION: Environmental Protection Regulations
Chapter 5, Subchapter II. Sec. 221 and
Section 252 ;
APPLICABILITY:
Area
New/Existing
Other
FACILITY SIZE
(MMBtu/hr)
EUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
Uncontrolled
< 250
All fossil
< 2% S
Statewide
New and Existing
Controlled
< 250
All fossil
SO. emissions (Ibs. SO?/MMBtu
equivalent to those whin using
< 2 * S fuel)
Statewide
New and Existing
N.A.
> 250
Liquid fossil
0.80 Ibs
S02/MMBtu
Solid fossil
1.2 Ibs S02/MHBtu
la, 2a, 3b, 3c, 3d, 4a, 5b. 5d
1. HEAT INPUT DETERMINATION:
runit design rated (MMBtu/hr) (maximum)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate at Director's request
c. sulfur content of fuel
d. other: as required by the Air Pollution Control Officer
2. TEST METHODS:
a. source testing: at request of the Director, Method 6
as specified in 40 CFR Part 60 (see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
(distillate or liquid)
ASTM _
other:
c. other testing:
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 5, Section 402 (written reports)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director: fuel type, quantity, nature and amount of
emissions, and other relevant information such as stack testing
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Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 2
STATE: New Jersey
REGULATION: Title 7, Chapter 27, Subchapter 9 & 10
APPLICABILITY:
Area3
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Zone 1 & 2
New & Existing
All
Bituminous
coal
< 1.0% S or
< 1.5 Ib SO,/
MMBtu
COMPLIANCE PROCEDURES!!
Zone 3 & 4
New & Existing
Units < 200 or
total facility
< 450
Bituminous
coal
< 0.2% S or
< 0.3 Ib SO,/
MMBtu i
Zone 1 & 2
New & Existing
All
Anthracite
coal
< 0.7% S or
< 0.3 Ib SO,
MMBtu
Zone 3 & 4
New & Existing
All
Anthracite
coal
< 0.2% S or
~ 0.3 Ib SO,/
MMBtu *•
Zone 3 & 4
Existing on or before 5/6/68
Units > 200 or group of
facility > 450
Bituminous
coal
< 1.0* S or
<" 0.3 Ib SO,/
~ MMBtu
Anthracite
coal
< 0.2% S or
< 0.3 Ib SO,/
MMBtu i
Statewide (all other zones)
New or reconstructed after
5/6/68
> 1
All coal
< 0.2* S or
t 0.3 Ib S02/ MMBtu
(1-5, listed below) Ic, 2c, 3d, 4d, 5b
CO
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTM
ASTM
ASTM
(coal or solid)
(residual or liquid)
(distillate or liquid)
other: specified by the Department
c. other testing: specified by the Department
Footnotes: See page 3, New Jersey
AVERAGING TIME: i
eTspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Department
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: subchapter 10.2 & 9.2
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
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Pg. 2
S02 EMISSION LIMITATIONS FSOM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 2
STATE: New Jersey (continued)
REGULATION: Title 7, Chapter 27, Subchap.ters 9 & 10
APPLICABILITY:
Area*
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Zone 1
New & Existing
All
fuel -oil
112 i*4, *5, #6
0.3% S 2.0% S or
<2.1 Ib SO,/
fiMBtu '
Zone 2 & 5
New & Existing
All
fuel o
<*2 #4
0.3% S 0.7% S
10.74
Ib SO,/
MMBtu*
Ic, 2c, 3d, 4d. 5b
1
>*5, #6
1.0% S.
11.05
Ib SO,/
MMBtu*
Zone 3 & 4 & 6
New & Existing
All
f
5*2
0.2% S
uel oil
0.3% S or
<0.32 Ib SO,/
HMBtu '
Zone 3
New & Existing
All
fuel oil
>«, 16
0.5% S or
10.53 Ib S02/MMBtu
Zone 4 & 6
New & Existing
All
fuel oil
>I5. 16
0.3% S or
10.32 Ib S02/MMBtu
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTM
ASIM
ASTM
(coal or solid)
(residual or liquid)
(distillate or liquid)
other: specified by the Department
c. other testing: specified by the Department
Footnotes: See page 3, New Jersey
4. AVERAGING TIME:
T.specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Department
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: subchapter 10.2 & 9.2
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 3
EPA region: 2 State: New Jersey (continued)
Footnotes:
aZone 1 - Atlantic, Cape May, Cumberland, and Ocean Counties
Zone 2 - Hunterdon, Sussex, and Warren Counties
Zone 3 - Burlington, Camden, Gloucester, and Mercer counties (except those municipalities
included in Zone 6)
Zone 4 - Bergen, Essex, Hudson, Middlesex, Monmouth, Morris, Passaic, Somerset, and
Union counties
Zone 5 - Salem County
Zone 6 - in Burlington County, the minicipalities of Bass River, Shamong, Southampton,
Tabernacle, Washington, Woodland, and in Camden County, Waterford Township
Refers to dry basis determination
en
O
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 2
STATE: New York
REGULATION: Title 6. Part 225
APPLICABILITY:
Area
New/Existing
FACILITY SIZE3
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMITh
COMPLIANCE PROCEDURES
(1-5, listed below)
New York City
New & Existing
All >10
Residual
oil
O0% S
Distillate6
& solid
fossil fuel
<.20% S
Nassau, Rockland &
Westchester Counties
New S Existing
All >10
Fuel oil
£.37* S
Solid fossil
<.20« S
Suffolk County, Towns of Babylon, Brookhaven,
Huntington, Islip, and Smith town
New & Existing
All Existing0, Newd <250
and >10
Fuel oil
<1.0% S
Solid fossil
<0.6« S
Newd >250
Fuel oil
£.75« S
Coal
£.60 Ib S/MMBtu
Id, 2a, 2b, Zc, 3a or 3d, 4a, 4c, 4d, 5b, 5d
1. HEAT INPUT DETERMINATION:
a~!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60
at Commissioner's request
ASTM _ (coal or solid)
ASTM
ASTM
other:
(residual or liquid)
(distillate or liquid)
Footnotes:
See page 3,
New York
most recent applicable ASTM methods
for sampling, compositing, and
analysis of fuel or other methods
acceptable to the Commissioner.
The following values will be
determined: (residual oil) sulfur
& ash content, specific gravity,
heating value, (distillate oil)
sulfur content, specific gravity,
heating value, (coal) sulfur & ash
content, heating value
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: if total heat input >25tt MMBtu/hr: (weekly) gross heat content and
ash content of fuel burned, electricity installations 'average
electrical output & minimum & maximum hourly,(daily) rate of fuel
burned
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average) for stack tests
d. other: 3 continuous 1 hour averages (arithmetic average) for continuous
monitoring data as specified in 40 CFR Part 60
REPORTING:
T.specified in 40 CER Part 60 (see Appendix A)
b. state regulation: Title 6, Part 225.6(d) and Part 225.7
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director (when to submit report)
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Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 2
STATE: New York
REGULATION: Title 6, Part 225
APPLICABILITY:
Area
New/Existing
FACILITY SIZE3
(HMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT11
COMPLIANCE PROCEDURES
(1-5, listed below)
Erie & Niagra Counties t
City of Lakawana & South Buffalo
New & Existing
All Existing,0
Newd <250 but >10
Fuel Oil
<1.1% S
Newd
>250
Fuel
Oil
<.7S%
S
Coal
<.60 Ib S/
MMBtu
Remainder of Areas
New & Existing
All Existing,0 Newd
Newd £250 but >10 >250
Fuel Oil
<2.0% S
Tmax . )
<1.7% S
Tavg.f)
Solid
Fossil
<1.7% S
Tmax.) &
<1.4% S
Tavg.9)
Fuel
Oil
<.75% S
Coal
<.60 Ib S/
~ MMBtu
Rest of State
New & Existing
All Existing,0 Newd
Newd £250 but >10 >250
Fuel
Oil
<2.0%
S
Solid
Fossil
<2.5% S
Tmax.) &
1.9* S
Tavg.9)
Fuel
Oil
<.75%
S
Coal
<.60
T"b S/
MMBtu
Id, 2a, 2b, 2c, 3a or 3d, 4a, 4c, 4d, 5b, 5d
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
at Commissioner's request
b. fuel testing: ASTM (coal or solid)
(residual or liquid)
(distillate or liquid)
ASTM
ASTM _
other:
Footnotes:
See page 3,
New York
most recent applicable ASTM methods
for sampling, compositing, and
analysis of fuel or other methods
acceptable to the Commissioner.
The following values will be
determined: (residual oil) sulfur
& ash content, specific gravity,
heating value, (distillate oil)
sulfur content, specific gravity,
heating value, (coal) sulfur & ash
content, heating value
5.
MONITORING REQUIREMENTS:
a"!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: if total heat Input >250 HMBtu/hr: (weekly) gross heat content &
ash content of fuel burned. Electricity installations: average
electrical output & minimum and maximum hourly, (daily) rate of
fuel burned
AVERAGING TIME:
a. specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 3 continuous 1 hour averages (arithmetic average) for continuous
monitoring data as specified In 40 CFR Part 60
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Title 6, Part 225.6(d) and Part 225.7
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director (when to submit report)
-------
EPA region: 2 State: New York (continued)
Footnotes:
Determined by product of fuel weight rate (Ibs./hr.) and fuel caloric1 value.
That area located in the City of Buffalo which is south of the line commencing at the
intersection of I 190 and Rt. 5 and proceeding east along I 190 to the city line.
Application for permit to construct received on or before 3/15/73.
Application for permit to construct received after 3/15/73.
eRefers to ASTM 1 & 2 (fuel oil), 1-D&2-D (diesel fuel oil), and 1-GT&2-GT turbine fuel oil.
Determined by dividing the sum or sulfur content times the amount of each shipment of oil
received by the total amount of oil received during each consecutive 3 month period.
9Determined by dividing the total sulfur content by the total gross heat content of all solid
fuel received during any consecutive 3 month period.
All sources in areas attaining the National Ambient Air Quality Standard for S02 March 24, 1979
having a source total heat input £250 MMBtu/hr. (oil) or <100 MMBtu (individual unit) gross heat
input (coal) will be permitted to use oil <3 percent by weight sulfur or coal <2.8 Ibs. sulfur/
MMBtu gross heat input, respectively, as approved by the Commissioner.
-------
Pg. 1
SO;
EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Delaware
REGULATION: VIII, XX (Section 2)
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
New Castle County
New & Existing
All
Distillate fossil
<0.3% S
Other fossil
<1.0% S & attain
TfAAQS
Any facility with SO, emission
control equipment
All fossil
Emission rate equivalent to sulfur
limitations
le, 2a, 2b, 3d, 4d, 5d
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr) for testing procedure
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by Director
2. TEST METHODS:
a. source testing:
b. fuel testing:
specified by Director
ASTM
ASIM
ASTM ~
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
4. AVERAGING TIME:
ITspecified in 40 CF.R Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 30 day rolling average for emissions limitation
x-ray absorption method (residual
or distillate for New Castle County)
c. other testing:
Ibs. S02/MMBtu total plant actual heat
input as specified by the Director
REPORTING:
T.specified in 40 CER Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
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Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA
REGION:
3
STATE:
Delaware
(continued)
REGULATION:
VIII,
XX
(Section
2)
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Kent, Sussex Counties
New
(construction on or after 8/17/71)
>250
All fossil
£1.2 Ibs. S02/MHBtu
la, Ib, Ic, 2a, 3d. 4d, 5d
Statewide
NSPS, new after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS. see Appendix A
la, 2c. 3d, 4d. 5d
Statewide
New ft Existing
All not previously specified
All
Specified by the Departuent
le, 2a, 3d. 5d
en
en
1. HEAT
a.
b.
c.
d.
e.
2. TEST
a.
b.
INPUT DETERMINATION:
unit design
unit actual
total plant
total plant
other: not
METHODS:
rated (MMBtu/hr)
or operating (MMBtu/hr)
design rated (MMBtu/hr)
actual or operating (MMBtu/hr)
specified
source testing: specified by Director
fuel testing: ASTM (coal or solid)
ASIM (residual or liquid)
ASTM (distillate or liquid)
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by Director
4. AVERAGING TIME:
T.specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 30 day rolling average for emissions limitation
other:
x-ray absorption method (residual
or distillate for New Castle County)
c. other testing:
Ibs. S02/MMBtu total plant actual heat
input as specified by the Director
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
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Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Maryland
REGULATION: 10.18.09
APPLICABILITY:
Area - County3
New/Existing
FACILITY SIZE
(MMBtu/hr}
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
I, II. V, VI
New & Existing
I13
residual fuel oil
2.0% S
distillate fuel
oil
0.3% S
process gas used
as fuel
0.3% S
la, 2c, 3d, 4a, 5b, 5d
>13 unit actual and
>100 total plant design capacity
solid fossil
3.5 Ibs S02/MMBtu
Ib, Ic, 2c, 3d, 4a, 5d
en
CTl
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: as requested by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60
ASTM _
ASTM
ASTM ^
other?
(coal or solid)
(residual or liquid)
(distillate or liquid)
other testing: Method 6 in "Test Methods for Stationary
Sources", Maryland State Bureau of Air
Quality and Noise Control, March 1976.
Test methods may be modified by the
Department
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director (fuel analysis, type & quantity for owner
and fuel supplier)
-------
Pg. 2
SO? EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
Maryland (continued)
REGULATION: 10.18.09
APPLICABILITY:
Area - County8
New/Existing
FACILITY SIZE
(Heat Input in MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
III & IV
New & Existing
i13
residual
fuel oil
1.0% S
distillate
fuel oil
0.3% S
>250
solid fossil
1.0% S
la, 2c, 3d, 4a, 5d
Statewide
NSPS, New after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
la, 2a, 3a, 4a, 5a
en
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:- as requested by the Department
2. TEST METHODS: 4.
a. source testing: Method 6 as specified in 40 CFR Part 60
b. fuel testing: ASIM
ASTM
ASTM
other"
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing:
Method 6 In "Test Methods for Stationary
Sources", Maryland State Bureau of Air
Quality and Noise Control, March 1976.
Test methods may be modified by the
Department
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1. hour
c. 2 hours (arithnetic average)
d. other:
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part SI (see Appendix B)
d. specified by the Director (fuel analysis, type & quantity for owner
and fuel supplier)
-------
Pg. 3
EPA region: 3
State: Maryland (continued)
Footnotes:
aArea I -
Area II -
Area III
Area IV -
Area V -
Area VI -
Alleghany, Garrett & Washington counties
Frederick county
- Baltimore city, Anne, Arundell , Baltimore, Carroll, Harford
Montgomery & Prince George counties
Calvert, Charles, & St. Mary counties
Caroline, Cecil, Dorchester, Kent, Queen Anne, Somerset, Tal
& Worcester counties
& Howard counties
bot, Wiconico,
en
00
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Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
Pennsylvania
REGULATION: Title 25, Part I. Subpart C.
Article III. Chapter 123.22
APPLICABILITY:
Area - Air Basin9
New/Existing
Compliance Date
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/HMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
I
New & Existing
N.A.d
All
Fuel oil
<#2 >#4, 5, 6
<0.5% S <2.8* S
or
<4.0 Ib S02/MMBtu
II
New & Existing
N.A.
All
Fuel
*4. 5. 6
<2.8% S
r
S02/MMBtu
III
New & Existing
8/1/79 8/1/79 8/1/82
All
Fuel oil
<#2
<0.3% S
I3-
All
All
Fuel oil
#4. 5. 6
<2.0% S
or
0 Ib S02/l
£1.5% S
WBtu
IV
New & Existing
N.A.
>2.5 but >50 but >2.000
<50 <2,000 ~
All fuel All fuel All fuel
oil oil oil
1.0 & (0.5)1
Ib S02/MMBtu
la. 2a. 2b. 2c. 3d. 4b, 5b. 5d
CJl
MD
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
rcontinuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing:
b. fuel testing:
determination of F-Factor only from
40 CFR Part 60 (Method 6)
ASTM (coal or solid)
ASTM
ASTM"
(residua] or liquid)
(distillate or liquid)
other: as specified by the Director
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) (for continuous SO. data)
b. 1 hour (for compliance stack testing)
c. 2 hours (arithmetic average)
d. other: 30 day, 1 day, & daily maximum (for continuous monitoring data)
c. other testing: stack testing (when specified by the 5.
Director) by 1) Devorkin, "Air Pollution Source Testing Manual"
L.A.P.C.D. 2nd printing, 11/65 or 2) equivalent method-Robert
Hilvinsky, "Determination of sulfur oxides" (utilizing isopropyl
alcohol and sodium hydroxide), Air Pollution Source Testing Manual ,c-
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
state regulation: Chapter 139.1022
b.
Method 5.4, South Coast Air Quality Manage
California, 2nd printinq, 8/78
specified in 40 CFR Part 51 (see Appendix B)
:nt District, El Monte, d- specified by the Director
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Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Pennsylvania (continued)
REGULATION: Title 25, Part I, Subpart C,
Article III, Chapter 123.22
APPLICABILITY:
Area - Air Basins3
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Its S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
V (Inner zone)
New & Existing
<250
Fuel oil
£#2 ^#4, 5, 6
<0.2% S <0.5% S
or
£1.0 Ib S02/MMBtu
V (Outer zone)
New & Existing
<250
Fuel
I*2
ttt, 5, 6
<1.0* S
r
02/MMBtu
V (Inner zone)
New & Existing
<250
Fuel oil
£#2 >#4. 5, 6
<0.2% S <0.5% S
or
£0.6 Ib S02/MMBtu
V (Outer zone)
New & Existing
<250
Fuel oil
£#2 ^#4, 5, 6
£0.3% S £l.0% S
or
<1.2 Ib S02/MMBtu
la, 2a, 2b, 2c, 3d, 4b, 5d
CTi
O
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a.
b.
source testing:
fuel testing:
determination of F-Factor only from
40 CFR Part 60 (Method 6)
ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: as specified by the Director
AVERAGING TIME:
a"! specified in 40 CFR Part 60 (see Appendix A) (for continuous SO, data)
b. 1 hour (for compliance stack testing)
c. 2 hours (arithmetic average)
d. other: 30 day, 1 day, & daily maximum (for continuous monitoring data)
REPORTING:
ITspecified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 139.1022
c. other testing: stack testing (when specified by the 5.
Director) by 1) Devorkin, "Air Pollution Source Testing Manual"
L.A.P.C.D. 2nd printing, 11/65 or 2) equivalent method-Robert
Hilvinsky, "Determination of sulfur oxides" utilizing isopropyl
alcohol and sodium hydroxide), Air Pollution Source Testing Manual,c. specified in 40 CFR Part 51 (see Appendix B)
Method 5.4, South Coast Air Quality Management District, El Monte, d. specified by the Director
California, 2nd printing, 8/78
-------
Pg. 3
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Pennsylvania (continued)
REGULATION: Title 25. Part I, Subpart C,
Article III, Chapter 123.22
APPLICABILITY:
Area - A1r Basins'
New/Existing
FACILITY SIZE
(MMBtu/hr)
EUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
I & II
New & Existing
All*
Solid fossil
<3.7 <4.0
(30 day (1 dayh
avg.) avg.)
<4.8
1 day
(max.)
Ill
New & Existing
All9
Solid fossil
£2.8 £3.0
(30 day Tl day
avg.) avg.)
<3.6
1 day
(max .
V (Inner zone)
New & Existing
<250
Solid fossil
£0.75
?30 day
avg.)
<1.0
Tl dayh
avg.)
>250
Solid fossil
£l.2 £0.45 £0.60 <0.72
1 day (30 day (1 dayh 1 day
(max.) avg.) avg.) (max.)
la. 2a, 2b, 2c, 3a. 4b, 4d, 5b, 5c
CT>
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
ITcontinuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2.
TEST METHODS:
a. source testing:
b. fuel testing:
determination of F-Factor only from
40 CFR Part 60 (Method 6)
ASTM (coal or solid)
ASTM (residual or liquid)
(distillate or liquid)
ASTM _
other"
as specified by the Director
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) (for continuous SO. data)
b. 1 hour (for compliance stack testing)
c. 2 hours (arithmetic average)
d. other: 30 day, 1 day & dally maximum (for continuous monitoring data)
c. other testing: stack testing (when specified by the 5.
Director) by 1) Devorkln, "Air Pollution Source Testing Manual"
L.A.P.C.D. 2nd printing, 11/65 of 2) equivalent method-Robert
Hilvinsky, "Determination of sulfur oxides" (utilizing isopropyl
alcohol and sodium hydroxide), Air Pollution Source Testing Manual,c. specified in 40 CFR Part 51 (see Appendix B)
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 139.1022
Method 5.2, South Coast Air Quality Management District, El Monte, d.
California, 2nd printing, 8/78
specified by the Director
Footnotes: See page 5, Pennsylvania
-------
Pg. 4
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Pennsylvania (continued)
REGULATION: Title 25, Part I, Subpart C,
Article III, Chapter 123.22
APPLICABILITY:
Area - Air Basins3
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
V (outer zone)
New & Existing
All
Solid fossil
<0.90, <1.2, <1.44,
(30 day avg.) (1 dayh avg.) 1 day (max.)
la, 2a, 2b, 2c, 3a, 4b, 4d, 5b, 5c
CTi
ro
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing: determination of F-Factor only from
40 CFR Part 60, (Method 6)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: as specified by the Director
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) (for continuous SO, data)
b. 1 hour (for compliance stack testing)
c. 2 hours (arithmetic average)
d. other: 30 day, 1 day, & daily maximum (for continuous monitoring data)
c. other testing: stack testing (when specified by the 5.
Director) by 1) Devorkin, "Air Pollution Source Testing Manual"
L.A.P.C.D. 2nd printing, 11/65 or 2) equivalent method-Robert
Hilvinsky, "Determination of sulfur oxides" (utilizing isopropyl
alcohol and sodium hydroxide), Air Pollution Source Testing Manual,c
Method 5.4, South Coast Air Quality Management District, El Monte, d
California, 2nd printing, 8/78
REPORTING:
specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 139.1022
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
EPA region: 3 State: Pennsylvania (continued)
Footnotes:
al = non-air basin areas.
II = Erie, Harrisburg, YorkftLancaster, Scranton, Wilkes-Barre.
Ill = Allentown, Bethlehem, Easton, Reading, Upper Beaver Valley, Johnston.
IV ='Allegheny County, Beaver Valley, Monongahela Valley.
V - Southeast Pennsylvania - Inner & Outer refer to zoning classifications within the air basin
Refers to "Fossil Fuel Fired" units not using coal.
cRefers to zone within specified air basin.
N.A. = not applicable.
eRefers to formula for determining emission rate, A = 1.7E
where: A = allowable S02 emissions (Ibs/MMBtu heat input)
E = heat input to the combustion unit in MMBtu/hrs
Specified sulfur content refers to facilities not using S0« pollution abatement devices to achieve
compliance. Controlled sources may use higher sulfur content fuel if meet IDS S02/MMBtu limitation.
9By department approval only.
Except for 2 days/month.
^lleghany County only.
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: Virginia
REGULATION: Air Pollution Control Board.
Part IV, Rule Ex-5, Section 4.51
APPLICABILITY:
Area - AQCRa
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT6
COMPLIANCE PROCEDURES
(1-5, listed below)
1, 2. 3, 4, 5, 6
New & Existing
All
All fossil
S = 2.64(k)
7
New & Existing
All
Solid fossil
S = 1.52(k)
Liquid or
Gaseous fossil
Combination liquid &
solid fossil
„ „ ,X(1.06) + Y(l. 52).
PS K ( £ + ^ ')
Ib, 2a or 2c, 3d, 4a or 4d, 5b, 5d
Statewide
NSPS, New after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
Ib, 2a, 3a, 4a, 5a
cn
-F=>
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr) at total capacity
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Board
JEST METHODS:
a. source testing:
b. fuel testing:
3 separate runs of Method 6 as specified
in 40 CFR Part 60 (see Appendix A)
ASTM (coal or solid)
(residual or liquid)
(distillate or liquid)
ASTM _
ASTM _
other:
other testing: as approved by the Board (3 separate runs) 5.
Footnotes: See page 2, Virginia
AVERAGING TIME:
a~lspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified in alternative approved test method
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Part IV, Section 4.05 (monitoring & test results)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director (provide reports at his request)
-------
EPA region: 3 State: Virginia (continued)
Footnotes:
aRefers to Air Quality Control Region (by counties & cities) listed in Appendix B, page 195 of
Commonwealth of Virginia Regulations for the Control and Abatement.
1 - Eastern Tennessee - Southwestern Virginia
2 - Valley of Virginia
3 - Central Virginia
4 - Northeastern Virginia
5 - State Capital
6 - Hampton Roads
7 - National Capital
TJhere:
S = Allowable SO? emissions in Ibs/hr.
k = Actual heat input at maximum capacity.
PS = Prorated allowable S02 emissions in Ibs/hr.
X = Percentage of actual heat input derived from liquid or gaseous fuel.
Y = Percentage of actual heat input derived from solid fuel.
en
in
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA
REGION: 3
STATE:
Uashington,
D
C.
REGULATION:
Section
8-2
704
&
2.705
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
All fossil
<1.0% S
la, 2b, 2c, 3a, 3c, 3d, 4c, 5b, 5d
Statewide
NSPS, new after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
la, 2a, 2b, 2c, 3a, 3c, Id, 4a, 4d, 5a, 5b
CTi
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous SO, monitoring by 40 CF" Part 60 (see Appendix A) (sources
emit >100 tonS/yr S02)
b. ambient monitorinn or diffusion estimate
c. sulfur content of fuel
d. other: quantity of fuel
2. TEST METHODS:
a. source testing:
b. fuel testing:
c. other testing:
Method 6 as specified in 40 CFR
Part 60
ASTM (coal or.solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: 40 CFR 60.45.f.5. Sulfur content, heat
content, viscosity, carbon residue
specified by the Director 5.
AVERAGING TIME:
a. specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: weekly sulfur content
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: 8-2.717 (power plants) weekly, monthly, quarterly,
(all other sources), annual (government boilers)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 3
STATE: West Virginia
REGULATION: X (1978A)
APPLICABILITY:
Areaa « b
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ib S02/MMBtu
COMPLIANCE PROCEDURES
(1-5. listed below)
I » II:
A(a)l A(c) & A(d)
New i Existing
>10
All fossil
£6.8 £2.7
I & II:
B»C A(b)
New i Existing
i10
All fossil
£3.1 £7.5
III: A(f), A(g),
A(1). B&C
New & Existing
i10
All fossil
<3.2
III: A(e)
New & Existing
I10
All fossil
£5.12
III: A(h)
New & Existing
>IO
All fossil
£3.1
IV: A(j), A(k), & (BSC)C
New & Existing
>»
All fossil
£1.6
Ib, Ic, 2b, 3a, 3d, 4d, 5b, 5d
1. HEAT INPUT DETERMINATION:
alunit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)> footnote b
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS':
aTcontinuous S02 monitoring by 40 CFR Part 60 (see Appendix A) at Director's request
b. ambient monitoring ar diffusion estimate
c. sulfur content of fuel
d. other: not specified
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTM
ASTM
ASTM
c. other testing:
(coal or solid)
(residual or liquid)
(distillate or liquid)
other: equivalent fuel sulfur content to
achieve compliance
Footnotes: See page 2, West Virginia
4. AVERAGING TIME:
a!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: continuous 24 hr. average of SO- data
5. REPORTING:
T.ipecTfied in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 6.05 (not to exceed one hourly violation
per month)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
EPA region: 3
State: West Virginia (continued)
en
00
Footnotes:
.„ Regions:
I & II - Brooke, Hancock, Marshall, Ohio, Grant (union district only),
Mineral (Elk, New Creek and Piedmont districts) counties.
Ill except IV - Jackson, Pleasants, Tyler, Wetzel & Wood counties.
IV - All other counties.
Type Equipment:
A - Fuel burning units which produce electricity for sale.
B - Any unit not classified as Type A or C.
C - Any hand-fired or stoker-fired unit not classified as Type A unit.
Refers to specific source or similar units in that Priority Region:
(a) Kammer; (b) Mitchell; (c) Willow Island; (d) Mt. Storm; (e) Harrison; (f) Rivesville; (g) Albright;
(h) Fort Martin; (i) Philip Sporn; (j) John Amos; (k) Kanawha
CB&C provided _<5,500 Ibs. S02/hr, discharged from all stacks at one plant.
-------
g. i
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Alabama
REGULATION:
Air Pollution Control, Chapter 5,
Section 1
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
IDS S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Class Ia or Jefferson Co.
New & Existing
All
All fossil
£1.8
Class II*
New & Existing
All
All fossil
<4.0
Jackson Co.
New & Existing
>5,000
All fossil
<1.2
Ic, 2a or 2c, 3b, 3c, 3d, 4d, 5b
Statewide
NSPS, new after 8/17/71 or
9/18/78
>2SO
NSPS. see Appendix A
NSPS, see Appendix A
la, 2a, 3a, 3b. 3c, 4a, 4d,
5a, Sb
vo
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr) see footnote b
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate (if total rated capacity heat
input >1500 ffJBtu/hr
c. sulfur content of fuel
d. other: as specified by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified 1n 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: as approved by the Director
Footnotes: See page 2, Alabama
4. AVERAGING TIME:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 24 hr average for compliance (for SO,) data or specified by
the Director '
5. REPORTING:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 1.7.2 (periodic reports on emission rates (24 hour
averages summarized monthly and submitted biannually), sulfur content of fuels
-------
Page 2
EPA Region: 4
State: Alabama (continued)
Footnotes:
aRefers to counties classified as Class I or Class II in the State of Alabama Air
Pollution Control Commission's Rules and Regulations, App. B, page 1 (February 13, 1980)
Units constructed that are applicable NSPS sources are not included in the total rated
capacity heat input for the installation.
°Refers to maintenance of "National Ambient Air Quality Standard" for SCL.
-------
Pg. 1
SO; EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Florida
REGULATION: Chapter 17-2.05, Supplement #97
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1*5, listed below)
Statewide
Existing"
>250
Solid fossil
<6.17
Liquid fossil
<2.75
Ib, 2c, 3a, 3d, 4c & 4a, 5a, 5b
Statewide
New & Existing8
<2SO
All fossil
BACTb
Ib, 2c, 3d, 4c, 5b
Statewide
NSPS. new after 8/1/7/71 or 9/18/78
>250
See Appendix A
See Appendix A
la, 2a, 3a, 4a, 4c, 5a
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)c
b. anbient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM ~(residual or liquid)
ASTM
otherr
(distillate or liquid)
c. other testing: see attachment (page 2)
Footnotes: See page 2, Florida
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)c .
b. state regulation: Chapter 17-2.08(2) Supplement 101°
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
EPA region: 4
State: Florida (continued)
Footnotes:
aExcludes sources and counties containing source specific emissions limitations.
Refers to use of "Best Available Control Technology" to limit emissions.
cRefers only to sources with S09 pollution control equipment.
j L.
Refers to sources without S02 pollution control equipment.
2.c. other testing:
source testing according to "Standard Sampling Techniques and Methods of
Analysis for Determination of Air Pollutants From Point Sources",
June 1975.
-------
Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Georgia
REGULATION: A1r Quality Control Chapter
391-3-l-2(g)
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT*
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
<100
oil
<2.6J S
>100
oil
<3.0X
S
<100
solid fossil
<2.5% S
>100
solid fossil
<3.0* S
Ib. 2b. 3d. 4a, 4d. 5a and 5b
Statewide
NSPS, new after 8/17/71 or 9/18/78
>250
All fossil
NSPS requirements, see Appendix A
la, 2a, 2b. 3a, 4a, 5a
CJ
1. HEAT INPUT DETERMINATION:
T.unit design rated (HMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fue]
d. other: specified by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM
ASTM "
(residual or liquid)
(distillate or liquid)
4. AVERAGING TIME:
alspecified in 40 CFR Part 60 (see Appendix A)if heat Input >250 MMBtu/hr
b. 1 hour
c. 2 hours (arithmetic average) -
d. other: specified by the Director
c. other testing:
other: % sulfur, heating value & ash content
(acceptable ASTM method)
Footnotes: See page 2, Georgia
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)If heat Input >250 MMBtu/hr
b. state regulation: Ch. 391-3-l-6(b)l Fuel testing as specified by the Director,
dally & monthly production rates, hours of operation
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 2
EPA Region: 4 State: Georgia (continued)
Footnotes:
a
Sulfur content is determined on a dry basis. Sources using S0? pollution abatement device may use higher
sulfur content fuel if emissions are equivalent. In addition to the sulfur in fuel limit, the State limits
sulfur dioxide emissions based on stack height and location (urban or rural .area). However, EPA has
"determined that the sulfur in fuel limit ... is sufficient standing alone to assure attainment and
maintenance of the national air quality standards for S02" (41FR35185, August 20, 1976).
--j
-P.
-------
Pg.
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
en
EPA REGION: 4 STATE: Kentucky
APPLICABILITY:
Area , (see attachment •
P9. 4)
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S09/MMBtu, solid
Ibs SOg/MMBtu, liquid
COMPLIANCE PROCEDURES
(1-5, listed below)
I II II
REGULATION: 401 KAR 61:015, Section 5
I IV » IVA y 4 VA
Existing (constructed on or
before 4/9/79)
<10
Solid fossil
Liquid or gaseous fossil
<5.0 <6.0 <
73.0 <4.0 <
7.0 10 butgZSO
Solid fossil
Liquid or gaseous fossil
Applicable county equation (see attachment)
Id, 2a. 2b. 3c, 4a, 4d, 5b. 5d
1. HEAT INPUT DETERMINATION:
a. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR PC
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: specified by the Department
c. other testing:
Footnotes: See page 5, Kentucky
3. MONITORING REQUIREMENTS:
a. continuous
new source
b. ambient no
c. sulfur con
d. other: Fo
& maximum
4. AVERAGING TIME
irt 60 a- specified
b.. 1 hour
c. 2 hours (a
d. other: We
5. REPORTING:
T. specified
c. specified
d. specified
S02 monitoring by 40 CFR Part 60 (see Appendix A) for existing &
s with heat Input >250 MMBtu/hr
Storing or diffusion estimate
tent of fuel, heating value, & ash content
r electric generators - average electrical output, Minimum
Hourly generation rate (dally). Summarize both monthly
in 40 CFR Part 60 (see Appendix A)
rithmetlc average)
ekly average for sulfur & ash content 4 heating value
in 40 CFR Part 60 (see Appendix A)
Ution: 401KAR 50:050 (periodic reports at Director's request)
in 40 CFR Part 51 (see Appendix B)
jy the Director
-------
Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA
REGION:
4
STATE:
Kentucky
(continued)
REGULATION:
401KAR
61
015,
Section
5
APPLICABILITY:
Area (see attachment,
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs 50,,/MMBtu, solid
Ibs SOj/MMBtu, liquid
COMPLIANCE PROCEDURES
(1-5, listed below)
I
II & III
IV II IVA
V & VA II IVA
V
VAa II IVA
V
VA
Existing (constructed on or before 4/9/72)
>250
Solid fossil
Liquid or gaseous fossil
7o!s
<3.3
72.2
<5.2
73.5
>250 but
71,500
Solid fossil
Liquid or
gaseous fossil
<5.2
73.5
<6.0
74.0
>1,500 but
<21,000
Solid fossil
Liquid or
gaseous fossil
<3.5
72.3
<6.0
74.0
I1'1
^21 ,000
Solid fossil
Liquid or gaseous fossil
I2-1
<6.0
74.0
I1'1
Id, 2a, 2b, 3a or 3c, 3d, 4a, 4d, 5b
1. HEAT INPUT DETERMINATION:
ITunit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a", continuous S02 monitoring by 40 CFR Part 60 (see Appendix A) for existing &
new sources with heat input >250 HM8tu/hr
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel, heating value, & ash content
d. other: For electric generators - average electrical output, minimum
& maximum
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: specified by the Department
c. other testing:
Footnotes: See page 5, Kentucky
AVERAGING TIME: Hourly generation rate (daily). Summarize both monthly
SLspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: Weekly average for sulfur & ash content & heating value
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: 401KAR 50:050 (periodic reports at Director's request)
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
Pg. 3
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Kentucky (continued)
REGULATION: 401KAR 61:015. Section 5
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
Combination fossil
Combination fuel equation3
Applicable size category
and county
Statewide
New (constructed after 4/9/72)
>10 but i250
Solid, liquid, or gaseous fossil
Applicable New Source equation
(see attachment)
Id, 2a, 2b, 3c, 3d, 4a, 4d. 5b
Statewide
NSPS, new after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
la, 2a, 2b, 3a or 3c, 4a, 4d. 5a
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T. continuous SO, monitoring- by 40 CFR Part 60 (see Appendix A) for existing &
new sources with heat Input >250 MMBtu/hr
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel, heating value, & ash content
d. other: For electric generators - average electrical output, minimum
& maximum
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM ~~ (residual or liquid)
(distillate or liquid)
ASTM
other: specified by the Department
c. other testing:
Footnotes: See page 5, Kentucky
4. AVERAGING TIME: Hourly generation rate (daily). Summarize both monthly
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: Weekly average for sulfur & ash content & heating value
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: 401KAR 50:050 (periodic reports at Director's request)
(.. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 4
EPA region: 4
00
State: Kentucky (continued)
ATTACHMENI
Kentucky
Equations to Determine S02 Emissions Limitation (Existing Sources)
County(s)
Jefferson & McCracken
Muhlenberg
Webster & Hancock
Boyd
Bell, Clark, & Woodford
Pulaski
(all other counties)
Class #
I
IVA
IV
VA
II
III
V
Solid Fuel Equation
y = 13.9871X-0'4434
-0.4434
-0.1338
-0.1338
-0.2979
-0.2236
-0.1260
y = 13.9871x
y = 10.8875X
y = 10.8875x
y = 11.9134X
y = 11.9872x
y = 12.0284X
Liquid or Gaseous Fuel Equation
y = 7.7223x-°-4106
-0.4106
-0.1347
-0.1347
y - 8.01681X-0'3047
y - 7.7966X'0-2291
y = 7.7223x
y = 7.3639X
y = 7.3639x
y = 8.0189x
-0.1260
Equations to Determine SOo Emissions Limitation (New Sources)
Counties
(all counties)
Solid Fuel Equation
y = 13.8781X-0'4434
Liquid or Gaseous Fuel Equatia
y = 7.7223X-0'4106
where: y = allowable SO, emissions (Ibs./MMBtu).
x = capacity rating (MMBtu/hr).
-------
EPA region: 4 State: Kentucky (continued)
Footnotes:
aAll existing and new fuel burning units in county Class VA must limit average annual S02 emissions
to fO.6 and hourly emissions to applicable size categories for that county.
K y(a) + z(b)
Allowable SOY (Ibs/MMBtu) = y + z
A
where: y = percent of total heat input (liquid or gaseous)
z = percent of total heat input (solid)
a = allowable applicable size category & county S02 emissions (Ibs. S02/MMBtu) for liquid
or gaseous fuel
b = allowable applicable size category & county S09 emissions (Ibs. S02/MMBtu) for solid
fuel
VD
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Mississippi
REGULATION: APC-S-1
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (construction on
or before 5/8/70)
All
All fossil
< average annual emission
rate for 1970 units
le, 2c, 3d, 4d, 5b
Statewide
New indirect heat transfer
unit (after 5/8/70)
All
All fossil
<4.8 Ib S02/MMBtu
All modified fuel
burning units
<250
All fossil
£2.4 Ib S02/MMBtu
la, 2c, 3d, 4d,
5b
Statewide
NSPS, new after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
la, 2c, 3a, 4a, 5b
oo
o
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: as specified in each permit
2. TjST METHODS:
a. source testing:
b. fuel testing:
ASTM
ASTM ~
ASTM ~
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing:
submit testing data (for permit
renewal) to demonstrate compli ance
at the Commission's request
Footnotes:
Modification shall mean any physical change which increases the
amount of SO^ emitted.
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: not specified
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: APC-S-2, Section 4.2 (records of operation and emission
data at Commission's request)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: North Carolina
REGULATION: Title 15, Chapter 20, Sections .0500,
.0516, .0603, .0604, .0606 '
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(HMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing
All
All fossil
<2.3 and attain
TTAAQS0 for S02
la, 2a or 2b, 2c
3c or 3d, 4ac, 5a
Statewide
New (construction after 2/1/76) and not specified
in 40 CFR Part 60 or 40 CFR Part 51 with an
average annual capacity > 30 percent
>250
Coal or residual oil
<2.3 and attain NAAQS for S02
la, Ic, 2a, 3c, 5b
Statewide
NSPS, new after 8/1/71 or
9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
Statewide
Existing (applicable
40 CFR Part 51 Source
See Appendix B
See Appendix B
See Appendix B
la, 2a, 3a, 4a, 5a
CO
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient nonitoring or diffusion estimate
c. sulfur content of fuel
d. other: as approved by Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
b. fuel testing: ASTH P3177 (coal of solid) percent sulfur
(dry basis)
ASTM D129_ (residual or liquid) * sulfur
(dry basis)
ASTM D129 (distillate or liquid) * sulfur
(dry basis)
other: (coal) sanpling-ASTM D2234,
preparation-ASTM D2013, Btu-ASTM D2015
(dry basis, moisture-ASTM D3177 (oil)
sampling-ASTM D270, Btu-ASTM D240
c. other testing: Emission rates determined by "F-Factor"
Method in 40 CFR 60.45
Footnotes: See page 2, North Carolina
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) (arithmetic average of
3 repetitions or runs)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section .0600 (quarterly reports of fuel type, quantity,
Btu value, percent sulfur by weight, and total calculated SO, emissions.
c. specified in 40 CFP. Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
EPA region: 4 State: North Carolina (continued)
oo
ro
Footnotes:
aRatio of the average load on equipment for one year.
National Ambient Air Quality Standards.
GDetermine compliance by stack testing.
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: south Carolina
REGULATION: No. 1, 62.5
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Class I (Charleston County)
New & Existing
<10
All fossil
£3 ..5
>10
All fossil
<2.3
Class II (Alken & Anderson Counties)
New & Existing
<1,000
All fossil
£3.5
£1.000
All fossil
I2-3
Class III (All other counties)
New & Existing
All
All fossil
53.5
la, 2c, 3d, 4d, 5b, 5d
00
GJ
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified for SO,
2. TEST METHODS:
a. source testing:
b. fuel testing:
ASTM
ASTM ~
ASTM _
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing: not specified for S0?, testing at
Director's request
4. AVERAGING TIME:
ITspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: not applicable
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: not specified for S02
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 1
SOZ EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Tennessee
REGULATION:
Division of A1r Pollution Control
Chapter 1200-3-14-.02
APPLICABILITY:
Area3
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
I
Existing (con-
struction on or
before 4/3/72
>1000
£1000
All fossil
I1-2
£1.6
II
Existing (con-
struction on or
before 4/3/72
>1000
_<1000
All fossil
I1-2
£5.0
III
Existing (con-
struction on or
before 4/3/72
All
All fossil
£2.4
IV
Existing (con-
struction on or
before 4/3/72
>600
coal
£4.0l
K & #6
fuel
nil
£2.7b
all
other
fossil
<0.5b
V
Existing (con-
struction on or
before 4/3/72
All
All fossil
<4.0
VI
Existing (con-
struction on or
before 4/3/72
All
All
£5.0
VII
Existing (con-
struction on or
before 4/3/72
>1000
All
£2.8
£1000
All
£5.0
la, 2a or 2c, 3d, 4d, 5b
00
-p.
1. HEAT INPUT DETERMINATION:
a~!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Technical Secretary in operating permit
2. TEST METHODS:
a. source testing:
b. fuel testing:
c. other testing:
Method 6 as specified in 40 CFR Part 60
(see Appendix A)
ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
specified in operating permit. Stack
testing by method contained in Chapter 3,
Source Sampling Manual, Tennessee
Department of Public Health, 1975
edition
Footnotes: See page 3, Tennessee
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Technical Secretary
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 1200-3-10-.02 (quarterly reports of excesses)
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 4
STATE: Tennessee (continued)
REGULATION:
Division of Air Pollution Control
Chapter 1200-3-14-.02
APPLICABILITY:
Area9
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
I
New (construction
after 4/3/72
£250
All fossil
£1.6
II. VI, and VII
New (construction
after 4/3/72
£250
All fossil
£5.0
III
New (construction
after 4/3/72
£250
All fossil
£2.4
V
New (construction
after 4/3/72
£250
All fossil
£4.0
Statewide
New (construction
after 4/3/72
>250
Liquid Solid
fossil
£.80 £1.2
Statewide
NSPS, after 8/17/71 or 9/18/72
(New)
>250
NSPS, see Appendix A
NSPS, see Appendix A
la. 2a or 2c, 3d, 4d, 5b
CO
en
1. HEAT INPUT DETERMINATION:
;Tunit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous SOZ monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Technical Secretary in operating permit
2.
TEST METHODS:
a. source testing: Method 6 as specified 1n 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM
other:
(distillate or liquid)
c. other testing:
specified in operating permit. Stack
testing by method contained 1n Chapter 3,
Source Sampling Manual, Tennessee
Department of Public Health, 1975
Edition
Footnotes: See page 3, Tennessee
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Technical Secretary
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 1200-3-10-.02 (quarterly reports of excesses)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 3
EPA region: 4 State: Tennessee (continued)
Footnotes:
aClass I - Polk
Class II - Maury and Humphreys
Class III - Sullivan
Class IV - Shelby
Class V - Anderson, Davidson, Hamilton, Hawkins, Knox, Rhea
Class VI - All counties not specifically classified
Class VII - Roane
Emission limit when using combination fuel:
Qcn = 4-Qx + 2.7y + Q.5z whefe Q = Allowable Emissions (Ibs. S09/MMBtu)
oup x i y T z oup £-
x = heat input (coal)
y = heat input (#5 or #6 fuel oil)
z = heat input from all other fuel
00
cr>
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Illinois
REGULATION: Rule 204
APPLICABILITY:
Area*
New/Existing
FACILITY SIZE
(MMBtu/hr
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
MMA
Existing (construction on or before 8/80
>250 <250
Solid fossil Solid fossil
<1.8 Ibs SO./MMBtu <6.8 Ibs SO,/MMBtu
la. 2c, 3d, 4b, 5b, 5d
Statewide
New (construction
All
Solid fossil
-------
g 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
Regulations)
OO
00
EPA REGION: 5 STATE: Illinois (continued)
REGULATION: Rule 204
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New (construction after 8/80)
£250
Solid
fossil
£1.8
Residual
oil
...
Distillate
oil
£0.3
>250
Solid Residual Distillate
fossil oil oil
£l.2 £l.O £0.3
la, 2c, 3d, 4b, 5b, 5d
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: continuous S02 monitoring if requested by the Agency
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTM _
ASTM _
ASTM __
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing: specified by the Agency
Footnotes: See page 3, Illinois
5.
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 107 (annual reports of emission quantity)
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
EPA region: 5
State: Illinois (continued)
00
10
Footnotes:
*Refers to fuel combustion sources located in Chicago, St. Louis, and Peoria Metropolitan Areas.
**where: E = allowable S02 emissions (Ibs./hr.) from all emission sources at one source which
is located within a 1 mile radius from the center point of such emission source.
H, = average actual stack height in feet.
a
HQ = effective height of effluent release = H + AH.
c a
AH = plume rise.
***where: E = allowable S02 emission (Ibs./hr.)
Ss = solid fuel standard (Ibs./MMBtu)
Sr = residual fuel standard (Ibs./MMBtu)
H = actual heat input (MMBtu/hr. solid)
H = actual heat input (MMBtu/hr. residual)
Hd = actual heat input (MMBtu/hr. distillate)
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Indiana
REGULATION: Air Pollution Control Board,
325 IAC 7-1, Sections 2, 3, 4
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MHBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (construction on or before 6/19/79)
>500
(Includes all sources with potential to emit
^10 Ibs S02/hr or >_25 tons S02/yr
All fossil
£6.0 and attain NAAQS for S02
Ic, 2a, 3b, 3c or 3d, 4a, 4b, 5b (1)
Statewide
New (construction after 6/19/79)
<500
All fossil
<6.0 and attain NAAQS for S02
le, 2a, 3c or 3d, 4a, 5b (2)
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified
MONITORING REQUIREMENTS:
a"! continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: procedures approved by the Board
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60
(see Appendix A)
ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
c. other testing:
Footnotes:
a
National Ambient Air Quality Standard for SO,.
"Storage and Retrieval or Aerometric Data.
REPORTING:
iTspecified in 40 CFR Part 60 (see Appendix A)
b. state regulation: (1) 325.IAC Section 4 (quarterly reporting of continuous
ambient SO, data to SAROAD ) & (2) 325 IAC Section 6 (performance test
results ana non-compliance procedures)
c. specified In 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Michigan
REGULATION:
Air Pollution Control General
Rule 336.1401, Rule 401, 402
APPLICABILITY:
Area
New/Existing
Compliance Date
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
1/1/81
£500,000 Ib steam/hr
Coal
<1.5* S
or
<2.4 Ibs
502/MMBtu
Oil
£l.5X S
~ or
<1.7 Ibs
I02/MMBtu
>500,000 Ib steam/hr
Coal
<1.0« S
or
<1.6 Ibs
502/MMBtu
Oil
<1.0« S
~ or
<1.1 Ibs
502/MMBtu
la, 2a, 2c, 3a , 4a, 4b, 5a, 5b, 5d
Statewide
NSPS, new after 8/17/71 or 9/18/78
t
N.A.
>250 MMBtu/hr
NSPS, see Appendix A
NSPS, see Appendix A
la, 2a, 3a, 4a, 4b, 5a, 5b, 5d
1. HEAT INPTJT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
Fcontinuous S02 monitoring by 40 CFR Part 60 (see Appendix A)>
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
b. fuel testing: ASTM
ASTM _
ASTM _
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing: specified by the Director
Footnotes: See page 2, Michigan
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour for continuous monitoring data
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 336.202 (annual reports by November 15 of
pertinent Information to determine compliance
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
EPA region: 5
State: Michigan (continued)
Footnotes:
a
Calculated on basis of following fuel heating value: solid: 13,000 Btu/lb;
liquid: 18,000 Btu/lb.
^Continuous monitoring required if source has unit heat input greater than
250 MMBtu/hr and has pollution abatement device installed.
IX)
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Minnesota
REGULATION: ARC 4, 6 MCAR §4.004, and APC 32
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Minneapolis - St. Paul
New & Existing
>IOO but <250 per unit, and
~250 total heat Input
Liquid fossil
£1.6
Statewide
Existing (construction on or before 1/1/80)
<250 total
ITeat input
Solid
fossil
<4.0
Liquid
fossil
£2.0
>250 total
heat input
Solid
fossil
<3.0
Liquid
fossil
<1.6
Statewide
New (construction after 1/1/80)
<250 total
Tfeat Input
Solid
fossil
<4.0
Liquid
fossil
<2.0
>250 total
heat input
Solid
fossil
£1.2
Liquid
fossil
-------
Pg. 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION:
5
STATE:
Minnesota
(continued)
REGULATION:
ARC
4, 6 MCAR
§4
004
and ARC
32
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Outside Minneapolis - St. Paul
New & Existing
>250 total heat input
Solid fossil
<4.0
Liquid fossil
£2.0
City of Duluth
New & Existing
>250 total
Solid fossil
<4.0
Liquid fossil
£2.0
Statewide
New & Existing
As applicable
Combination fuels
y(a) + z(b)
x + y + z
la, lc, 2a or 2c, 3d, 4a, 5b
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr) N.A. for direct heating
equipment
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: if choosing compliance by derating, continuous monitoring
of boiler steam flow
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR
Part 60, see Appendix A
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM
other:
(distillate or liquid)
c. other testing: Director's approval. If choosing
compliance by derating3, determine
actual heat input in Btu/hr, during
each test period.
Footnotes: See page 3, Minnesota
4. AVERAGING TIME:
a. specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour (if choosing compliance by derating)
c. 2 hours (arithmetic average)
d. other:
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: 6 MCAR §4.004 I (for derating)
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
EPA region: 5 State: Minnesota (continued)
Footnotes:
aDerating means limitation of heat input and corresponding steam output capacity.
bw = maximum allowable S02 emissions (Ibs/MMBtu).
x, y, z = percent of total heat input derived from gaseous, liquid, and solid fossil fuels, respectively.
a = applicable S02 emissions (Ibs/MMBtu) for liquid fossil fuels.
b = applicable S02 emissions (Ibs/MMBtu) for solid fossil fuels.
-------
Pg. 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Ohio
REGULATION: Rule 3745-18-06 (General Provisions)
and Rule 3745-18-07 (Example3 see
attachment)
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New after 8/17/71 or 9/18/78
>250
NSPS, see Appendix A
NSPS, see Appendix A
la, 2a, 3a, 4a, 4d, 5a, 5d
Example: Adam County3
New & Existing
All
Coal
_<3.6
All other fossil (source specific3)
(Source specific8)
Ib, 2b, 2c, 3a or 3c, 4a, 4d, 5b, 5d
i-D
cr>
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a~!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 30 day (arithmetic average) of daily compliance averages
other: sulfur & heat content (daily) by EPA
methods
c. other testing: Determine emission rate from fuel sulfur 5.
c content:
(solid) ER = (1 x 10°) (5) (1.9) ER = daily actual emission
H g ra te
(liquid) ER = (1 x 10 ) (D) (5) (1.974) H = heat content in Btu/lb
H <; . S = percent sulfur content
(gaseous) ER = (1 x 10°) (D) (S) (1.998) n = density of the fuel
U (Ibs/gal)
Footnotes: See page 2, Ohio
REPORTING:
a^specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 3745-18-04(6)
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
EPA region: 5 State: Ohio (continued)
Footnotes:
aEach county has source specific regulations with no general rules or guidelines.
See Rules 3745-18-06 through 3745-18-94 for specific emissions limitations. All
sources are allowed 2 days in excess of the (county) emission limitations per
30 day period. Example county used is Adam County.
vo
-------
Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION:
STATE: Wisconsin
REGULATION: NR 154.12
APPLICABILITY:
Area8
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Brokow RACT
Construction on or before 1/1/80
All FFFSGC with S <160
(S=stack height in ft.)
Liquid Fossil
<0.22% S
All other combustion
sources with S <160 (S=
stack height 1n ft.)
Liquid Fossil
<3.0% S
Madison RACT
Construction on or before 11/1/79
>25 but <100
Mf1Btu/hr
Solid or combina-
tion of solid,
liquid or gaseous
fossil
<0.52 S
Tdi still ate),
100 MHBtu/hr
Solid or combina-
tion of solid,
liquid or gaseous
fossil
<4.25
Tt S02/MMBtu
All other boilers >100 MMBtu/hr:
S <180, 180 < S > 720, S >220
(S = stack heiqht(s) 1n ft.)
Solid or combination of solid,
liquid or gaseous fossil
<2.5
Tb SO,/
MMBtiT
X = 10
(0.0089(s)-
1.18)
(see footnote d
la, 2a or 2c, 3d, 4a or 4d, 5b
<5.8
Tbs SO,/
HMBtu
CO
1. HEAT INPUT DETERMINATION:
a7unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the department
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
see Appendix A
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: specified by the department
Footnotes: See page 3, Wisconsin
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified 1n "ASME Performance Test Code 27", 1957
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: NR 154.06 (annual reports of pertinent Information
request to determine compliance)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 2
SO, EMISSION LIMITATIONS FROM FUEL BURKING INSTALLATIONS
(SIP Regulations)
EPA REGION: 5
STATE: Wisconsin (continued)
REGULATION: NR 154.12
APPLICABILITY:
Area8
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing (construction after 4/1/72)
>Z50
Solid fossil
£1.2
Liquid fossil
_<0.8
Southeast Wisconsin Intrastate
New & Existing
£250
Coal
<1.1
la. 2a or 2c, 3d, 4a or 4d, 5b
10
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR
Part 60. see Appendix A
ASTM (coal or solid)
ASTM
ASTM "
other:
(residual or liquid)
(distillate or liquid)
c. other testing: specified by the Department
Footnotes: See page 3, Wisconsin
4. AVERAGING TIME:
JLspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified in "ASME Performance Test Code 27", 1957
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: NR 154.06 (annual reports of pertinent information
request to determine compliance)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Pg. 3
EPA Region: 5 State: Wisconsin (continued)
Footnotes:
a"Air Quality Control Region:
Brokow RACT - Brokow Village and Marathon County
Madison RACT - City of Madison and Dane County
"Reasonably Available Control Technology"
c"Fossil Fuel Fired Steam Generator"
dWhere x = IDS SCWMMBtu heat input
s = stack neight in ft.
o
o
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 6
STATE: Arkansas
REGULATION: Air Pollution Control, Section 5 and
' Section 8
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(HHBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
All fossil
Attain NAAQS*
la, 2c, 3e, 4a, 5b
Statewide
NSPS, New after 8/17/71 or
9/18/78
>250
NSPS. See Appendix A
NSPS, See Appendix A
la, 2a. 3a, 4a, 5a, 5b
Statewide
Existing (Applicable
40 CFR 51 Source)
See Appendix B
See Appendix B
Attain NAAQS*
la, 2a, 2b or 2c, 3d, 4a, 4d, 5b
5c
1. HEAT INPUT DETERMINATION:
a~!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS':
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified in 40 CFR Part 51 (see Appendix B)
e. as determined necessary by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: specified in 40 CFR Part 51
(see Appendix B).
other testing: specified by the Director
Footnotes: . .
*Source must not cause the National Ambient Air Quality Standard
for SO- to be exceeded; emissions limit specific to Individual
source operating permit.
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) for source testing
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified in 40 CFR Part 51 (see Appendix B) for continuous
monitoring data
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 7 (biannual reports on 11/30 and 5/31 of each
year)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 1
S02 EMISSION LIMITATIONS FROM F.UEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 6
STATE: Louisiana
REGULATION: Department of Health and Human
Resources RuTe 24
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
All fossil fuels
<2,000 ppm by volume at standard
conditions (see footnote a)
Ib, 2a or 2c, 3d, 4d, 5b
Statewide
NSPS, New after 8/17/71
or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2a, 3a. 4a, 5a, 5b
Statewide
Existing
Applicable 40 CFR 51 Source
See Appendix B
See Appendix B
See Appendix B
la, 2a, 3a, 4d, 5b, 5c
o
ro
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr) see footnote b
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing:
ASTM
ASTM
ASTM ~
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing:
One of the following (see attachment)
or approved by the Department
Footnotes: See page 2, Louisiana
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 3 hrs. (arithmetic average)
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 17 (semi-annual reports by 1/20 and 7/20 of all
applicable data (emission type, amount, quantity)
c. specified in 40 CF8 Part 51 (see Appendix B)
d. specified by the Director
-------
EPA Region: 6 State: Louisiana (continued)
2.c. other testing (continued):
1) Seidman, Analytical Chemistry Volume 30, page 1680 (1958) "Determination of Sulfur Oxides
in Stack Gases".
2) Shell Development Company method for the Determination of Sulfur Dioxide and Sulfur Trioxide
PHS 999 AP-13 Appendix B, pages 85-87 "Atmospheric Emissions Sulfuric Acid Manufacturing
Processes".
3) Reich Test for Sulfur Dioxide. "Atmospheric Emissions from Sulfuric Acid Manufacturing Process"
PHS 999 AP-13 Appendix B, pages 76-80.
4) The Modified Monsanto Company Method. "Atmospheric Emissions from Sulfuric Acid Manufacturing
Process" PHS 999 AP-13, Appendix B, pages 61-67.
Footnotes:
aA gas at 21°C (70°F) and 29.92 inches of mercury.
Heat input refers to actual measurement determined by the product of heating value of fuel and
the quantity of fuel burned in tons/hour.
-------
Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 6
STATE: New Mexico
REGULATION: Air Quality Control Regulation 602 and 605
APPLICABILITY:
Area
New/Existing
Compliance Date
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing
(on or before 12/31/82)
>250 but < 3,000
Coal
emit <50% of SOp
produced
(footnote a)
la, 2a, 2c, 3a, 3c, 4a,
Statewide
Existing
(on or before 12/31/84)
>250 but £ 3,000
Coal
emit <40% of S02
produced or
<6,000 Ibs S0?/hr
Tfootnote b)
4d, 5a, 5b
Statewide
Existing
(on or before 12/31/81)
>3,000 but <5,000'
Coal
emit <40% S02
produced
(footnote a)
Statewide
Existing
(after 12/31/81)
>3,000 but <5,000
Coal
emit <28% S02
produced
(footnote a)
Statewide
Existing
(after 12/31/84) if >2 units/source
>250
Coal
emit <28% S02
produced or
total S02 ^17,900 (footnotes
Ibs/hr for source a and b)
o
-p.
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
ASTM (coal or solid)
(residual or liquid)
(distillate or liquid)
ASTM _
ASTM _
other:
other testing: performance testing at Director's
request, not more than 1 per year (by
Method 6).
Footnotes: See page 3, New Mexico
4. AVERAGING TIME:
J!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: daily average of fuel sulfur content.
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 602 (continuous S02 data, rate of actual heat
input (daily average), percent sulfur fuel (daily average). Report quarterly)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 6
STATE:
New Mexico
(Continued)
REGULATION: Air Quality Control Regulation 602 and 605
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MHBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Compliance for new and existing units
on or before 12/31/82
>25 MW generating capacity or >250
Vintage 1, 2, or 3C
Fuel Oil
£1.2
MMBtu/hr
Vintage 4C
Fuel Oil
<0.34
Statewide
Compliance for new and existing units
after 12/31/82
>25 MW generating capacity or >250 MMBtu/hr
Vintage 1, 2, or 3C
Fuel Oil
<0.55 (30 day average)d
la, 2a, 2c, 3a, 3c, 4a, 4c, 5a, 5b
o
en
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a.
b.
source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
fuel testing: ASTM (coal or solid)
ASTM
ASTM "
other:
(residual or liquid)
(distillate or liquid)
other testing: performance testing at Director's
request, not more than 1 per year
(by Method 6).
Footnotes: See page 3, New Mexico
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: daily average of fuel sulfur content.
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 602 (continuous SOg data,..rat* of actual heat
input (daily average), percent sulfur fuel (daily average). Report quarterly).
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 3
EPA Region: 6 State: New Mexico (continued)
Footnotes:
Averaged over 30 days for all similar sized units (percent reduction basis).
Not to be exceeded more than once per year.
Vintage refers to date beginning commercial operation:
Vintage 1 - began operation between 12/31/76 and 10/31/79.
Vintage 2 - began operation between 11/1/79 and 3/31/82.
Vintage 3 - began operation between 4/1/82 and 12/31/82.
Vintage 4 - other coal burning equipment which is not Vintage 1, 2, or 3.
Refers to a 30 day average of continuous S02 monitor hourly data average.
o
en
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION:
6
STATE:
Oklahoma
REGULATION:
16
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (constructed on or
before 6/22/74)
All
All fossil
Attain NAAQSa for SO. or source meets
New Source emission limits.
la, 3b, 5b or New Source guidelines
If >250 MMBtu/hr
Statewide
New (constructed after 6/22/74)
>250
NSPS, See Appendix A
NSPS, See Appendix A
la. 2a, 2b. 3a. 4a. 5a
£250
See Appendix A
See Appendix A
la, 2c, 3c, 4c, 5b
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (NMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
T. continuous S02 nonitoring by 40 CFR Part-60 (see Appendix A)
b. ambient monitoring or diffusion estinate
c. sulfur content of fuel
d. other:
2. TEST MEMOOS:
a. source testing: Method 6 as specified in 40 CFR Part 60.
See Appendix A.
b. fuel testing: ASIM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other: commissioner's approval
c. other testing: as specified in 36 FR 159, 8/17/71
(CFR 466.26).
Footnotes:
aSource does not cause or contribute to any S02 NAAQS violation.
AVERAGING IIHE:
jT specified in 40 CF.R Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
T. specified in 40 CER Part 60 (see Appendix A)
b. state regulation: Section 13.1 (Existing)
Not specified (New)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
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Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 6
STATE: Texas
REGULATION:
Texas Air Control Board,
Regulation II, 131.04
APPLICABILITY:
Area (County)
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Galveston & Harris
New & Existing
All
All fossil
Equivalent emissions3
and <0.28 ppm, net ground
leveT concentration
Ib. 2c, 3d, 4d, 5b
Jefferson & Orange
New & Existing
All
All fossil
Equivalent emissions3
and <0.32 ppm, net ground
leveT concentration
Statewi de
New & Existing
All
Solid fossil
<3.0 Ibs. S02/MMStu
and <0.4 ppm, net
ground level
concentration
Statewide
New & Existing
All
Liquid fossil
<440 ppm SOo by
volume and <0.4 ppm,
net ground Tevel
concentration
Statewide
NSPS, New after
8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
o
CD
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr) .
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Board of the Executive Director.
2. TEST METHODS:
a. source testing: Method 6 as specified 1n 40 CFR Part 60,
See Appendix A.
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: specified by the Board of the Executive
Director or alternate methods on approval.
Methods shall be those commonly used in the
field of air pollution control.
Footnotes: See pane 2. Texas
AVERAGING TIME;
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: not specified.
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: General Rules 31, Ch. 101.8 and Ch. 101.10 (Report test
results as specified by the Executive Director).
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 2
EPA Region: 6 State: Texas (continued)
Footnotes:
a
Refers to an emission rate which would not exceed the specified net ground level concentration averaged over
a 30 minute period.
Actual heat-input = heating value of fuel X quantity of fuel burned in tons/hour.
o
UD
-------
Hage 1
SO?
EMISMUN LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 7
STATE: Iowa
REGULATION: IAC Environmental Quality
Department 400 Title I
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Black Hawk, Clinton, Des Moines, Dubuque, Jackson, Lee, Linn, Louisa, Muscatine, Scott counties
Existing (constructed on or before 9/23/70)
All
Solid fossil
£6.0
All
Liquid fossil
£2.5
la, 2a, 2b, 2c, 3d, 4c, 5b
HEAT INPUT. DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CER Part 60 (see Appendix A)
b. ambient monitoring or diffus-ron- estimate
c. sulfur content of fuel
d. other: specified by Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR, Pt. 60,
(see Appendix A).
b. fuel testing: ASTHD2015-66 (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: Method 6 as specified in "Compliance
Sampling Manual", May 19, 1977. Iowa
Environmental Quality Department.
5.
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
specified in 40 CFR Part 60 (see Appendix A)
state regulation: 400-5.1 (455B) Excess emissions reporting and monthly
reporting requirements.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
Page 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 7
STATE: Iowa
REGULATION: IAC Environmental Quality
Department 400 Title I
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs SOg/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (constructed on
or before 9/23/70)
>SOO
Solid fossil
<5.0
All
Liquid fossil
<2.5
Statewide
New (constructed after
9/23/70)
<250
Solid fossil
<6.0
All
Liquid fossil
<2.5
la. 2a, 2b, 2c. 3d, 4c, 5c
Statewide
NSPS. New after 8/17/71
or 9/18/78
>250
NSPS. See Appendix A
NSPS. See Appendix A
la, 2a, 3a, 4a, 5a
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by Director
2. TEST METHODS:
a. source testing: Method 6 as specified 1n 40 CFR, Pt. 60,
(see Appendix A).
b. fuel testing: ASTHD2015-66coal or solid) ,
ASTM (residual or liquid)" ,
ASTM (distillate or liquid)
other:
c other testing- Method 6 as specified in "Compliance
Sampling Manual". May 19. 1977. Iowa
Environmental Quality Department
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state.regulation: 400-5.1 (455B) Excess emissions reporting and monthly
reporting requirements.
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regu.lations)
EPA REGION: 7
STATE: Kansas
REGULATION:
Air Pollution Emission Controls
28-19-31
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing
(construction on or before 1/1/71)
Equipment which operates >2000 hrs/yr.
All
All fossil (except natural gas)
<1.5 Ibs S/MMBtu (if annual emissions
Increase by a factor of 2 or more)
Ic, 2b, 2c, 3d, 4d, 5b
Statewide
New
(construction after 1/1/71)
>250 MHBtu/hr
All fossil
<1.5 Ibs S/MMBtu
ro
1. HEAT INPUT DETERMINATION:
sTunit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr) or manufacturer's,
d. total plant actual or operating (MMBtu/hr) whichever is
e. other: greater
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CER Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTHp-271-6ftcoal or solid) or D-2015-66
ASTMtj-24jj-66''esidual or liquid)
ASTM (distillate or liquid)
other: approved by the Department
c. other testing: as specified by the Director
Footnotes:
aRefers to 1971 emissions or the first 12 months of operation.
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by the Director
5. REPORTING:
T. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 28-19-8 (type and amount of fuel burned,
emission rate as specified by the Director).
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 7
STATE: Missouri
REGULATION- Division 10 CSR 10, Chapter 2,
Chapter 3, Chapter 4, Chapter 5,
'Chapter 6.070
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Kansas City
New and Existing
>350,000 Btu/hr.
All fossil
<9.0
Id. 2a, 2b, 2c.
3c. 4a, 5b & 5d
St. Louis
New and Existing
(Compliance by 3/24/70)
>2,000 MMBtu/hr.
All fossil
<4.8
Ic, 2a, 2b, 2c, 3c,
4a, 4d, 5b & 5d
Springfield - Green County
New and Existing
>350.000 Btu/hr.
All fossil
<9.2
Outstate Missouri Area
New and Existing
>350,000 Btu/hr.
All fossil
<12.9
Id, 2a, 2b. 2c. 3c, 4a. 5b & 5d
Statewide
New after
8/17/71 or
9/18/7S (NSPS)
>250
MMBtu/hr.
NSPS, See
Appendix A
NSPS, See
Appendix A
la, 2a, 3a,
4a a 4d, Sa
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr) or manufacturers,
whichever is greater.
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60.
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A) 3 tests (hours).
b. 1 hour arithmetic average
c. 2 hours (arithmetic average)
b. fuel testing: ASTMD.3JHr7&:oal or solid)sulfur content -. .. . * ~.~.~y-, ,„ J J .. „. - . -„
ASTHpi29-64(residual or liquid)sulfur content d. other: 3 hours for continuous SO. data as specified 1n 40 CFR Part 60
ASTMQi22r£4(di still ate or liquid)sulfur content (see Appendix A).
other: heat content (solid) by ASTMD (2015-66)
& (liquid) by ASTM 0(240-64).
c. other testing: 5. REPORTING:
specified by the Director a"!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Chapter 2.130. 3.130, 4.120, 5.210 (semi-annual
reports)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 7
STATE: Nebraska
REGULATION- Air Pollution Control Rule 9
& Rule 4
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
All fossil
<2.5
la or le, 2a, 2c, 3a, 3d, 4a, 5b, 5d
Statewide
NSPS, New after 8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2a, 2c, 3a, 4a, 5a, 5d
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr) or manufacturer's, whichever
b. unit actual or operating (MMBtu/hr) is greater.
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: or aggregate heat content of all fuels burned,
whichever is greater
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified by 40 CFR Part 60,
see Appendix A.
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing:
at Director's request if noncompliance
is suspected.
4. AVERAGING TIME:
a"! specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a~. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 3 (periodic reports of fuel quantity, emission
rate).
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
-
STATE: Colorado
-
REGULATION:
Air Quality Control,
Regulation 1, Section A
APPLICABILITY:
Area
New/Existing
FACILITY SUE
(NMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (construction on or before 1/30/79)
<300
>300
coal
,,.
*.
<300
>300
oil
*.
<0.8
<300
>300
gaseous
**
<0.8
Statewide
NSPS. after 8/17/71 or 9/18/78. and other new
fuel burning units constructed after 1/30/79
<250
>250
coal"
*.
<0.4
<250
>250
Oil
<0.8
5.0.3
<250
>250
gaseous
<0.8
<0.35
la. 2a. 2c, 3a. 4a, 4c, 5a
1. HEAT INPUT DETERMINATigN:
a^unit design rated (HHBtu/hr)
b. unit.actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a! continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ancient Monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified In 40 CFR Part 60.
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM
ASTM "
other:
(residual or liquid)
(distillate or liquid)
c. other testing: equivalent methods as specified by
the Department
Footnotes: See page 2, Colorado
4. AVERAGING TIME:
a^specified in 40 CFR Part 60 (see Appendix A) for continuous SO, data
b. 1 hour
c. 2 hours (arithmetic-average) for Method & or equivalent method
d. other:
5. REPORTING:
a. specified in 40 CER Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
STATE: Colorado
REGULATION:
Air Quality Control,
Regulation 1, Section A
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
>250
Combination fossil fuels
pr _ Y(0.3)+Z(0.4)
JS02 Y+Z
(footnote b)
la, 2a, 2c, 3a, 4a, 4c, 5a
CT>
HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: equivalent methods as specified by
the Department
Footnotes: See page 3, Colorado
5.
AVERAGING TIME:
a~!specified in 40 CFR Part 60 (see Appendix A) for continuous S0~ data
b. 1 hour
c. 2 hours (arithmetic average) for Method 6 or equivalent method
d. other:
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
EPA Region: 8 State: Colorado (continued)
Footnotes:
aThis Includes sources converted from other fuels to coal.
To determine emissions limit: where PS^Q = prorated emission limit in Ibs. SOg/MMBtu,
Y = percentage of total heat input (liquid).
Z = percentage of total heat input (solid).
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
SIATE: Montana
REGULATION: Air Quality Rule 16.8.1411
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
(comply after 7/1/72)
>1
solid or liquid fossil
<1.0 Ibs S/MMBtu
Ib, 2c, 3d, 4d, 5b, 5d
Statewide
NSPS, New after 8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2a, 3a, 4a, 5a, 5d
CO
1. HEAT INPUT DETERMINATION:
a"!unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: data specified by Director recorded hourly
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A)
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM "
other:
(distillate or liquid)
other testing: as specified by the Director's written
request, and new sources should employ
Best Available Control Technology (BACT)
5.
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: as specified by the Director
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Rule 16.8.704
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
so,
EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
STATE: North Dakota
REGULATION: Chapter 33-15-06-01
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
All
All fossil
<3.0 Ibs S02/MMBtu
Ic, 2a, 3a, 3c, 4a, 5a
1. HEAT INPUT DETERMINATION: 3
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr) manufacturer's
d. total plant actual or operating (MMBtu/hr) guaranteed max.
e. other:
MONITORING REQUIREMENTS:
alcontinuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM
ASTM "
other:
(residual or liquid)
(distillate or liquid)
c. other testing:
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
iTspecified in 40 CFR Part 60 (see
A)
a. auci. i i icu in tu wi n mi i> uw vacc nuu« . '• . .
b state regulation- Chapter 33-15-12, NSPS General Provisions (where
applicable). Annual emission Inventory, yearly, judged
on case-by-case basis.
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
STATE: South Dakota
REGULATION: 44:10:06:03 and 44:10:09:04
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
All fossil
<3.0 Ibs S02/MMBtu
la, 2c. 3d, 4a, 5d
Statewide
NSPS, New after 8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2a, 3a, 4a, 5a
ro
o
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)or manufacturer, whichever
b. unit actual or operating (MMBtu/hr) is greater
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a"!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified
2. TEST METHODS:
a. source testing: Method 6 as specified 1n 40 CFR Part 60
b. fuel testing:
ASTM
ASTM
ASTM
other:
c. other testing: specified by Director
(coal or solid)
(residual or liquid)
(distillate or liquid)
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
STATE: Utah
REGULATION: Air Conservation Regulations
(Part IV. Section 4.2)
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
EUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5. listed below)
Statewide
New and Existing
All
coal fuel oil
<1.0 Ibs S/MMBtu <0.85 Ibs S/MMBtu
Ib. 2a. 2b, 2c. 3d. 4a, 5b
Statewide
NSPS. New after 8/17/71 or 9/18/7B
>250 1
NSPS. See Appendix A
NSPS, See Appendix A
la. 2a. 2b, 2c. 3a, 4a, 5a. 5b
ro
1. HEAT INPUT DETERMINATION:
iTunit design rated (MMBtu/hr)
b. unit actual or operating (HMBtu/hr)
c. total plant design rated (HMBtu/hr)
d. total plant actual or operating (HMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous SOZ monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: not specified
2. TEST HETXODS: 4.
a. source testing: Method 6 as specified In 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
otherrippli cable ASTM Method
c. other testing: mandatory every 5 years, source must 5.
be at maximum combustion rate during
test
AVERAGING TIME:
T.specified in 40 CER Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other:
REPORTING:
T.specified in 40 CER Part 60 (see Appendix A)
b. state regulation: Sections 2.2 and 3.5 (annual emission Inventory
Including emission type, quantity, rate, control equipment used (for
sources emitting >25 tons/yr SO.})
c. specified in 40 CFff Part 51 (see'Appendl* B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 8
STATE: Wyoming
REGULATION: Air Quality Regulation Section 4
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
Ibs S02/MMBtu
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
Existing (construction on or
before 1/1/74)
>250 but
<2500
coal
I1-2
>2500 but
<5000
coal
<0.5
>5000
coal
<0.3
la, 2a or 2c. 3d, 4a, 5b, 5d
Statewide
New (construction after 1/1/74)
>250
coal fuel oil
<0.2 <0.8
la, 2a, 3a, 4a, 5a
ro
ro
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)or manufacturer's, whichever
b. unit actual or operating («MBtu/hr) is greater.
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CF8 Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Director
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM - - - - -
other:
(distillate or liquid)
c. other testing: each stack test by Method 6 or approved
equivalent test will consist of 3
separate runs.
4. AVERAGING TIME:
JLspecified in 40 CFR Part 60 (see Appendix A)(arithmetic mean of 3 test
b. 1 hour runs)
c. 2 hours (arithmetic average)
d. other:
5. REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: section 19 (excesses & equipment malfunction)
c. specified in 40 CER Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 9
STATE: Arizona
REGULATION:
Air Pollution Control Commission.
Chapter 3, Title 9, R9-3-524
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MNBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
IDS S02/HHBtu
COMPLIANCE PROCEDURES
(1-5. listed*elow)
Statewide
Existing (constructed on or
before 5/30/72)
All
Solid or low
sulfur oil*
<1.0
High sulfur
011**
<2.2
Statewide
New (constructed after
5/30/72)
All
Solid or low
sulfur oil*
<0.8
Ic, le, 2b, 2c. 3d, 4d. 5b
Statewide
NSPS. New after 8/17/71 or
9/18/78
>250
NSPS, See Appendix A
NSPS. See Appendix A
Ic, le. 2a or 2c, 3a, 4a. 4d. 5a. 5b
INS
CO
1. HEAT INPUT DETERMINATION:
T. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: Aggregate heat content of all fuels whose products
of combustion pass through a stack.
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CFR Part 60 (see Appendix A) or state
b. ambient monitoring or diffusion estimate reference method
c. sulfur content of fuel
d. other: as specified by the Department
2. TEST METHODS: 4. AVERAGING TIME:
a. source testing: Method b as specified in 40 CFR Part 60, T.specified in 40 CFR Part 60 (see Appendix A) (continuous SO, data 4
(see Appendix A). b. 1 hour Method 6) i
b. fuel testing: ASTM D-271 (coal or solid) or ASTM D-2-15 c. 2 hours (arithmetic average)
ASTM (residual or liquid) (heat content)d. other: 3 hr. average and as specified In "Arizona Testing Manual"
ASTM .(distillate or liquid)
other:
c. other testing: Test methods in "Arizona Testing Manual"
or other methods as approved by the
Department.
Footnotes:
*Low sulfur oi
is <.90 percent by weight sulfur content.
**H1gh sulfur oil is ^.90 percent by weight sulfur content.
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: R9-3-314 (excess emissions) R9-3-30B (periodic reports)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
Page 1
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 9
STATE: California
REGULATION: See specific Rule numbers under
"Source Applicability" in each
APCD.
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Bay Area
Rule # 9-1-304
New & Existing
All
All fossil
<300 ppm or
<0.5% S
Sacramento
Rule # 15
New & Existing
All
Solid &
liquid fossil
<0.5% S
gaseous
<50 qr/
100 cu.
ft. fuel
input
San Diego
Rule # 62
New & Existing
All
Solid & gaseous
liquid fossil
<0.5% S <10 gr/
100 cu.
ft. fuel
input
Fresno
Rule It 408
New & Existing
All
All fossil
<200 Ibs S02/hr
South Coast
Rule # 431.2, 116d
New & Existing
All
Solid
fossil
<0.56
Tb SO,,/
MMBtu
Liquid
fossil
<0.5% S
le, 2c, 3d. 4d, 5e
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: specified by applicable APCD
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by applicable APCD requirements
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
AST.M
ASTM "
(residual or liquid)
(distillate or liquid)
other:
c. other testing: specified by applicable APCD method
Footnotes: See page 3, California
AVERAGING TIME:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by applicable APCD requirements
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
e. specified by applicable APCD requirements
-------
Page 2
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 9
STATE: California
REGULATION: See specific Rule numbers under
"Source Applicability" 1n each
APCD."
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
NSPS, New after 8/17/71 or 9/18/78
>2SO MHBtu/hr
NSPS. See Appendix A
NSPS, See Appendix A
la, 2a, 3a, 4a, 5a
ro
en
1. HEAT INPUT DETERMINATION:
T. unit design rated (MHBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. ' ' -
e.
total plant actual or operating (MMBtu/hr)
other: specified by applicable APCD
3. MONITORING REQUIREMENTS:
a!continuous S02 monitoring by 40 CFR Part 60 (see-Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by applicable APCD requirements
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: specified by applicable APCD method
Footnotes: See page 3, California
4. AVERAGING TIME:
Fspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified by applicable APCD requirements
5. REPORTING:
T.splclfied in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
e. specified by applicable APCD requirements
-------
Page 3
EPA Region: 9
State: California (continued)
Footnotes:
aRefers to Air Pollution Control Districts. There are 15 APCD's in
California and each applicable district's regulations should be
consulted to determine specific test methods, averaging times, and
reporting requirements. Emission limitations are expressed for
individual counties in each district. Typical APCD regulations
limit SCL emissions and fuel sulfur contents to 200 Ibs./hr. and
0.5% sulfur by weight, respectively. The districts specifically
mentioned are examples.
CTl
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 9
STATE: Hawaii
REGULATION: Chapter 43, Vol. II, Section 14
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
All fossil
<2.0« S
la. 2c. 3d, 4d, 5b
ro
1. HEAT INPUT DETERMINATION:
«Tunit design rated (HHBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
¥!continuous S0% Monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient Monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing:
b. fuel testing: ASTM
ASTM ~
ASTM ~
other:
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing: as specified by the Department
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: not specified
5. REPORTING:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. state regulation:
c.
d.
Section 3, 4 and Section 342-22 (as specified by
the Department).
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
Page 1
S02
EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 9
STATE: Nevada
REGULATION: Air Quality Regulation, Article 8
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
40 CFR 51 sources
<250 Btu/hr.
All fossil
Y = 0.7 x
(Ibs. S/MMBtu)
see footnote a
excluding applicable
>250 Btu/hr.
All fossil
(or combination)
Y _ L(0.4) + S(0.6)
L + S
(Ibs. S/MMBtu)
see footnote a
Ib, 2c. 5b, 5c. 5d
Statewide
New and Existing
Applicable 40 CFR 51, Appendix B Sources
See Appendix B
See Appendix B
See Appendix B
(Ibs. S02/MMBtu)
la, 2c, 3a, 4a, 5b, 5c, 5d
ro
oo
HEAT INPUT DETERMINATION:
a. unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFB Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: continuous S02 monitoring by 40 CFR Part 51 (see Appendix B)
2.
TEST METHODS:
a. source testing:
b. fuel testing:
4.
ASTM _
ASTM
ASTM "
other?
(coal or solid)
(residual or liquid)
(distillate or liquid)
c. other testing: testing specified by the Director prior 5.
to permit issuance or renewal. Recognized
methods will be used and two separate runs
of the test procedure are required
Footnotes: See page 2, Nevada
AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: specified in 40 CFR Part 51 (see Appendix B)
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Section 2.6-2.17 (excess emissions)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
EPA Region: 9 State: Nevada (continued)
Footnotes:
awhere X = operating heat input in MMBtu/hr.
Y = allowable rate of five emissions in Ibs/hr.
L « percentage of total heat Input (liquid fuel).
S = percentage of total heat input (solid fuel).
ro
vo
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 10
STATE: Alaska
REGULATION: Title 18, Chapter 50, Article 1.050
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
All fossil
<500 ppm SO, by volume,
dry basis determination
laa or lba, 2a, 2b, 3d, 4d, 5b, 5d
OJ
o
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
MONITORING REQUIREMENTS:
a~!continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate if sulfur content 0.7 percent
c. sulfur content of fuel
d. other: specified in permit
2. TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60,
(see Appendix A) with unit at maximum
ASTM (coal or solid) capacity.
ASTM
ASTM "
(residual or liquid)
(distillate or liquid)
other: sulfur, ash, moisture content
c. other testing:
Footnotes:
Specified in permit to operate.
4. AVERAGING TIME:
T.specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: 3 hour average
REPORTING:
T. specified in 40 CFR Part BO^see^Appendix A)
b. state regulation: •'--'•
SectiorTlOri.d
c.
d.
specified in 40 CFR Part 51 (see Appendix B)
specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 10
STATE: Idaho
REGULATION: Air Pollution Control Title 1,
Ch. 1, Rule 1351 through 1355
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MHBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing
All
Coal
<1.0% S
le. 2b,
1. HEAT INPUT DETERMINATION:
a. unit design rated (HMBtu/h
b. unit actual or operating (
c. total plant design rated (
d. total plant actual or oper
e. other: not specified for c
Residual
fuel oil
<1.75X S
Distil
ASTM grad
late fuel
e 1
<0.3X S
AS1
oil
FM grade 2
<0
5% S
2c, 3c, 4d, 5b
Statewide
NSPS. New after 8/17/71 or 9/18/78
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2b, 3a or 3c, 4a or 4d, 5b
3. MONITORING REQUIREMENTS:
r) au continuous S02 monitoring by 40 CER Part 60 (see Appendix A)
MMBtu/hr) b. ambient monitoring or diffusion estimate
MHBtu/hr) c. sulfur content of fuel
ating (MMBtu/hr) d. other:
ompliance purposes
2.
TEST METHODS:
a. source testing:
b. fuel testing:
Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
ASTHD271-6E(coa1 or solid)
ASTMDTSBT-ep-esidual or liquid)or D129-64 or
ASTMDTFSr-eBJi still ate or liquid) D1552-
other!or 0129-64 or 01552-64
heating value and ash content once per week
c. other testing: Test procedures 1n "Procedures Manual b.
for Air Pollution Control", Idaho
Department of Health and Welfare.
AVERAGING TIME:
a. specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d other: Dally for fuel analysis, other specified
•64
by the Director
REPORTING:
a. specified in 40 CFR Part 60 (see Appendix A) , ,
b. state regulation: Rule 1005 (periodic reports) and Rule 1954 (monthly
summary of estimated SO, emissions)
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION: 10
STATE: Oregon
REGULATION: Chapter 340, Division 22
APPLICABILITY:
Area
New/Existing
nthpr
FACILITY SIZE
(MHBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New & Existing
Must comply by 1/1/72
uncontrolled
All
Distil la
(ASTM Gn
1
<0.3% S
te
ide)
2
<0.5X S
Statewide
New & Existing
After 1/1/74
uncontrolled
All
coal
150 but <250
solid
1.4 Ibs.
SO,/MMBtu
(footnote b)
liquid
1.6 Ibs.
SO,/MMBtu
(f&otnote b)
la, 2c, 3b, 3d, 4c, 5b
Statewide
NSPS, New construction
N.A.
>250
NSPS, See Appendix A
NSPS, See Appendix A
la, 2c, 3d, 3b, 4c, 5b
GO
ro
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other:
3. MONITORING REQUIREMENTS:
a. continuous S02 monitoring by 40 CFR Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other: specified by the Department
2. TEST METHODS:
a. source testing: Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
b. fuel testing: ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
c. other testing: any method accepted by the Department
Refers to a source using no SO. pollution abatement devices.
Controlled sources may use higner sulfur content coal if
equivalent emission rate to sulfur restrictions can be
achieved on approval by the Department.
Refers to maximum emission rate for 2 hour average (using actual
heat input for testing).
4. AVERAGING TIME:
a"!specified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average) during emission test
d. other: not specified
5. REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: Division 20 (semi-annual basis and test results as
requested by the Director
c. specified in 40 CFR Part 51 (see Appendix B)
d. specified by the Director
-------
S02 EMISSION LIMITATIONS FROM FUEL BURNING INSTALLATIONS
(SIP Regulations)
EPA REGION:
10
STATE:
Washington
REGULATION:
WAS 173-400-040
APPLICABILITY:
Area
New/Existing
FACILITY SIZE
(MMBtu/hr)
FUEL TYPE
EMISSIONS LIMIT
COMPLIANCE PROCEDURES
(1-5, listed below)
Statewide
New and Existing fuel burning units
(includes Wigwam and hog fuel boilers also)
All
All fossil fuels and wood waste
<1,000 ppm*
le, 2c, 3b, 4d, 5b
Statewide
New after
NSPS
8/17/71 or 9/18/78
>250
NSPS, See
NSPS, See
la. 2a, 3a
Appendix A
Appendix A
, 3b, 4a, 5b, Sc
co
co
1. HEAT INPUT DETERMINATION:
T.unit design rated (MMBtu/hr)
b. unit actual or operating (MMBtu/hr)
c. total plant design rated (MMBtu/hr)
d. total plant actual or operating (MMBtu/hr)
e. other: not specified
MONITORING REQUIREMENTS:
T.continuous S02 monitoring by 40 CER Part 60 (see Appendix A)
b. ambient monitoring or diffusion estimate
c. sulfur content of fuel
d. other:
2. TEST METHODS:
a. source testing:
b. fuel testing:
c. other testing:
Footnotes:
L
Method 6 as specified in 40 CFR Part 60,
(see Appendix A).
ASTM (coal or solid)
ASTM (residual or liquid)
ASTM (distillate or liquid)
other:
source testing at the request of the
Director by procedures contained in
"Source Test Manual - Procedures for
Compliance Testing", State of Washington,
Department of Ecology.
4. AVERAGING TIME:
SLspecified in 40 CFR Part 60 (see Appendix A)
b. 1 hour
c. 2 hours (arithmetic average)
d. other: not specified
REPORTING:
T.specified in 40 CFR Part 60 (see Appendix A)
b. state regulation: WAC 173-400-120 (annual emission Inventory with
estimated quarterly emissions.
*Exhaust gas volume is corrected to 7 percent oxygen.
c.
d.
specified in 40 CFR Part 51 (see Appendix B) for SO, continuous
specified by the Director monitoring equipment
-------
134
-------
References
1. Sargent, D.H., et al. Effect of Physical Coal Cleaning on Sulfur
Content and Variability, Versar, Inc., Springfield, VA, EPA 600/7-80-107,
May 1980, pg. 66.
2. "Compilation of Air Pollution Emission Factors," Supplement No. 6,
Environmental Protection Agency, AP-42, April 1976, P. 1.1-3.
3. "Steam/Its Generation and Use," Babcock and Wilcox, New York, NY,
1975, P. 5-11 and 5-19.
135
-------
136
-------
Appendix A. Federal New Source Performance Standard Criteria
Sources subject to Federal fuel combustion source sulfur dioxide ($02)
regulations follow the guidelines contained In 40CFR60, July 1979 ~ The
applicable emission limitations, testing and reporting proceedures are
reproduced for your convenience from Subpart D, Subpart Da, and Appendix A
(Reference Method 6 -Determination of S02 Emissions From Stationary Sources).
Chapter I—Environmental Protection Agency
§60.42
Subpart D—Standards of Perform-
ance for Fossil-Fuel-Fired Steam
Generators for Which Construction
Is Commenced After August 17,
1971
and designation of
$60.40 Applicability
affected facility.
(a) The affected facilities to which
the provisions of this subpart apply
are:
(1) Each fossil-fuel-fired steam gen-
erating unit of more than 73
megawatts heat input rate (250 million
Btu per hour).
(2) Each fossil-fuel and wood-resi-
due-fired steam generating unit capa-
ble of firing fossil fuel at a heat input
rate of more than 73'megawatts (250
million Btu per hour).
(b) Any change to an existing fossil-
fuel-fired steam generating unit to ac-
commodate the use of combustible ma-
terials, other than fossil fuels as de-
fined in this subpart, shall not bring
that unit under the applicability of
this subpart.
(c) Except as provided in paragraph
(d) of this section, any facility under
paragraph (a) of this section that com-
menced construction or modification
after August 17, 1971. is subject to the
requirements of this subpart.
(d) The requirements of
JJ 60.44(a)(4), (a)(5), (b) and (d). and
60.45(f)(4)(vi) are applicable to lignite-
fired steam generating units that com-
menced construction or modification
after December 22,1976.
(e) Any facility covered under Sub-
part Da is not covered under this Sub-
part.
(Sees. 111. 114. and 301(a), Clean Air Act;
Sec. 4(a) of Pub. L. 91-604. 84 Stat. 1683;
sec. 2 of Pub. L. 90-148. 81 Stat. 504 (42
U.S.C. 1857c-6. 1857g(a), 7411. 7414. and
7601))
[42 PR 37936. July 25, 1977. as amended at
43 FR 9278. Mar. 7, 1978; 44 PR 33612. June
17.19793
§ 60.41 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act. and in Subpart
A of this part.
(a) "Fossil-fuel fired steam generat-
ing unit" means a furnace or boiler
used in the process of burning fossil
fuel for the purpose of producing
steam by heat transfer.
(b) "Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from
such materials for the purpose of cre-
ating useful heat.
(c) "Coal refuse" means waste-prod-
ucts of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob,
etc.) containing coal, matrix material,
clay, and other organic and inorganic
material.
(d) "Fossil fuel and wood residue-
fired steam generating unit" means a
furnace or boiler used in the process
of burning fossil fuel and wood residue
for the purpose of producing steam by
heat transfer.
(e) "Wood residue" means bark, saw-
dust, slabs, chips, shavings, mill trim,
and other wood products derived from
wood processing and forest manage-
ment operations.
(f) "Coal" means all solid fuels clas-
sified as anthracite, bituminous, subbi-
tuminous, or lignite by the American
Society for Testing Material. Designa-
tion D 388-66.
(Sees. Ill and 301(a), Clean air Act. as
amended (42 U.S.C. 7411. 7414. and 7601))
[39 FR 20791, June 14, 1974, as amended at
40 FR 2803, Jan. 16. 1975; 41 FR 51398. Nov.
22. 1976; 43 FR 9278, Mar. 7. 1978)
§ 60.42 Standard for paniculate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which:
(1) Contain particulate matter in
excess of 43 nanograms per joule heat
input'(0.10 Ib per million Btu) derived
from fossil fuel or fossil fuel and wood
residue.
(2) Exhibit greater than 20 percent
opacity except for one six-minute
period per hour of not more than 27
percent opacity.
(Sec. Ill, 301(a). Clean Air Act as amended
(42U.S.C. 7411, 7601))
[39 FR 20792. June 14. 1974. as amended at
41 FR 51398. Nov. 22. 1976: 42 FR 61537.
Dec. 5. 1977]
A-l
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§ 60.43
Title 40—Protection of Environment
§ 60.43 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which
contain sulfur dioxide in excess of:
(1) 340 nanograms per joule 'heat
input (0.80 Ib per million Btu) derived
from liquid fossil fuel or liquid fossil
fuel and wood residue.
(2) 520 nanograms per joule heat
input (1.2 Ib per million Btu) derived
from solid fossil fuel or solid fossil fuel
and wood residue.
-------
Chapter I—Environmental Protection Agency
§60.45
[39 FR 20792. June 14. 1974. as amended at
41 FR 51398. Nov. 22. 1976: 43 FR 9278. Mar.
7.19781
§ 60.45 Emission and fuel monitoring.
(a) Each owner or operator shall in-
stall, calibrate, maintain, and operate
continuous monitoring systems for
measuring the opacity of emissions.
sulfur dioxide emissions, nitrogen
oxides emissions, and either oxygen or
carbon dioxide except as provided in
paragraph (b) of this section.
(b) Certain of the continuous moni-
toring system requirements under
paragraph (a) of this' section do not
apply to owners or operators under
the following conditions:
(1) For a fossil fuel-fired steam gen-
erator that burns only gaseous fossil
fuel, continuous monitoring systems
for measuring the opacity of emissions
and sulfur dioxide emissions are not
required.
(2) For a fossil fuel-fired steam gen-
erator that does not use a flue gas de-
sulfurization device, a continuous
monitoring system for measuring
sulfur dioxide emissions is not re-
quired if the owner or operator moni-
tors sulfur dioxide emissions by fuel
sampling and analysis under para-
graph (d) of this section.
(3) Notwithstanding §60.13(b). in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed until after the initial perform-
ance tests under § 60.8 have been con-
ducted. If the owner or operator dem-
onstrates during the performance test
that emissions of nitrogen oxides are
less than 70 percent of the applicable
standards in § 60.44, a continuous mon-
itoring system for measuring nitrogen
oxides emissions is not required. If the
initial performance test results show
that nitrogen oxide emissions are
greater than 70 percent of the applica-
ble standard, the owner or operator
shall install a continuous monitoring
system for nitrogen oxides within one
year after the date of the initial per-
formance tests under § 60.8 and
comply with all other applicable moni-
toring requirements under this part.
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen
oxides, as provided under paragraphs
(b)
-------
§60.45
of this section, the following conver-
sion procedures shall be used to con-
vert the continuous monitoring data
into units of the applicable standards
(ng/J, Ib/million Btu):
(1) When a continuous monitoring
system for measuring oxygen is select-
ed, the measurement of the pollutant
concentration and oxygen concentra-
tion Shall each be on a consistent basis
(wet or dry). Alternative procedures
approved by the Administrator shall
be used when measurements are on a
wet basis. When measurements are on
a dry basis, the following conversion
procedure shall be used:
£=CF[20.9/20.9—percent O,]
where:
E, C, F. and %O» are determined under
paragraph (f) of this section.
(2) When a continuous monitoring
system for measuring carbon dioxide is
selected, the measurement of the pol-
lutant concentration and carbon diox-
ide concentration shall each be on a
consistent basis (wet or dry) and the
following conversion procedure shall
be used:
£=CfcUOO/percent CO,)
where:
E, C. Pt and %CO2 are determined under
paragraph (f) of this section.
(f) The values used in the equations
under paragraphs (e) (1) and (2) of
this section are derived as follows:
(1) £=pollutant emissions, ng/J (lb/
million Btu).
(2) C= pollutant concentration, ng/
dscm (Ib/dscf), determined by multi-
plying the average concentration
(ppm) for each one-hour period by
4.15x10' M ng/dscm per ppm
(2.59xlO~9 M Ib/dscf per ppm) where
M= pollutant molecular weight, g/g-
mole (Ib/lb-mole). M=64.07 for sulfur
dioxide and 46.01 for nitrogen oxides.
(3) %O,, %CO2 = oxygen or carbon
dioxide volume (expressed as percent),
determined with equipment specified
under paragraph (d) of this section.
(4) F, Fc = a factor representing a
ratio of the volume of dry flue gases
Title 40—Protection of Environment
generated to the calorific value of the
fuel combusted (F), and a factor repre-
senting a ratio of the volume of
carbon dioxide generated to the calo-
rific value of the fuel combusted (Fc),
respectively. Values of F and Fc are
given as follows:
(i) For anthracite coal as classified
according to A.S.T.M. D 388-66, F=
2.723x10-" dscm/J (10,140 dscf/mil-
lion Btu) and ^=0.532x10-" scm
CO,// (1,980 scf CDs/million Btu).
(ii) For subbituminous and bitumi-
nous coal as classified according to
A.S.T.M. D 388-66, F= 2.637x10-'
dscm/J (9,820 dscf/million Btu) and
Fc=0.486xlO-' scm CO,// (1,810 scf
CO,/million Btu).
(iii) For liquid fossil fuels including
crude, residual, and distillate oils,
F= 2.476x10-' dscm/J (9,220 dscf/mil-
lion Btu) and .FV=0.384x10-' scm CO,/
J (1,430 scf CO,/million Btu).
(iv) For gaseous fossil fuels, F= 2.347
x 10-' dscm/J (8,740 dscf/million Btu).
For natural gas, propane, and butane
fuels, Ft = 0.279x10-' scm CO,/J (1.040
scf CO,/million Btu) for natural gas,
0.322x10-' scm CO,// (1.200 scf CO,/
million Btu) for propane, and
0.338x10-' scm CO,// (1,260 scf CO,/
million Btu) for butane.
(v) For bark F=^2.589x10-' dscm/J
(9,640 dscf/million Btu) and Fc=0.500
xlO-' scm CO,/J (1,840 scf CO,/ mil-
lion Btu). For wood residue other than
bark F=2.492xlQ-' dscm/J (9.280
dscf/million Btu) and Fc=0.494xlO-'
scm CO,/J (1,860 scf CO,/ million
Btu).
(vi) For lignite coal as classified ac-
cording to A.S.T.M. D 388-66,
F=2.659xlO-' dscm/J (9900 dscf/mil-
lion Btu) and Fc=0.516xlO-'scm CO,/
J (1920 scf CO2/million Btu).
(5) The owner or operator may use
the following equation to determine
an F factor (dscm/J or dscf/million
Btu) on a dry basis (if it is desired to
calculate F on a wet basis, consult the
Administrator) or Fr factor (scm CO,/
J, or scf COj/million Btu) on either
basis in lieu of the F or Ff factors spec-
ified in paragraph (f)(4) of this sec-
tion:
r .«.. 1227.2 (pet.
r-iv
.r)..r» (pet.
5.0 (prt. S)+8.7 (|>ct. N)-28.7 (pet. 0)1
A-4
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•I Protection Agency
§6045
(SI unite)
GCV
(English unitn)
„
20.0(%C)
GCV
(SI units)
_321X10»(%C)
GCV
(English units)
(1) H, C, S. N, and O are content by
weight of hydrogen, carbon, sulfur, ni-
trogen, and oxygen (expressed as per-
cent), respectively, as determined on
the same basis as GCV by ultimate
analysis of the fuel fired, using
A.S.T.M. method D3178-74 or D3176
(solid fuels), or computed from results
using A.S.T.M. methods D1137-53(70).
D1945-64C73). or D1946-67(72) (gas-
eous fuels) as applicable.
(ii) GCV is the gross calorific value
(kJ/kg, Btu/lb) of the fuel combusted,
determined by the A.S.T.M. test meth-
ods D2015-66(72) for solid fuels and D
1826-64(70) for gaseous fuels as appli-
cable.
(iii) For affected facilities which fire
both fossil fuels and nonfossil fuels,
the F or Fr value shall be subject to
the Administrator's approval.
(6) For affected facilities firing com-
binations of fossil fuels or fossil fuels
and wood residue, the F or Fc factors
determined by paragraphs (f)(4) or
(f)(5) of this section shall be prorated
in accordance with the applicable for-
mula as follows:
'=SA'<
or
where:
X,=the fraction of total heat input de-
rived from each type of fuel (e,g. natu-
ral gas, bituminous coal, wood residue.
etc.)
Fi or (F,)i=the applicable F or F, factor
for each fuel type determined In ac-
cordance with paragraphs (f)(4) and
(f X5) of this section.
n=the number of fuels being burned In
combination.
(g) For the purpose of reports re-
quired under {60.7(c), periods of
excess emissions that shall be reported
are defined as follows:
(1) Opacity, Excess emissions are de-
fined as any six-minute period during
which the average opacity of emissions
exceeds 20 percent opacity, except
that one six-minute average per hour
of up to 27 percent opacity need not
be reported.
(2) Sulfur dioxide. Excess emissions
for affected facilities are defined as:
(i) Any three-hour period during
which the average emissions (arithme-
tic average of three contiguous one-
hour periods) of sulfur dioxide as
measured by a continuous monitoring
system exceed the applicable standard
under § 60.43.
(3) Nitrogen oxides. Excess emissions
for affected facilities using a continu-
ous monitoring system for measuring
nitrogen oxides are defined as any
three-hour period during which the
average emissions (arithmetic average
of three contiguous one-hour periods)
exceed the applicable standards under
{ 60.44.
A-5
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§ 60.46
Title 40—Protection of Environment
(Sees. 111. 114. and 301
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Chapter I—Environmental Protection Agency
§ 60.41a
2015-66(72) (solid fuels). D 240-64(73)
(liquid fuels), or D 1826-64(7) (gaseous
fuels) as applicable. The method used
to determine calorific value of wood
residue must be approved by the Ad-
ministrator. The owner or operator
shall determine the rate of fuels
burned during each testing period by
suitable methods and shall confirm
the rate by a material balance over the
steam generation system.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7414))
(40 FR 46258. Oct. 6. 1975. as amended at 41
FR 53199. Nov. 22. 1976: 43 FR 8800, Mar. 3.
1978]
Subpart Da—Standards of Perform-
ance for Electric Utility Steam Gen-
erating Units for Which Construc-
tion Is Commenced After Septem-
ber 18, 1978
AUTHORITY: Sec. 111. 301(a) of the Clean
Air Act as amended (42 U.S.C. 7411.
7601(a», and additional authority as noted
below.
i
SOURCE: 44 FR. 33613, June 11, 1979, unless
otherwise noted.
§60.40a Applicability and designation of
affected facility.
(a) The affected facility to which
this subpart applies is each electric
utility steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel
(either alone or in combination with
any other fuel); and
(2) For which construction or modi-
fication is commenced after Septem-
ber 18, 1978.
(b) This subpart applies to electric
utility combined cycle gas turbines
that are capable of combusting more
than 73 megawatts (250 million Btu/
hour) heat input of fossil fuel in the
steam generator. Only emissions re-
sulting from combustion of fuels in
the steam generating unit are subject
to this subpart. (The gas turbine emis-
sions are subject to Subpart GG.)
(c) Any change to an existing fossil-
fuel-fired steam generating unit to ac-
commodate the use of combustible ma-
terials, other than fossil fuels, shall
not bring that unit under the applica-
bility of this subpart.
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to ac-
commodate the use of any other fuel
(fossil or nonfossil) shall not bring
that unit under the applicability of
this subpart.
§ 60.41a Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart
A of this part.
"Steam generating unit" means any
furnace, boiler, or other device used
for combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included).
"Electric utility steam generating
unit" means any steam electric gener-
ating unit that is constructed for the
purpose of supplying more than one-
third of its potential electric output
capacity and more than 25 MW electri-
cal output to any utility power distri-
bution system for sale. Any steam sup-
plied to a steam distribution system
for the purpose of providing steam to
a steam-electric generator that would
produce electrical energy for sale is
also considered in determining the
electrical energy output capacity of
the affected facility.
"Fossil fuel" means natural gas, pe-
troleum, coal, and any form of solid,
liquid, or gaseous fuel derived from
such material for the purpose of creat-
ing useful heat.
"Subbituminous coal" means coal
that is classified as subbituminous A,
B, or C according to the American So-
ciety of Testing and Materials'
(ASTM) Standard Specification for
Classification of Coals by Rank D388-
66.
"Lignite" means coal that is classi-
fied as lignite A or B according to the
American Society of Testing and Ma-
terials' (ASTM) Standard Specifica-
tion for Classification of Coals by
Rank D388-66.
"Coal refuse" means waste products
of coal mining, physical coal cleaning.
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
A-7
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§ 60.41a
Title 40—Protection of Environment
material, clay, and other organic and
inorganic material.
"Potential combustion concentra-
tion" means the theoretical emissions
(ng/J. Ib/million Btu heat input) that
would result from combustion of a fuel
in an uncleaned state 9without emis-
sion control systems) and:
(a) For particulate matter is:
(1) 3,000 ng/J (7.0 Ib/million Btu)
heat input for solid fuel; and
(2) 75 ng/J (0.17 Ib/million Btu)
heat input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/J (0.67 Ib/million Btu)
heat input for gaseous fuels;
(2) 310 ng/J (0.72 Ib/million Btu)
heat input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/million Btu)
heat input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion
system where heat from the turbine
exhaust gases is recovered by a steam
generating unit.
"Interconnected" means that two or
more electric generating units are elec-
trically tied together by a network of
power transmission lines, and other
power transmission equipment.
"Electric utility company" means
the largest interconnected organiza-
tion, business, or governmental entity
that generates electric power for sale
(e.g., a holding company with operat-
ing subsidiary companies).
"Principal company" means the elec-
tric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies
with one or more electric power inter-
connections to the principal company
and which have geographically adjoin-
ing service areas.
"Net system capacity" means the
sum of the net electric generating ca-
pability (not necessarily equal to rated
capacity) of all electric generating
equipment owned by an electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contractual pur-
chases that are interconnected to the
affected facility that has the malfunc-
tioning flue gas desulfurization
system. The electric generating capa-
bility of equipment under multiple
ownership is prorated based on owner-
ship unless the proportional entitle-
ment to electric output is otherwise es-
tablished by contractual arrangement.
"System load" means the entire elec-
tric demand of an electric utility com-
pany's service area interconnected
with the affected facility that has the
malfunctioning flue gas desulfuriza-
tion system plus firm contractual sales
to other electric utility companies.
Sales to other electric utility compa-
nies (e.g., emergency power) not on a
firm contractual basis may also be in-
cluded in the system load when no
available system capacity exists in the
electric utility company to which the
power is supplied for sale.
"System emergency reserves" means
an amount of electric generating ca-
pacity equivalent to the rated capacity
of the single largest electric generat-
ing unit in the electric utility company
(including steam generating units, in-
ternal combustion engines, gas tur-
bines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected
with the affected facility that has the
malfunctioning flue gas desulfuriza-
tion system. The electric generating
capability of equipment under multi-
ple ownership is prorated based on
ownership unless the proportional en-
titlement to electric output is other-
wise established by contractual ar-
rangement.
"Available system capacity" means
the capacity determined by subtract-
ing the system load and the system
emergency reserves from the net
system capacity.
"Spinning reserve" means the sum
of the unutilized net generating capa-
bility of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting addi-
tional load. The electric generating ca-
pability of equipment under multiple
ownership is prorated based on owner-
ship unless the proportional entitle-
ment to electric output is otherwise es-
tablished by contractual arrangement.
"Available purchase power" means
the lesser of the following:
A-8
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(a) The sum of available system ca-
pacity in all neighboring companies.
(b) The sum of the rated capacities
of the power interconnection devices
between the principal company and all
neighboring companies, minus the
sum of the electric power load on
these interconnections.
(c) The rated capacity of the power
transmission lines between the power
interconnection devices and the elec-
tric generating units (the unit in the
principal company that has the mal-
functioning flue gas desulfurization
system and the unit(s) in the neigh-
boring company supplying replace-
ment electrical power) less the electric
power load on these transmission
lines.
"Spare flue gas desulfurization
system module" means a separate
system of sulfur dioxide emission con-
trol equipment capable of treating an
amount of flue gas equal to the total
amount of flue gas generated by an af-
fected facility when operated at maxi-
mum capacity divided by the total
number of nonspare flue gas desulfuri-
zation modules in the system.
"Emergency condition" means that
period of time when: «
(a) The electric generation output of
an affected facility with a malfunc-
tioning flue gas desulfurization system
cannot be reduced or electrical output
must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being oper-
ated, and
(2) All available purchase power in-
terconnected with the affected facility
is being obtained, or
(b) The electric generation demand
is being shifted as quickly as possible
from an affected facility with a mal-
functioning flue gas desulfurization
system to one or more electrical gener-
ating units held in reserve by the prin-
cipal company or by a neighboring
company, or
(c) An affected facility with a mal-
functioning flue gas desulfurization
system becomes the only available
unit to maintain a part or all of the
principal company's system emergency
reserves and the unit is operated in
spinning reserve at the lowest practi-
cal electric generation load consistent
with not causing significant! physical
damage to the unit. If the unit is oper-
ated at a higher load to meet load
demand, an emergency condition
would not exist unless the conditions
under (a) of this definition apply.
"Electric utility combined "cycle gas
turbine" means any combined cycle
gas turbine used for electric genera-
tion that is constructed for the pur-
pose of supplying more than one-third
of its potential electric output capac-
ity and more than 25 MW electrical
output to any utility power distribu-
tion system for sale. Any steam distri-
bution system that is constructed for
the purpose of providing steam to a
steam electric generator that would
produce electrical power for sale is
also considered in determining the
electrical energy output capacity of
the affected facility.
"Potential electrical output capac-
ity" is defined as 33 percent of the
maximum design heat input capacity
of the steam generating unit (e.g., a
steam generating unit with a 100-MW
(340 million Btu/hr) fossil-fuel heat
input capacity would have a 33-MW
potential electrical output capacity).
For electric utility combined cycle gas
turbines the potential electrical
output capacity is determined on the
basis of the fossil-fuel firing capacity
of the steam generator exclusive of
the heat input and electrical power
contribution by the gas turbine.
"Anthracite" means coal that is clas-
sified as anthracite according to the
American Society of Testing and Ma-
terials' (ASTM) Standard Specifica-
tion for Classification of Coals by
Rank D388-66.
• "Solid-derived fuel" means any solid.
liquid, or gaseous fuel derived from
solid fuel for the purpose of creating
useful heat and includes, but is not
limited to, solvent refined coal, liqui-
fied coal, and gasified coal.
"24-hour period" means the period
of time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands.
Guam, American Samoa, the Com-
A-9
-------
monwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit
for the entire 24 hours.
§ 60.42a Standard Tor participate matter.
(a) On and after the date on which
the performance test required to be
conducted under § 60.8 is completed,
no owner or operator subject to the
provisions of this subpart shall cause
to be discharged into the atmosphere
from any affected facility any gases
which contain particulate matter in
excess of:
(1) 13 ng/J (0.03 Ib/million Btu)
heat input derived from the combus-
tion of solid, liquid, or gaseous fuel;
(2) 1 percent of the potential com-
bustion concentration (99 percent re-
duction) when combusting solid fuel;
and
(3) 30 percent of potential combus-
tion concentration (70 percent reduc-
tion^ when combusting liquid fuel.
(b) On and after the date the partic-
ulate matter performance test re-
quired to be conducted under § 60.8 is
completed, no owner or operator sub-
ject to the provisions of this subpart
shall cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than
20 percent opacity (6-minute average),
except for one 6-minute period per
hour of not more than 27 percent
opacity.
§ 60.43a Standard for sulfur dioxide.
(a) On and after the date on which
the initial performance test required
to be conducted under § 60.8 is com-
pleted, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the atmos-
phere from any affected facility which
combusts solid fuel or solid-derived
fuel, except as provided under para-
graphs (c), (d), (f) or (h) of this sec-
tion, any gases which contain sulfur
dioxide in excess of: ^
(1) 520 ng/J (1.20 Ib/million Btu)
heat input and 10 percent of the po-
tential combustion concentration (90
percent reduction), or
(2) 30 percent of the potential com-
bustion concentration (70 percent re-
duction), when emissions are less than
260 ng/J (0.60 Ib/million -Btu) heat
input.
(b) On and after the date on which
the initial performance test required
to be conducted under § 60.8 is com-
pleted, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the atmos-
phere from any affected facility which
combusts liquid or gaseous fuels
(except for liquid or gaseous fuels de-
rived from solid fuels and as provided
under paragraphs (e) or (h) of this sec-
tion), any gases which contain sulfur
dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu)
heat input and 10 percent of the po-
tential combustion concentration (90
percent reduction), or
(2) 100 percent of the potential com-
bustion concentration (zero percent re-
duction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat
input.
(c) On and after the date on which
the initial performance test required
to be conducted under § 60.8 is com-
plete, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the atmos-
phere from any affected facilitywhich
combusts solid solvent refined coal
(SRC-I) any gases which contain
sulfur dioxide in excess of 520 ng/J
(1.20 Ib/million Btu) heat input and 15
percent of the potential combustion
concentration (85 percent reduction)
except as provided under paragraph
(f) of this section; compliance with the
emission limitation is determined on a
30-day rolling average basis and com-
pliance with the percent reduction re-
quirement is determined on a 24-hour
basis.
(d) Sulfur dioxide emissions are lim-
ited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recov-
ery facility, or
(3) Is located in a noncontinental
area and combusts solid fuel or solid-
derived fuel.
(e) Sulfur dixoide emissions are lim-
ited to 340 ng/J (0.80 Ib/million Btu)
heat input from any affected facility
which is located in a noncontinental
A-10
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Chapter I—Environmental Protection Agency
§ 60.44c
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction require-
ments under this section do not apply
to any affected facility that is operat-
ed under an SOi commercial demon-
stration permit issued by. the Adminis-
trator in accordance with the provi-
sions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction re-
quirements under this section are both
determined on a 30-day rolling average
basis except as provided under para-
graph (c) of this section.
(h) When different fuels are com-
busted simultaneously, the applicable
standard is determined by proration
using the following formula:
(1) If emissions of sulfur dioxide to
the atmosphere are greater than 260
ng/J (0.60 Ib/million Btu) heat input
EM, = 1340 x + 520 y]/100 and
PSO, = 10 percent
(2) If emissions of sulfur dioxide to
the atmosphere are equal to or less
than 260 ng/J (0.60 Ib/million Btu)
heat input:
En, = [340 x + 520 y]/100 and
P«o,= C90x + 70y]/100
where:
EM, is the prorated sulfur dioxide emission
limit (ng/J heat input),
P»o, is the percentage of potential sulfur
dioxide emission allowed (percent reduc-
tion required = 100 — PSio,).
x is the percentage of total heat input de-
rived from the combustion of liquid or
gaseous fuels (excluding solid-derived
fuels)
y is the percentage of total heat input de-
rived from the combustion of solid fuel
(including solid-derived fuels)
5 60.44a Standard for nitrogen oxides.
(a) On and after the date on which
the initial performance test required
to be conducted under J60.8 is com-
pleted, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the atmos-
phere from any affected facility,
except as provided under paragraph
(b) of this section, any gases which
contain nitrogen oxides in excess of
the following emission limits, based on
a 30-day rolling average.
(1) NO. Emission Limits-
Fuel type
Emsnonkmrt
ng/J (Ib/nvllon Blu)
heat input
Gaseous Fuels
Coal-dewed fuels.
All other fuels
Liquid Fuels:
Cod-dewed fuels.
Shale oil .'....
All other fuels
Solid Fuels:
Coal-derived fuels,
Any fuel containing more than
210
210
210
130
210
(0.50)
(0.20)
(0.50)
(0.50)
(0.30)
(0.50)
25V by weight, coal refuse ..
Any fuel containing more than
25V by weight, lignite il the
lignite is mined in North
Dakota, South Dakota, or
Montana, and is combusted
in a slag tap furnace
Lignite not subject to the 340
ng/J heat input emission limn
SubbiUiminous coal ;
Bituminous coal
Anthracite coal
All olher fuels
Exempt from NO,
standards and NO.
monitoring
requirements
340 (0.80)
260 (0 60)
210 (0.50)
260 (0.60)
260 (0.60)
260 (0.60)
(2) NO,.reduction requirements-
Fuel type
Percent reduction
of potential
combustion
concentration
Gaseous fuels....
Liquid fuels
Solid fuels ,
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel
and is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(c) When two or more fuels are com-
busted simultaneously, the applicable
standard is determined by proration
using the following formula:
ENO| = [86 w + 130 x + 210 y + 260 zl/100
where:
ENOl is the applicable standard for nitrogen
oxides when multiple fuels are combust-
ed simultaneously (ng/J heat input);
w is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 86 ng/J heat input standard:
x Is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 130 ng/J heat input standard:
40-101
A-ll
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§ 60.45a
Title 40—Protection of Environment
y is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 210 ng/J heat input standard:
and
z is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 260 ng/J heat input standard.
§6(M5a Commercial demonstration
permit.
(a) An owner or operator of an af-
fected facility proposing to demon-
strate an emerging technology may
apply to the Administrator for a com-
mercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (e) of this section.
Commercial demonstration permits
may be issued only by the Administra-
tor, and this authority will not be dele-
gated.
(b) An owner or operator of an af-
fected facility that combusts solid sol-
vent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is not
subject to the SO2 emission reduction
requirements under § 60.43a(c) but
must, as a minimum, reduce SO2 emis-
sions to 20 percent of the potential
combustion concentration (80 percent
reduction) for each 24-hour period of
steam generator operation and to less
than 520 ng/J (1.20 Ib/million Btu)
heat input on a 30-day rolling average
basis.
(c) An owner or operator of a flui-
dized bed combustion electric utility
steam generator (atmospheric or pres-
surized) who is issued a commercial
demonstration permit by the Adminis-
trator is not subject to the SO2 emis-
sion reduction requirements under
§ 60.43a(a) but must, as a minimum,
reduce SO, emissions to 15 percent of
the potential combustion concentra-
tion (85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu) heat
input on a 30-day rolling average basis.
(d) The owner or operator of an af-
fected facility that combusts coal-de-
rived liquid fuel and who is issued a
commercial demonstration permit by
the Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a)
but must, as a minimum, reduce emis-
sions to less than 300 ng/J (0.70 lb/
million Btu) heat input on a 30-day
rolling average basis.
(e) Commercial demonstration per-
mits may not exceed the following
equivalent MW electrical generation
capacity for any one technology cate-
gory, and the total equivalent MW
electrical generation capacity for all
commercial demonstration plants may
not exceed 15,000 MW.
Technology
Equivalent
electrical
Pollutant capacity
(MW electrical
output)
Solid solvent refined coal
(SRC I)
Fluidized bed combustion
(atmosphenc)
Fluidized bed combustion
(pressurized)
Coal liquification
SO, 6.000-10.000
SO, 400-3.000
SO,
NO,
Total allowable for all
technologies
400-1.200
750-10,000
15.000
§ 60.46a Compliance provisions.
(a) Compliance with the particulate
matter emission limitation under
§ 60.42a(a)(l) constitutes compliance
with the percent reduction require-
ments for particulate matter under
§ 60.42a(a)(2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
§ 60.44a(a) constitutes compliance with
the percent reduction requirements
under § 60.44a(a)(2).
(c) The particulate matter emission
standards under § 60.42a and the nitro-
gen oxides emission standards under
§ 60.44a apply at all times except
during periods of startup, shutdown,
or malfunction. The sulfur dioxide
emission standards under § 60.43a
apply at all times except during peri-
ods of startup, shutdown, or when
both emergency conditions exist and
the procedures under paragraph (d) of
this section are implemented.
(d) During emergency conditions in
the principal company, an affected fa-
cility with a malfunctioning flue gas
desulfurization system may be operat-
ed if sulfur dioxide emissions are mini-
mized by:
(1) Operating all operable flue gas
desulfurization system modules, and
A-12
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Chapter I—Environmental Protection Agency
bringing back into operation any mal-
functioned module as soon as repairs
are completed.
(2) Bypassing flue gases around only
those flue gas desulfurization system
modules that have been taken out of
operation because they were incapable
of any sulfur dioxide emission reduc-
tion or which would have suffered sig-
nificant physical damage if they had
remained in operation, and
(3) Designing, constructing, and op-
erating a spare flue gas desulfurization
system module for an affected facility
larger than 365 MW (1.250 million
Btu/hr) heat input (approximately
125 MW electrical output capacity).
The Administrator may at his discre-
tion require the owner or operator
within 60 days of notification to dem-
onstrate spare module capability. To
demonstrate this capability, the owner
or operator must demonstrate compli-
ance with the appropriate require-
ments under paragraph (a), (b), (d),
(e). and (i) under $ 60.43a for any
period of operation lasting from 24
hours to 30 days when:
(i) Any one flue gas desulfurization
module is not operated,
(ii) The affected facility is operating
at the maximum heat input rate,
(iii) The fuel fired during the 24-
hour to 30-day period is representative
of the type and average sulfur content
of fuel used over a typical 30-day
period, and
(iv) The owner or operator has given
the Administrator at least 30 days
notice of the date and period of time
over which the demonstration will be
performed.
(e) After the initial performance test
required under § 60.8, compliance with
the sulfur dioxide emission limitations
and percentage reduction require-
ments under i 60.43a and the nitrogen
oxides emission limitations under
§ 60.44a is based on the average emis-
sion rate for 30 successive boiler oper-
ating days. A separate performance
test is completed at the end of each
boiler operating day after the initial
performance test, and a new 30 day
average emission rate for both sulfur
dioxide and nitrogen oxides and a new
percent reduction for sulfur dioxide
are calculated to show compliance
with the standards.
§ 60.47o
only). Compliance with the percentage
reduction requirement for SO, is de-
termined based on the average inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under
§ 60.47a of this subpart, compliance of
the affected facility with the emission
requirements under §§60.43a and
60.44a of this subpart for the day on
which the 30-day period ends may be
determined by the Administrator by
following the applicable procedures in
sections 6.0 and 7.0 of Reference
Method 19 (Appendix A).
§ 60.47a Emission monitoring.
(a) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output ,of the system, for measuring
the opacity of emissions discharged to
the atmosphere, except where gaseous
fuel is the only fuel combusted. If
opacity interference due to water dro-
A-13
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§ 60.47o
Title 40—Protection of Environment
plets exists in the stack (for example,
from the use of an FGD system), the
opacity is monitored upstream of the
interference (at the inlet to the PGD
system). If opacity interference is ex-
perienced at all locations (both at the
inlet and outlet of the sulfur dioxide
control system), alternate parameters
indicative of the particulate matter
control system's performance are mon-
itored (subject to the approval of the
Administrator).
(b) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted,
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet
of the sulfur dioxide control device.
(2) For a facility which qualifies
under the provisions of § 60.43a(d),
sulfur dioxide emissions are only mon-
itored as discharged to the atmos-
phere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirements of Method
19 (Appendix A) may be used to deter-
mine potential sulfur dioxide emis-
sions in place of a continuous sulfur
dioxide emission monitor at the inlet
to the sulfur dioxide control device as
required under paragraph (b)(l) of
this section.
(c) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged
to the atmosphere.
(d) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
the oxygen or carbon dioxide content
of the flue gases at each location
where sulfur dioxide or nitrogen
oxides emissions are monitored.
(e) The continuous monitoring sys-
tems under paragraphs (b), (c), and (d)
of this section are operated and data
recorded during all periods of oper-.
ation of the affected facility including
periods of startup, shutdown, malfunc-
tion or emergency conditions, except
for continuous monitoring system
breakdowns, repairs, calibration
checks, and zero and span adjust-
ments.
(f) When emission data are not ob-
tained because of continuous monitor-
ing system breakdowns, repairs, cali-
bration checks and zero and span ad-
justments, emission data will be ob-
tained by using other monitoring sys-
tems as approved by the Administra-
tor or the reference methods as de-
scribed in paragraph (h) of this sec-
tion to provide emission data for a
minimum of 18 hours in at least 22 out
of 30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph §60.13(h) are ex-
pressed in ng/J (Ibs/million Btu) heat
input and used to calculate the aver-
age emission rates under § 60.46a. The
1-hour averages are calculated using
the data points required under
§ 60.13(b). At least two data points
must be used to calculate the 1-hour
averages.
(h) Reference methods used to sup-
plement continuous monitoring
system data to meet the minimum
data requirements in paragraph
§ 60.47a(f) will be used as specified
below or otherwise approved by the
Administrator.
(1) Reference Methods 3, 6, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2) For Method 6, the minimum sam-
pling time is 20 minutes and the mini-
mum sampling volume is 0.02 dscm
(0.71 dscf) for each sample. Samples
are taken at approximately 60-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken
at approximately 30-minute intervals.
The arithmetic average of these two
consective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken
for each hour when continuous SO,
and NO,, data are taken or when Meth-
ods 6 and 7 are required. Each sample
shall be taken for a minimum of 30
minutes in each hour using the inte-
grated bag method specified in
A-14
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Chapter I—Environmental Protection Agency
§ 60.48o
Method 3. Each sample represents a 1-
hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J Ub/mil-
lion Btu) heat input are determined
and used as needed to achieve the
minimum data requirements of para-
graph (f) of this section.
(i) The following procedures are
used to conduct monitoring system
performance evaluations under
! 60.13(c) and calibration checks under
§ 60.13(d).
(1) Reference method 6 or 7, as ap-
plicable, is used for conducting per-
formance evaluations of sulfur dioxide
and nitrogen oxides continuous moni-
toring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under per-
formance specification 2 of appendix
B to this part.
(3) For affected facilities burning
only fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and
80 percent and for a continuous moni-
toring system measuring nitrogen
oxides is determined as follows:
Fossil fuel
Span value lor
nitrogen oxides (ppm)
Gas
Liquid
SoW
Combination..
500
SOO
1.000
500 (x + y)+ 1.0002
where:
x is the fraction of total heat input derived
from gaseous fossil fuel.
y is the fraction of total heat input derived
from liquid fossil fuel, and
z is the fraction of total heat input derived
from solid fossil fuel.
(4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels
are rounded to the nearest 500 ppm.
(5) For affected facilities burning
fossil fuel, alone or in combination
with non-fossil fuel, the span value of
the sulfur dioxide continuous monitor-
ing system at the inlet to the sulfur
dioxide control device is 125 percent of
the maximum estimated hourly poten-
tial emissions of .the fuel fired, and the
outlet of the sulfur dioxide control
device is 50 percent of maximum esti-
mated hourly potential emissions of
the fuel fired.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
§ 60.48a Compliance determination proce-
dures and methodx.
(a) The following procedures and
reference methods are used to deter-
mine compliance with the standards
for particulate matter under § 60.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method
17.
(2) Method 5 is used for determining
particulate matter emissions and asso-
ciated moisture content. Method 17
may be used for stack gas tempera-
tures less than 160 C (320 F). ^
(3) For Methods 5 or 17, Method 1 is
used to select the sampling site and
the number of traverse sampling
points. The sampling time for each
run is at least 120 minutes and the
minimum sampling volume is 1.7 dscm
(60 dscf) except that smaller sampling
times or volumes, when necessitated
by process variables or other factors,
may be approved by the Administra-
tor.
(4) For Method 5, the probe and
filter holder heating system in the
sampling train is set to provide a gas
temperature no greater than 160°C
(32°F).
(5) For determination of particulate
emissions, the oxygen or carbon-diox-
ide sample is obtained simultaneously
with' each run of Methods 5 or 17 by
traversing the duct at the same sam-
pling location. Method 1 is used for se-
lection of the number of traverse
points except that no more than 12
sample points are required.
(6) For each run using Methods 5 or
17, the emission rate expressed in ng/J
heat input is determined using the
oxygen or carbon-dioxide measure-
ments and particulate matter mea-
surements obtained under this section,
the dry basis Fc-factor and the dry
basis emission rate calculation proce-
dure contained in Method 19 (Appen-
dix A).
(7) Prior to the Administrator's issu-
ance of a particulate matter reference
method that does not experience sul-
furic acid mist interference problems,
particulate matter emissions may be
A-15
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§ 60.49o
Title 40—Protection of Environment
sampled prior to a wet flue gas desul-
f urization system.
(b) The following procedures and
methods are used to determine compli-
ance with the sulfur dioxide standards
under § 60.43a.
(1) Determine the percent of poten-
tial combustion concentration (percent
PCC) emitted to the atmosphere as
follows:
(i) Fuel Pretreatment (% Rf): Deter-
mine the percent reduction . achieved
by any fuel pretreatment using the
procedures in Method 19 (Appendix
A). Calculate the average percent re-
duction for fuel pretreatment on a
quarterly basis using fuel analysis
data. The determination of percent R,
to calculate the percent of potential
combustion concentration emitted to
the atmosphere is optional. For pur-
poses of determining compliance with
any percent reduction requirements
under § 60.43a, any reduction in poten-
tial SO2 emissions resulting from the
following processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.),
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System
(% /£<,): Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix
A); or, a combination of an "as fired"
fuel monitor and emission rates meas-
ured after the control system, follow-
ing the procedures in Method 19 (Ap-
pendix A). When the "as fired" fuel
monitor is used, the percent reduction
is calculated using the average emis-
sion rate from the sulfur dioxide con-
trol device and the average SO2 input
rate from the "as fired" fuel analysis
for 30 successive boiler operating days.
(iii) Overall percent reduction (%
R,): Determine the overall percent re-
duction using the results obtained in
paragraphs (b)(l) (i) and (ii) of this
section following the procedures in
Method 19 (Appendix A). Results are
calculated for each 30-day period
using the quarterly average percent
sulfur reduction determined for fuel
pretreatment from the previous quar-
ter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC): Calcu-
late the percent of potential combus-
tion concentration emitted to the at-
mosphere using the following equa-
tion: Percent PCC =100-Percent R0
(2) Determine the sulfur dioxide
emission rate's following the proce-
dures in Method 19 (Appendix A).
(c) The procedures and methods out-
lined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collect-
ed under § 60.47a to determine compli-
ance with the applicable nitrogen
oxides standard under § 60.44.
(d) Electric utility combined cycle
gas turbines are performance tested
for particulate matter, sulfur dioxide,
and nitrogen oxides using the proce-
dures of Method 19 (Appendix A). The
sulfur dioxide and nitrogen oxides
emission rates from the gas turbine
used in Method 19 (Appendix A) calcu-
lations are determined when the gas
turbine is performance tested under
subpart GG. The potential uncon-
trolled particulate matter emission
rate from a gas turbine is defined as 17
ng/J (0.04 Ib/million Btu) heat input.
§ 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen
oxides, and particulate matter emis-
sions, the performance test data from
the initial performance test and from
the performance evaluation of the
continuous monitors (including the
transmissometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following information is re-
ported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter; rea-
sons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the poten-
tial combustion concentration of
sulfur dioxide for each 30 successive
A-16
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Chapter I—Environmental Protection Agency
§ 60.49a
boiler operating days, ending with the
last 30-day period in the quarter, rea-
sons for non-compliance with the
standard; and. description of correc-
tive actions taken.
(4) Identification of the boiler oper-
ating days for which pollutant or dilu-
tent data have not been obtained by
an approved method for at least 18
hours of operation of the facility; jus-
tification for not obtaining sufficient
data; and description of corrective ac-
tions taken.
(5) Identification of the times when
emissions data have been excluded
from the calculation of average emis-
sion rates because of startup, shut-
down, malfunction (NO, only), emer-
gency conditions (SO, only), or other
reasons, and justification for exclud-
ing data for reasons other than star-
tup, shutdown, malfunction, or emer-
gency conditions.
(6) Identification of "F" factor used
for calculations, method of determina-
tion, and type of fuel combusted.
(7) Identification of times when
hourly averages have been obtained
based on manual sampling methods.
(8) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
system.
(9) Description of any modifications
to the continuous monitoring system
which could affect the ability of the
continuous monitoring system to
comply with Performance Specifica-
tions 2 or 3.
(c) If the minimum quantity of emis-
sion data as required by § 60.47a is not
obtained for any 30 successive boiler
operating days, the following informa-
tion obtained under the requirements
of §60.46a(h) is reported to the Ad-
ministrator for that 30-day period:
(1) The number of hourly averages
available for outlet emission rates (nc)
and inlet emission rates (n,) as applica-
ble.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,) as applica-
ble.
(3) The lower confidence limit for
the mean outlet emission rate (£„*)
and the upper confidence limit for the
mean inlet emission rate (E,*) as appli-
cable.
(4) The applicable potential combus-
tion concentration.
(5) The ratio of the upper confi-
dence limit for the mean outlet emis-
sion rate (£„•) and the allowable emis-
sion rate (EMU) as applicable.
(d) If any standards under {60.43a
are exceeded during emergency condi-
tions because of control system mal-
function, the owner or operator of the
affected facility shall submit a signed
statement:
(1) Indicating if emergency condi-
tions existed and requirements under
!60.46a(d) were met during each
period, and
(2) Listing the following informa-
tion:
(i) Time periods the emergency con-
dition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(iii) Amount of power purchased
from interconnected neighboring util-
ity companies during the emergency
period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate (ng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit
toward the sulfur dioxide emission
standard under § 60.43a is claimed, the
owner or operator of the affected fa-
cility shall submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the cal-
endar quarter, and whether the credit
was determined in accordance with the
provisions of § 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat con-
tent, and date each pretreated fuel
shipment was received during the pre-
vious quarter; the name and location
of the fuel pretreatment facility; and
the total quantity and total heat con-
tent of all fuels received at the affect-
ed facility during the previous quarter.
(f) For any periods for which opac-
ity, sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected fa-
cility shall submit a signed statement
indicating if any changes were made in
operation of the emission control
A-17
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§ 60.50
Title 40—Protection of Environment
system during the period of data una-
vailability. Operations of the control
system and affected facility during pe-
riods of data unavailability are to be
compared with operation of the con-
trol system and affected facility before
and following the period of data una-
vailability.
(g) The owner or operator of the af-
fected facility shall submit a signed
statement indicating whether:
(1) The required continuous moni-
toring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to show compli-
ance was or was not obtained in ac-
cordance with approved methods and
procedures of this part and is repre-
sentative of plant performance.
(3) The minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were unavoid-
able.
(4) Compliance with the standards
has or has not been achieved during
the reporting period. ,
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable opac-
ity standard and the date of such ex-
cesses are to be submitted to the Ad-
ministrator each calendar quarter.
(i) The owner or operator of an af-
fected facility shall submit the written
reports required under this section
and subpart A to the Administrator
for every calendar quarter. All quar-
terly reports shall be postmarked by
the 30th day following the end of each
calendar quarter.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
Subpart E—Standards of Performance
for Incinerators
§ 60.50 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to each incinerator of
more than 45 metric tons per day
charging rate (50 tons/day), which is
the affected facility.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after August
17, 1971, is subject to the requirements
of this subpart.
(Sees. Ill and 301(a), Clean Air Act; sec. 4a)
of Pub. L. 91-604, 84 Stat. 1683; sec. 2 of
Pub. L. 90-148, 81 Stat. 504 (42 U.S.C. 1857c-
6, 1857g(a)»
[42 FR 37936, July 25, 1977]
§ 60.51 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A of this part.
(a) "Incinerator" means any furnace
used in the process of burning solid
waste for the purpose of reducing the
volume of the waste by removing com-
bustible matter.
(b) "Solid waste" means refuse, more
than 50 percent of which is municipal
type waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other
combustibles, and noncombustible ma-
terials such as glass and rock.
(c) "Day" means 24 hours.
[36 FR 24877, Dec. 23, 1971, as amended at
39 FR 20792. June 14, 1974]
§ 60.52 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this part shall cause to be dis-
charged into the atmosphere from any
affected facility any gases which con-
tain particulate matter in excess of
0.18 g/dscm (0.08 gr/dscf) corrected to
12 percent CO*.
[39 FR 20792, June 14, 1974]
§ 60.53 Monitoring of operations.
(a) The owner or operator of any in-
cinerator subject to the provisions of
this part shall record the daily charg-
ing rates and hours of operation.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7414))
[39 FR 20792, June 14, 1974, as amended at
43 FR 8800, Mar. 3, 1978]
A-18
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Chapter I—Environmental Protection Agency
§60.54
§ 60.54 Test methods and procedures.
(a) The reference methods in Appen-
dix A to this part, except as provided
for in § 60.8(b), shall be used to deter-
mine compliance with the standard
prescribed in § 60.52 as follows:
(1) Method 5 for the concentration
of participate matter and the associat-
ed moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis and
calculation of excess air, using the in-
tegrated sample technique.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the minimum sample volume
shall be 0.85 dscm (30.0 dscf) except
that smaller sampling times or sample
volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator.
(c) If a wet scrubber is used, the gas
analysis sample shall reflect flue gas
conditions after the scrubber, allowing
for carbon dioxide absorption by sam-
pling the gas on the scrubber inlet and
outlet sides according to either the
procedure under paragraphs (c)(l)
through (c)(5) of this section or the
procedure under paragraphs (cXl),
(c)(2) and (c)(6) of this section as fol-
lows:
(1) The outlet sampling site shall be
the same as for the particulate matter
measurement. The inlet site shall be
selected according to Method 1, or as
specified by the Administrator.
(2) Randomly select 9 sampling
points within the cross-section at both
the inlet and outlet sampling sites. Use
the first set of three for the first run,
the second set for the second run, and
the third set for the third run.
(3) Simultaneously with each partic-
ulate matter run, extract and analyze
for CO, an integrated gas sample ac-
cording to Method 3. traversing the
three sample points and sampling at
each point for equal increments of
time. Conduct the runs at both inlet
and outlet sampling sites.
(4) Measure the volumetric flow rate
at the inlet during each particulate
matter run according to Method 2,
using the full number of traverse
points. For the inlet make two full ve-
locity traverses approximately one
hour apart during each run and aver-
age the results. The outlet volumetric
flow rate may be determined from the
particulate matter run (Method 5).
(5) Calculate the adjusted CO, per-
centage using the following equation:
(% CO,).a)=(% CO,),,, (Qa,/Qd.>
where:
C% CO,).^ is the adjusted CO, percentage
which removes the effect of CO, absorp-
tion and dilution air.
<% CO,)d, is the percentage of CO, meas-
ured before the scrubber, dry basis.
Qt, is the volumetric flow rate before the
scrubber, average of two runs, dscf/min
(using Method 2). and
Coo is the volumetric flow rate after the
scrubber, dscf/min (using Methods 2
and 5).
(6) Alternatively, the following pro-
cedures may be substituted for the
procedures under paragraphs (c) (3),
(4), and (5) of this section:
(i) Simultaneously with each partic-
ulate matter run, extract and analyze
for CO,, Oi, and N, an integrated gas
sample according to Method 3, travers-
ing the three sample points and sam-
pling for equal increments of time at
each point. Conduct the runs at both
the inlet and outlet sampling sites.
(ii) After completing the analysis of
the gas sample, calculate the percent-
age of excess air (% EA) for both the
inlet and outlet sampling sites using
equation 3-1 in Appendix A to this
part.
(iii) Calculate the adjusted CO» per-
centage using the following equation:
i = (% CO.)41
riOO+(%KA)i
|_100+<%BA),
where:
(% CO,).* is the adjusted outlet CO, per-
centage,
(% CO,)d, is the percentage of CO, meas-
ured before the scrubber, dry basis.
(% EA), is the percentage of excess air at
the inlet, and
(% EA). is the percentage of excess air at
the outlet.
(d) Particulate matter emissions, ex-
pressed in g/dscm, shall be corrected
to 12 percent CO» by using the follow-
ing formula:
c,,=l2e/%CO,
A-19
-------
§ 60.60
Title 40—Protection of Environment
where:
da is the concentration of particulate
matter corrected to 12 percent CO,, c is
the concentration of particulate matter
as measured by Method 5, and % Cd is
the percentage of CO, as measured by
Method 3, or when applicable, the ad-
justed outlet CO, percentage as deter-
mined by paragraph (c) of this section.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
[39 FR 20793, June 14, 1974]
Subport f—Standards of Performance
for Portland Cement Plants
§ 60.60 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in Portland cement plants:
Kiln, clinker cooler, raw mill system,
finish mill system, raw mill dryer, raw
material storage, clinker storage, fin-
ished product storage, conveyor trans-
fer points, bagging and bulk loading
and unloading systems.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after August
17, 1971, is subject to the requirements
of this subpart.
(Sees. Ill and 301(a) of the Clean Air Act;
sec. 4(a) of Pub. L. 91-604, 84 Stat. 1683; sec.
2 of Pub. L. 90-148, 81 Stat. 504 (42 U.S.C.
1857C-6, 1857g(a)»
[42 FR 37936, July 25. 1977]
§ 60.61 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A of this part.
(a) "Portland cement plant" means
any facility manufacturing portland
cement by either the wet or dry proc-
ess.
[36 FR 24877. Dec. 23. 1971, as amended at
39 FR 20793. June 13, 1974]
§ 60.62 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any kiln any gases which:
(1) Contain particulate matter in
excess of 0.15 kg per metric ton of feed
(dry basis) to the kiln (0.30 Ib per ton).
(2) Exhibit greater than 20 percent
opacity.
(b) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any clinker cooler any gases which:
(1) Contain particulate matter in
excess of 0.050 kg per metric ton of
feed (dry basis) to the kiln (0.10 Ib per
ton).
(2) Exhibit 10 percent opacity, or
greater.
(c) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility other than the
kiln and clinker cooler any gases
which exhibit 10 percent opacity, or
greater.
[39 FR 20793, June 14, 1974, as amended at
39 FR 39874, Nov. 12, 1974; 40 FR 46258.
Oct. 6, 1975]
§ 60.63 Monitoring of operations.
(a) The owner or operator of any
Portland cement plant subject to the
provisions of this part shall record the
daily production rates and kiln feed
rates.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
[39 FR 20793, June 14, 1974. as amended at
43 FR 8800, Mar. 3. 1978]
§ 60.64 Test methods and procedures.
(a) The reference methods in Appen-
dix A to this part, except as provided
for in § 60.8(b), shall be used to deter-
mine compliance with the standards
prescribed in § 60.62 as follows:
(1) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
A-20
-------
Chapter I—Environmental Protection Agency App. A
and substitute only for those leakage rates 6.6 Acetone Blank Concentration.
(I* or LJ which exceed /..
6.4 Volume of water vapor.
n __ "••
'. =r,.
Equation 5--'
Equation 5-4
6.7 Acetone Wash Blank.
where:
JTi=0.001333 mVml for metric units
=0.04707 ftVml for English units.
6.5 Moisture Content.
«-.
c.= (0.001 g/mg)
6.10 Conversion Factors:
From
To
set
g/ft1
g/W
m>
gr/tt'
fc/rt'
g/m>
Equation 5-G
Multiply by
0.02832
15.43
2.205x10-'
35.31
6.11 Isokinetic Varition.
6.11.1 Calculation From Raw Data.
100 T.[v,vlt
wev.P.A,
Equation j-7
where:
#,=0.003454 mm Hg-mVml-'K for metric
units.
=0.002669-in. Hg-ftVml-'R for English
units.
6.11.2
Values.
Calculation From Intermediate
T.\'m
(iid)
Equation .'>-»
where:
K.=4.320 for metric units
=0.09450 for English units.
6.12 Acceptable Results. If 90 percent /
<110< percent, the results are acceptable.
If the results are low in comparison to the
standard and / is beyond the acceptable
range, or, if 7 is less than 90 percent, the Ad-
ministrator may opt to accept the results.
Use Citation 4 to make judgments. Other-
wise, reject the results and repeat the test.
7. Bibliography
I. Addendum to Specifications for Inciner-
ator Testing at Federal Facilities. PHS.
NCAPC. Dec. 6. 1967.
2. Martin, Robert M. Construction Details
of Isokinetic Source-Sampling Equipment.
A-21
-------
App. A
Title 40—Protection of Environment
Environmental Protection Agency. Re-
search Triangle Park, N.C. APTD-0581.
April 1971.
3. Rom. Jerome J. Maintenance, Calibra-
tion, and Operation of Isokinetic Source
Sampling Equipment. Environmental Pro-
tection Agency. Research Triangle Park.
N.C. APTD-0576. March, 1972.
4. Smith, W. S., R. T. Shigehara. and W.
P. Todd. A method of Interpreting Stack
Sampling Data. Paper Presented at the 63d
Annual Meeting of the Air Pollution Con-
trol Association, St. Louis, Mo. June 14-19,
1970.
5. Smith. W. S., et al. Stack Gas Sampling
Improved and Simplified With New Equip-
ment. APCA Paper No. 67-119. 1967.
6. Specifications for Incinerator Testing at
Federal Facilities. PHS, NCAPC. 1967.
7. Shigehara, R. T. Adjustments in the
EPA Nomograph for Different Pilot Tube
Coefficients and Dry Molecular Weights.
Stack Sampling News 2:4-11, October, 1974.
8. Vollaro, R. F. A Survey of Commercially
Available Instrumentation For the Measure-
ment of Low-Range Gas Velocities. U.S. En-
vironmental Protection Agency, Emission
Measurement Branch. Research Triangle
Park. N.C. November, 1976 (unpublished
paper). '
9. Annual Book of ASTM Standards. Part
26. Gaseous Fuels; Coal and Coke; Atmos-
pheric Analysis. American Society for Test-
ing and Materials. Philadelphia, Pa. 1974.
pp. 617-622.
METHOD 6—DETERMINATION OF SULFUR DIOX-
IDE EMISSIONS FROM STATIONARY SOURCES
1. Principle and Applicability
1.1 Principle. A gas sample is extracted
from the sampling point in the stack. The
sulfuric acid mist (including sulfur trioxide)
and the sulfur dioxide are separated. The
sulfur dioxide fraction is measured by the
barium-thorin titration method.
1.2 Applicability. This method is applica-
ble for the determination of sulfur dioxide
emissions from stationary sources. The
minimum detectable limit of the method
has been determined to be 3.4 milligrams
(mg) of SO,/m3 (2.12x10-'Ib/ft3). Although
no upper limit has been established, tests
have shown that concentrations as high as
80,000 mg/m5 of SOi can be collected effi-
ciently in two midget impingers, each con-
taining 15 milliliters of 3 percent hydrogen
peroxide, at a rate of 1.0 1pm for 20 minutes.
Based on theoretical calculations, the upper
concentration limit in a 20-liter sample is
about 93,300 mg/m,.
Possible interferents are free ammonia.
water-soluble cations, and fluorides. The ca-
tions and fluorides are removed by glass
wool filters and an isopropanol bubbler, and
hence do not affect the SO, analysis. When
samples are being taken from a gas stream
with high concentrations of very find metal-
lic fumes (such as in inlets to control de-
vices), a high-efficiency glass fiber filter
must be used in place of the glass wool plug
(i.e., the one in the probe) to remove the
cation interferents.
Free ammonia interferes by reacting with
SO, to form particulate sulfite and by react-
ing with the indicator. If free ammonia is
present (this can be determined by knowl-
edge of the process and noticing white par-
ticulate matter in the probe and isopropanol
bubbler), alternative methods, subject to
the approval of the Administrator, U.S. En-
vironmental Protection Agency, are re-
quired.
2. Apparatus
A-22
-------
PO
co
THERMOMETER
PROBE (END PACKED'
WITH QUARTZ OR
PYREX WOOL)
STACK WALL
MIDGET IMPINGERS
MIDGET BUBBLER
GLASS WOOL
ICE BATH
THERMOMETER —*€/
RATE METER NEEDLE VALVE
PUMP
Figure 6-1. S02 sampling train.
SURGE TANK
1
-------
APR. A
2.1 Sampling. The sampling train is
shown in Figure 6-1, and component parts
are discussed below. The tester has the
option of substituting sampling equipment
described in Method 8 in place of the
midget impinger equipment of Method 6.
However, the Method 8 train must be modi-
fied to include a heated filter between the
probe and isopropanol impinger, and the op-
eration of the sampling train and sample
analysis must be at the flow rates and solu-
tion volumes defined in Method 8.
The tester also has the option of deter-
mining SO, simultaneously with particulate
matter and moisture determinations by (1)
replacing the water in a Method 5 impinger
system with 3 percent peroxide solution, or
(2) by replacing the Method 5 water im-
pinger system with a Method 8 isopropanol-
filter-peroxide system. The analysis for SO,
must be consistent with the procedure in
Method 8.
2.1.1 Probe. Borosilicate glass, or stain-
less steel (other materials of construction
may be used, subject to the approval of the
Administrator), approximately 6-mm inside
diameter, with a heating system to prevent
water condensation and a filter (either in-
stack or heated outstack) to remove particu-
late matter, including sulfuric acid mist. A
plug of glass wool is a satisfactory filter.
2.1.2 Bubbler and Impingers. One midget
bubbler, with medium-coarse glass frit and
borosilicate or quartz glass wool packed in
top (see Figure 6-1) to prevent sulfuric acid
mist carryover, and three 30-ml midget im-
pingers. The bubbler and midget impingers
must be connected in series with leak-free
glass connectors, silicone grease may be
used, if necessary, to prevent leakage.
At the option of the tester, a midget im-
pinger may be used in place of the midget
bubbler.
Other collection absorbers and flow rates
may be used, but are subject to the approval
of the Administrator. Also, collection effi-
ciency must be shown to be at least 99 per-
cent for each test run and must be docu-
mented in the report. If the efficiency is
found to be acceptable after a series of
three tests, further documentation is not re-
quired. To conduct the efficiency test, an
extra absorber must be added and analyzed
separately. This extra absorber must not
contain more than 1 percent of the total
SO,.
2.1.3 Glass Wool. Borosilicate or quartz.
2.1.4 Stopcock Grease. Acetone-insoluble,
heatstable silicone grease may be used, if
necessary.
2.1.5 Temperature Gauge. Dial thermom-
eter, or equivalent, to measure temperature
of gas leaving impinger train to within r C
(2- F.)
Title 40—Protection of Environment
2.1.6 Drying Tube. Tube packed with 6-
to 16-mesh indicating type silica gel, or
equivalent, to dry the gas sample and to
protect the meter and pump. If the silica gel
has been used previously, dry at 175° C (350°
F) for 2 hours. New silica gel may be used as
received. Alternatively, other types of decis-
sants (equivalent or better) may be used,
subject to approval of the Administrator.
2.1.7 Valve. Needle valve, to regulate
sample gas flow rate.
2.1.8 Pump. Leak-free diaphragm pump.
or equivalent, to pull gas through the train.
Install a small surge tank between the
pump and rate meter to eliminate the pulsa-
tion effect of the diaphragm pump on the
rotameter.
2.1.9. Rate Meter. Rotameter. or equiva-
lent, capable of measuring flow rate to
within 2 percent of the selected flow rate of
about 1000 cc/min.
2.1.10 Volume Meter. Dry gas meter, suf-
ficiently accurate to measure the sample
volume within 2 percent, calibrated at the
selected flow rate and conditions actually
encountered during sampling, and equipped
with a temperature gauge (dial thermom-
eter, or equivalent) capable of measuring
temperature to within 3° C (5.4° F).
2.1.11 Barometer. Mercury, aneroid, or
other barometer capable of measuring at- •
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby na-
tional weather service station, in which case
the station value (which is the absolute
barometric pressure) shall be requested and
an adjustment for elevation differences be-
tween the weather station and sampling
point shall be applied at a rate of minus 2.5
mm Hg (0.1 in. Hg) per 30 m (100 ft) eleva-
tion increase or vice versa for elevation de-
crease.
2.112 Vacuum Gauge and Rotameter. At
least 760 mm Hg (30 in. Hg) gauge and 0-40
cc/min rotameter, to be used for leak check
of the sampling train.
2.2 Sample Recovey.
2.2.1 Wash bottles. Polyethylene or glass,
500 ml, two.
2.2.2 Storage Bottles. Polyethylene, 100
ml, to store impinger samples (one per
sample).
2.3 Analysis.
2.3.1 Pipettes. Volumetric type, 5-ml, 20-
ml (one per sample), and 25-ml sizes.
2.3.2 Volumetric Flasks. 100-ml size (one
per sample) and 1000 ml size.
2.3.3 Burettes. 5- and 50-ml sizes.
2.3.4 Erlenmeyer Flasks. 250 mi-size (one
for each sample, blank, and standard).
2.3.5 Dropping Bottle. 125-ml size, to add
indicator.
2.3.6 Graduated Cylinder. 100-ml size.
2.3.7 Spectrophotometer. To measure ab-
sorbance at 352 nanometers.
A-24
-------
Chapter I—Environmental Protection Agency
App. A
3. Reastrnt*
Unless otherwise indicated, all reagents
must conform to the specifications estab-
lished by the Committee on Analytical Rea-
gents of the American Chemical Society.
Where such specifications are not available.
use the best available grade.
3.1 Sampling.
3.1.1 Water. Deionized, distilled to con-
form to ASTM specification Dl 193-74. Type
3. At the option of the analyst, the KMnO.
test for oxidizable organic matter may be
omitted when high concentrations of organ-
ic matter are not expected to be present.
3.1.2 Isopropanol, 80 percent. Mix 80 ml
of isopropanol with 20 ml of deionized. dis-
tilled water. Check each lot of isopropanol
for peroxide impurities as follows: shake 10
ml of isopropanol with 10 ml of freshly pre-
pared 10 percent potassium iodide solution.
Prepare a blank by similarly treating 10 ml
of distilled water. After 1 minute, read the
absorbance at 352 nanometers on a spectro-
photometer. If absorbance exceeds 0.1,
reject alcohol for use.
Peroxides may be removed from isopro-
panol by redistilling or by passage through
a column of activated alumina: however.
reagent grade isopropanol with suitably low
peroxide levels may be obtained from com-
mercial sources. Rejection of contaminated
lots may. therefore, be a more efficient pro-
cedure.
3.1.3 Hydrogen Peroxide. 3 Percent.
Dilute 30 percent hydrogen peroxide 1:9 (v/
v) with deionized. distilled water (30 ml is
needed per sample). Prepare fresh daily.
3.1.4 Potassium Iodide Solution. 10 Per-
cent. Dissolve 10.0 grams KI in deionized,
distilled water and dilute to 100 ml. Prepare
when needed.
3.2 Sample Recovery.
3.2.1 Water. Deionized. distilled, as in
3.1.1.
3.2.2 Isopropanol, 80 Percent. Mix 80 ml
of isopropanol with 20 ml of deionized, dis-
tilled water.
3.3 Analysis.
3.3.1 Water. Deionized, distilled, as in
3.1.1.
3.3.2 Isopropanol. 100 percent.
3.3.3 Thorin Indicator. l-(o-arsonopheny-
lazo)-2-naphthol-3,6-disulfonic acid, diso-
dium salt, or equivalent. Dissolve 0.20 g in
100 ml of deionized. distilled water.
3.3.4 Barium Perchlprate Solution, 0.0100
N. Dissolve 1.95 g of barium perchlorate tri-
hydrate [Ba(ClO.),3H,O] in 200 ml distilled
water and dilute to 1 liter with isopropanol.
Alternatively. 1.22 g of [Bad, 2H.CO may be
used instead of the perchlorate. Standardize
as in Section 5.5.
3.3.5 Sulfuric Acid Standard, 0.0100 N.
Purchase or standardize to ±0.0002 N
against 0.0100 N NaOH which has previous-
ly been standardized against potassium acid
phthalate (primary standard grade).
4. Procedure.
4.1 Sampling.
4.1.1 Preparation 61 collection train.
Measure 15 ml of 80 percent isopropanol
into the midget bubbler and 15 ml of 3 per-
cent hydrogen peroxide into each of the
first two midget implngers. Leave the final
midget impinger dry. Assemble the train as
shown in Figure 6-1. Adjust probe heater to
a temperature sufficient to prevent water
condensation. Place crushed Ice and water
around the impingers.
4.1.2 Leak-check procedure. A leak check
prior to the sampling run is optional; how-
ever, a leak check after the sampling run is
mandatory. The leak-check procedure is as
follows:
Temporarily attach a suitable (e.g.. 0-40
cc/min) rotameter to the outlet of the dry
gas meter and place a vacuum gauge at or
near the probe inlet. Plug the probe inlet,
pull a vaccum of at least 250 mm Hg (10 in.
Hg), and note the flow rate as indicated by
the rotameter. A leakage rate not in excess
of 2 percent of the average sampling rate is
acceptable.
NOTE: Carefully release the probe inlet
plug before turning off the pump.
It is suggested (not mandatory) that the
pump be leak-checked separately, either
prior to or after the sampling run. If done
prior to the sampling run, the pump leak-
check shall precede the leak check of the
sampling train described immediately above:
if done after the sampling run, the pump
leak-check shall follow the train leak-check.
To leak check the pump, proceed as follows:
Disconnect the drying tube from the probe-
impinger assembly. Place a vacuum gauge at
the inlet to either the trying tube or the
pump, pull a vacuum of 250 mm (10 in.) Hg,
plug or pinch off the outlet of the flow
meter and then turn off the pump. The
vacuum should remain stable for at least 30
seconds.
Other leak-check procedures may be used,
subject to the approval of the Adminstrator.
U.S. Environmental Protection Agency.
4.1.3 Sample collection. Record the ini-
tial dry gas meter reading and barometric
pressure. To begin sampling, position the tip
of the probe at the sampling point, connect
the probe to the bubbler, and start the
pump. Adjust the sample flow to a constant
rate of approximately 1.0 liter/min as indi-
cated by the rotameter. Maintain this con-
stant rate (±10 percent) during the entire
sampling run. Take readings (dry gas meter,
tempertures at dry gas meter and at im-
pinger outlet and rate meter) at least every
5 minutes. Add more ice during the run to
keep the temperture of the gases leaving
the last impinger at 20* C (68* F) or less. At
the conclusion of each run, turn off the
A-25
-------
APP.A
Title 40—Protection of Environment
pump, remove probe from the stack, and
record the final readings. Conduct a leak
check as in Section 4.1.2 (This leak check is
mandatory.) If a leak is found, void the test
run, or use procedures acceptable to the Ad-
ministrator to adjust the sample volume for
the leakage. Drain the ice bath, and purge
the remaining part of the train by drawing
clean ambient air through the system for 15
minutes at the sampling rate.
Clean ambient air can be provided by
passing air through a charcoal filter or
through an extra midget impinger with 15
ml of 3 percent H,Oj. The tester may opt to
simply use ambient air, without purifica-
tion.
4.2 Sample Recovery. Disconnect the im-
pingers after purging. Discard the contents
of the midget bubbler. Pour the contents of
the midget impingers into a leak-free poly-
ethylene bottle for shipment. Rinse the
three midget impingers and the connecting
tubes with deionized, distilled water, and
add the washings to the same storage con-
tainer. Mark the fluid level. Seal and identi-
fy the sample container.
4.3 Sample Analysis. Note level of liquid
in container, and confirm whether any
sample was lost during shipment; note this
on analytical data sheet. If a noticeable
amount of leakage has occurred, either void
the sample or use methods, subject to the
approval of the Administrator, to correct
the final results.
Transfer the contents of the storage con-
tainer to a 100-ml volumetric flask and
dilute to exactly 100 ml with deionized, dis-
tilled water. Pipette a 20-ml aliquot of this
solution into a 250-ml Erlenmeyer flask, add
80 ml of 100 percent isopropanol and two to
four drops of thorin indicator, and titrate to
a pink endpoint using 0.0100 N barium
perchlorate. Repeat and average the titra-
tion volumes. Run a blank with each series
of samples. Replicate titrations must agree
within 1 percent or 0.2 ml, whichever is
larger.
(NOTE.—Protect the 0.0100 N barium
perchlorate solution from evaporation at all
times.)
5. Calibration
5.1 Metering System.
5.1.1 Initial Calibration. Before its initial
use in the field, first leak check the meter-
ing system (drying tube, needle valve, pump,
rotameter, and dry gas meter) as follows:
place a vacuum gauge at the inlet to the
drying tube and pull a vaccum of 250 mm
(10 in.) Hg; plug or pinch off the outlet of
the flow meter, and then turn off the pump.
The vaccum shall remain stable for at least
30 seconds. Carefully release the vaccum
gauge before releasing the flow meter end.
Next, calibrate the metering system (at
the sampling flow rate specified by the
method) as follows: connect an appropriate-
ly sized wet test meter (e.g., 1 liter per revo-
lution) to the inlet of the drying tube. Make
three independent calibration runs, using at
least five revolutions of the dry gas meter
per run. Calculate the calibration factor, Y
(wet test meter calibration volume divided
by the dry gas meter volume, both volumes
adjusted to the same reference temperature
and pressure), for each run. and average the
results. If any Y value deviates by more
than 2 percent from the average, the meter-
ing system is unacceptable for use. Other-
wise, use the average as the calibration
factor for subsequent test runs.
5.1.2 Post-Test Calibration Check. After
each field test series, conduct a calibration
check a£ in Section 5.1.1 above, except for
the following variations: (a) the leak check
is not to be conducted, (b) three, or more
revolutions of the dry gas meter may be
used, and (c) only two independent runs
need be made. If the calibration factor does
not deviate by more than 5 percent from
the initial calibration factor (determined in
Section 5.1.1), then the dry gas meter vol-
umes obtained during the test series are ac-
ceptable. If the calibration factor deviates
by more than 5 percent, recalibrate the me-
tering system as in Section 5.1.1, and for the
calculations, use the calibration factor (ini-
tial or recalibration) that yields the lower
gas volume for each test run.
5.2 Thermometers. Calibrate against
mercury-in-glass thermometers.
5.3 Rotameter. The rotameter need not
be calibrated but should be cleaned and
maintained according to the manufactu-
turer's instruction.
5.4 Barometer. Calibrate against a mer-
cury barometer.
5.5 Barium Perchlorate Solution. Stand-
ardize the barium perchlorate solution
against 25 ml of standard sulfuric acid to
which 100 ml of 100 percent isopropanol has
been added.
6. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation.
6.1 Nomenclature.
G.O, = Concentration of sulfur dioxide, dry
basis corrected to standard conditions,
mg/dscm (Ib/dscf).
N=Normality of barium perchlorate titrant,
milliequivalents/ml.
Pbmr=Barometric pressure at the exit orifice
of the dry gas meter, mm Hg (in. Hg).
PM = Standard absolute pressure, 760 mm
Hg (29.92 in. Hg).
A-26
-------
Chapter I—Environmental Protection Agency
App. A
r.=Average dry gas meter absolute tem-
perature, 'K CR).
T.,,,=Standard absolute temperature, 293° K
(528- R).
V.=Volume of sample aliquot titrated, ml.
V.=Dry gas volume as measured by the dry
gas meter, dcm (dcf).
V.uu)=Dry gas volume measured by the dry
gas meter, corrected to standard condi-
tions, dscm (dscf >.
Virt.=Total volume of solution in which the
sulfur dioxide sample is contained, 100
ml.
V/=Volume of barium perchlorate titrant
used for the sample, ml (average or rep-
licate titrations).
V.»=Volume of barium perchlorate titrant
used for the blank, ml.
y=Dry gas meter calibration factor.
32.03 = Equivalent weight of sulfur dioxide.
6.2 Dry sample gas volume, corrected to
standard conditions.
Equation 6-1
where: ,
A", = 0.3858° K/mm Hg for metric units.
= 17.64' R/in. Hg for English units.
6.3 Sulfur dioxide concentration.
Equation 6-2
where:
Jf>= 32.03 mg/meq. for metric units.
= 7.061 x lO"5 Ib/meq. for English units.
7. Bibliography
1. Atmospheric Emissions from Sulfuric
Acid Manufacturing Processes. U.S. DHEW,
PHS. Division of Air Pollution. Public
Health Service Publication No. 999-AP-13.
Cincinnati. Ohio. 1965.
2. Corbett. P. F. The Determination of
SO, and SO, in Flue Gases. Journal of the
Institute of Fuel. 24: 237-243. 1961.
3. Matty. R. E. and E. K. Diehl. Measuring
Flue-Gas SO, and SO,. Power. 707; 94-97.
November 1957.
4. Patton, W. F. and J. A. Brink. Jr. New
Equipment and Techniques for Sampling
Chemical Process Gases. J. Air Pollution
Control Association. 13:162. 1963.
5. Rom, J. J. Maintenance, Calibration.
and Operation of Isokinetic Source-sam-
pling Equipment. Office of Air Programs.
Environmental Protection Agency. Re-
search Triangle Park. N.C. APTD-0576.
March 1972.
6. Hamil. H. F. and D. E. Camann. Col-
laborative Study of Method for the Deter-
mination of Sulfur Dioxide Emissions from
Stationary Sources (Fossil-Fuel Fired Steam
Generators). Environmental Protection
Agency, Research Triangle Park, N.C. EPA-
650/4-74-024. December 1973.
V. Annual Book of ASTM Standards. Part
31; Water, Atmospheric Analysis. American
Society for Testing and Materials. Philadel-
phia, Pa. 1974. pp. 40-42.
8. Knoll, J. E. and M. R. Midgett. The Ap-
plication of EPA Method 6 to High Sulfur
Dioxide Concentrations. Environmental
Protection Agency. Research Triangle Park,
N.C. EPA-600/4-76-038. July 1976.
METHOD 7—DETERMINATION OF NITROGEN
OXIDE EMISSIONS FROM STATIONARY SOURCES
1. Principle and Applicability
1.1 Principle. A grab sample is collected
in an evacuated flask containing a dilute
sulfuric acid-hydrogen peroxide absorbing
solution, and the nitrogen oxides, except ni-
trous oxide, are measured colorimeterically
using the phenoldisulfonic acid (PDS) pro-
cedure.
1.2 Applicability. This method is applica-
ble to the measurement of nitrogen oxides
emitted from stationary sources. The range
of the method has been determined to be 2
to 400 milligrams NO. (as NO,) per dry
standard cubic meter, without having to
dilute the sample.
2. Apparatus
2.1 Sampling (see Figure 7-1). Other grab
sampling systems or equipment, capable of
measuring sample volume to within ±2.0
percent and collecting a sufficient sample
volume to allow analytical reproducibility to
within ±5 percent, will be considered ac-
ceptable alternatives, subject to approval of
the Administrator, U.S. Environmental Pro-
tection Agency. The following equipment is
used in sampling:
2.1.1 Probe. Borosilicate glass tubing, suf-
ficiently heated to prevent water condensa-
tion and equipped with an in-stack or out-
stack filter to remove participate matter (a
plug of glass wool is satisfactory for this
purpose). Stainless steel or Teflon ' tubing
may also be used for the probe. Heating is
not necessary if the probe remains dry
during the purging period.
3 Mention of trade names or specific prod-
ucts does not constitue endorsement by the
Environmental Protection Agency.
A-27
-------
EVACUATE
i
ro
oo
PROBE
\
FILTER
GROUND-GLASS SOCKET.
§ NO. 12/5
110
3-WAY STOPCOCK
T-BORE. I PYREX.
2-fnm BORE. 8-nvn
GROUND-GLASS CONE
STANDARD TAPER.
I SLEEVE NO. 24/40
3
SQUEEZE BULB
UMP VALVE
PUMP
THERMOMETER
210 nwn
GROUND-GLASS
SOCKET. 5 NO. 12/5
PVREX
Figure 7-1. Sampling train, flask valve, and flask.
•FOAM ENCASEMENT
BOILING FLASK •
2-LITER. ROUND-BOTTOM. SHORT NECK.
WITH | SLEEVE NO. 24/40
I
i
e
a..
i
-------
. . APPend1x B. Applicable 40CFR51 Minimum Emission Monitoring Requirements
Sources subject to sulfur dioxide (SO,) continuous emissions monitoring
are reproduced below from Appendix P of 40CFR51, July 1, 1979.
App.P
APPENDIX P—MINIMUM EMISSION
MONITORING REQUIREMENTS
1.0 Purpose. This Appendix P sets forth
the minimum requirements for continuous
emission monitoring and recording that
each State Implementation Plan must in-
clude in order to be approved under the pro-
visions of 40 CPR 51.19(e). These require-
ments include the source categories to be af-
fected: emission monitoring, recording, and
reporting requirements for those sources;
performance specifications for accuracy, re-
liability, and durability of acceptable moni-
toring systems; and techniques to convert
emission data to units of the applicable
State emission standard. Such data must be
reported to the State as an indication of
whether proper maintenance and operating
procedures are being utilized by source op-
erators to maintain emission levels at or
below emission standards. Such data may be
used directly or indirectly for compliance
determination or any other purpose deemed
appropriate by the State. Though the moni-
toring requirements are specified in detail,
States are given some flexibility to resolve
difficulties that may arise during the imple-
mentation of these regulations.
1.1 Applicability.
The State plan shall require the owner or
operator of an emission source in a category
listed in this Appendix to: (1) Install, cali-
brate, operate, and maintain all monitoring
equipment necessary for continuously moni-
toring the pollutants specified in this Ap-
pendix for the applicable source category;
and (2) complete the installation and per-
formance tests of such equipment and begin
monitoring and recording within 18 months
of plan approval or promulgation. The
source categories and the respective moni-
toring requirements are listed below.
1.1.1 Fossil fuel-fired steam generators.
as specified in paragraph 2.1 of this appen-
dix, shall be monitored for opacity, nitrogen
oxides emissions, sulfur dioxide emissions.
and oxygen or carbon dioxide.
1.1.2 Fluid bed catalytic cracking unit
catalyst regenerators, as specified In para-
graph 2.4 of this appendix, shall be moni-
tored for opacity.
1.1.3 Sulfuric acid plants, as specified in
paragraph 2.3 of this appendix, shall be
monitored for sulfur dioxide emissions.
1.1.4 Nitric acid plants, as specified in
paragraph 2.2 of this appendix, shall be
monitored for nitrogen oxides emissions.
1.2 Exemptions.
The States may Include provisions within
their regulations to grant exemptions from
the monitoring requirements of paragraph
1.1 of this appendix for any source which is:
1.2.1 subject to a new source perform-
ance standard promulgated in 40 CFR Part
Title 40—Protection of Environment
60 pursuant to Section 111 of the Clean Air
Act; or
1.2.2 not subject to an applicable emis-
sion standard of an approved plan: or
1.2.3 scheduled for retirement within 5
years after inclusion of monitoring require-
ments for the source in Appendix P, pro-
vided that adequate evidence and guaran-
tees are provided that clearly show that the
source will cease operations prior to such
date.
1.3 Extensions.
States may allow reasonable extensions of
the time provided for installation of moni-
tors for facilities unable to meet the pre-
scribed timeframe (i.e., 18 months from plan
approval or promulgation) provided the
owner or operator of such facility demon-
strates that good .'aith efforts have been
made to obtain and install such devices
within such prescribed timeframe.
1.4 Monitoring System Malfunction.
The State plan may provide a temporary
exemption from the monitoring and report-
ing requirements of this appendix during
any period of monitoring system malfunc-
tion, provided that the source owner or op-
erator shows, to the satisfaction of the
State, that the malfunction was unavoidable
and is being repaired as expeditiously as
practicable.
2.0 Minimum Monitoring Requirement.
States must, as a minimum, require the
sources listed in paragraph 1.1 of this ap-
pendix to meet the following basic require-
ments.
V 2.1 Fossil fuel-fired, steam generators.
Each fossil fuel-fired steam generator,
except as provided in the following subpara-
graphs. with an annual average capacity
factor of greater than 30 percent, as report-
ed to the Federal Power Commission for cal-
endar year 1974, or as otherwise demon-
strated to the State by the owner or opera-
tor, shall conform with the following moni-
toring requirements when such facility is
subject to an emission standard of an appli-
cable plan for the pollutant in question.
2.1.1 A continuous monitoring system for
the measurement of opacity which meets
the performance specifications of paragraph
3.1.1 of this appendix shall be installed, cali-
brated, maintained, and operated in accord-
ance with the procedures of this appendix
by the owner or operator of any such steam
generator of greater than 250 million BTU
per hour heat Input except where:
2.1.1.1 gaseous fuel Is the only fuel
burned, or
2.1.1.2 oil or a mixture of gas and oil are
the only fuels burned and the source is able
to comply with the applicable paniculate
matter and opacity regulations without uti-
lization of particulate matter collection
equipment, and where the source has never
B-l
-------
Chapter I—Environmental Protection Agency
App. P
been found, through any administrative or
judicial proceedings, to be in violation of
any visible emission standard of the applica-
ble plan.
2.1.2 A continuous monitoring system for
the measurement of sulfur dioxide which
meets the performance specifications of
paragraph 3.1.3 of this appendix shall be in-
stalled, calibrated, maintained, and operated
on any fossil fuel-fired steam generator of
greater than 250 million BTU per hour heat
input which has installed sulfur dioxide pol-
lutant control equipment.
2.1.3 A continuous monitoring system for
the measurement of nitrogen oxides which
meets the performance specification of
paragraph 3.1.2 of this appendix shall be In-
stalled, calibrated, maintained, and operated
on fossil fuel-fired steam generators of
greater than 1000 million BTU per hour
heat input when such facility is located in
an Air Quality Control Region where the
Administrator has specifically determined
that a control strategy for nitrogen dioxide
is necessary to attain the national stand-
ards, unless the source owner or operator
demonstrates during source compliance
tests as required by the State that such a
source emits nitrogen oxides at levels 30
percent or more below the emission stand-
ard within the applicable plan.
2.1.4 A continuous monitoring system for
the measurement of the percent oxygen or
carbon dioxide which meets the perform-
ance specifications of paragraphs 3.1.4 or
3.1.5 of this appendix shall be installed, cali-
brated, operated, and maintained on fossil
fuel-fired steam generators where measure-
ments of oxygen or carbon dioxide in the
flue gas are required to convert either
sulfur dioxide or nitrogen oxides continuous
emission monitoring data, or both, to units
of the emission standard within the applica-
ble plan.
2.2 Nitric acid plants.
Each nitric acid plant of greater than 300
tons per day production capacity, the pro-
duction capacity being expressed as 100 per-
cent acid, located in an Air Quality Control
Region where the Administrator has specifi-
cally determined that a control strategy for
nitrogen dioxide is necessary to attain the
national standard shall install, calibrate,
maintain, and operate a continuous moni-
toring system for the measurement of nitro-
gen oxides which meets the performance
specifications of paragraph 3.1.2 for each
nitric acid producing facility within such
plant.
2.3 Sulfuric acid plants.
Each Sulfuric acid plant of greater than
300 tons per day production capacity, the
production being expressed as 100 percent
acid, shall install, calibrate, maintain and
operate a continuous monitoring system for
the measurement of sulfur dioxide which
meets the performance specifications of
3.1.3 for each sulfuric acid producing facili-
ty within such plant.
2.4 Fluid bed catalytic cracking unit
catalyst regenerators at petroleum refiner-
ies.
Each catalyst regenerator for fluid bed
catalytic cracking units of greater than
20,000 barrels per day fresh feed capacity
shall install, calibrate, maintain, and oper-
ate a continuous monitoring system for the
measurement of opacity which meets the
performance specifications of 3.1.1.
3.0 Minimum specifications.
All State plans shall require owners or op-
erators of monitoring equipment installed
to comply with this Appendix, except as
provided in paragraph 3.2, to demonstrate
compliance with the following performance
specifications.
3.1 Performance specifications.
The performance specifications set forth
in Appendix B of Part 60 are Incorporated
herein by reference, and shall be used by
States to determine acceptability of moni-
toring equipment installed pursuant to this
Appendix except that (1) where reference is
made to the "Administrator" in Appendix
B. Part 60. the term "State" should be in-
serted for the purpose of this Appendix
(e.g.. in Performance Specification 1. 1.2,
" • • • monitoring systems subject to ap-
proval by the Administrator," should be in-
terpreted as. "• • • monitoring systems sub-
ject to approval by the State"), and (2)
where reference is made to the "Reference
Method" in Appendix B, Part 60, the State
may allow the use of either the State ap-
proved reference method or the Federally
approved reference method as published in
Part 60 of this Chapter. The Performance
Specifications to be used with each type of
monitoring system are listed below.
3.1.1 Continuous monitoring systems for
measuring opacity shall comply with Per-
formance Specification 1.
3.1.2 Continuous monitoring systems for
measuring nitrogen oxides shall comply
with Performance Specification 2.
3.1.3 Continuous monitoring systems for
measuring sulfur dioxide shall comply with
Performance Specification 2.
3.1.4 Continuous monitoring systems for
measuring oxygen shall comply with Per-
formance Specification 3.
3.1.5 Continuous monitoring systems for
measuring carbon dioxide shall comply with
Performance Specification 3.
3.2 Exemptions.
Any source which has purchased an emis-
sion monitoring system(s) prior to Septem-
ber 11, 1974. may be exempt from meeting
such test procedures prescribed in Appendix
B of Part 60 for a period not to exceed five
years from plan approval or promulgation.
3.3 Calibration Gases.
For nitrogen oxides monitoring systems
installed on fossil fuel-fired steam gener-
40-100 0-7* 10
B-2
-------
App. P
Title 40—Protection of Environment
ators the pollutant gas used to prepare cali-
bration gas mixtures (Section 2.1. Perform-
ance Specification 2. Appendix B. Part 60)
shall be nitric oxide (NO). For nitrogen
oxides monitoring systems, installed on
nitric acid plants the pollutant gas used to
prepare calibration gas mixtures (Section
2.1. Performance Specification 2. Appendix
B. Part 60 of this Chapter) shall be nitrogen
dioxide (NO,). These gases shall also be
used for dally checks under paragraph 3.7 of
this appendix as applicable. For sulfur diox-
ide monitoring systems installed on fossil
fuel-fired steam generators or sulfuric acid
plants the pollutant gas used to prepare
calibration gas mixtures (Section 2.1, Per-
formance Specification 2, Appendix B. Part
60 of this Chapter) shall be sulfur dioxide
(SO,). Span and zero gases should be trace-
able to National Bureau of Standards refer-
ence gases whenever these reference gases
are available. Every six months from date of
manufacture, span and zero gases shall be
reanalyzed by conducting triplicate analyses
using the reference methods in Appendix A.
Part 60 of this chapter as follows: for sulfur
dioxide, use Reference Method 6; for nitro-
gen oxides, use Reference Method 7; and for
carbon dioxide or oxygen, use Reference
Method 3. The gases may be analyzed at
less frequent intervals if longer shelf lives
are guaranteed by the manufacturer.
3.4 Cycling times.
Cycling times include the total time a
monitoring system requires to sample, ana-
lyze and record an emission measurement.
3.4.1 Continuous monitoring systems for
measuring opacity shall complete a mini-
mum 01 one cycle of operation (sampling.
analyzing, and data recording) for each
successive 10-second period.
3.4.2 Continuous monitoring systems for
measuring oxides of nitrogen, carbon diox-
ide, oxygen, or sulfur dioxide shall complete
a minimum of one cycle of operation (sam-
pling, analyzing, and data recording) for
each successive 15-minute period.
3.5 Monitor location.
State plans shall require all continuous
monitoring systems or monitoring devices to
be Installed such that representative mea-
surements of emissions or process param-
eters (i.e.. oxygen, or carbon dioxide) from
the affected facility are obtained. Addition-
al guidance for location of continuous moni-
toring systems to obtain representative sam-
ples are contained In the applicable Per-
formance Specifications of Appendix B of
Part 60 of this Chapter.
3.6 Combined effluent!.
When the effluents from two or more af-
fected facilities of similar design and operat-
ing characteristics are combined before
being released to the atmosphere, the State
plan may allow monitoring systems to be In-
stalled on the combined effluent. When the
affected facilities are not of similar design
and operating characteristics, or when the
effluent from one affected facility is re-
leased to the atmosphere through more
than one point, the State should establish
alternate procedures to Implement the
intent of these requirements.
3.7 Zero and drift.
State plans shall require owners or opera-
tors of all continuous monitoring systems
installed In accordance with the require-
ments of this Appendix to record the zero
and span drift in accordance, with the
method prescribed by the manufacturer of
such instruments; to subject the instru-
ments to the manufacturer's recommended
zero and span check at least once daily
unless the manufacturer has recommended
adjustments at shorter intervals, in which
case such recommendations shall be fol-
lowed; to adjust the zero and span whenever
the 24-hour zero drl.'t or 24-hour calibration
drift limits of the applicable performance
specifications in Appendix B of Part 60 are
exceeded; and to adjust continuous monitor-
Ing systems referenced by paragraph 3.2 of
this Appendix whenever the 24-hour zero
drift or 24-hour calibration drift exceed 10
percent of the emission standard.
3.8 Span.
Instrument span should be approximately
200 per cent of the expected instrument
data display output corresponding to the
emission standard for the source.
3.9 Alternative procedures and require-
ments.
In cases where States wish to utilize dif-
ferent, but equivalent, procedures and re-
quirements for continuous monitoring sys-
tems, the State plan must provide a descrip-
tion of such alternative procedures for ap-
proval by the Administrator. Some exam-
ples of situations that may require alterna-
tives follow:
3.9.1 Alternative monitoring require-
ments to accommodate continuous monitor-
Ing systems that require corrections for
stack moisture conditions (e.g., an instru-
ment measuring steam generator SO, emis-
sions on a wet basis could be used with an
Instrument measuring oxygen concentration
on a dry basis if acceptable methods of
measuring stack moisture conditions are
used to allow accurate adjustments of the
measured SO, concentration to dry basis.)
3.9.2 Alternative locations for Installing
continuous monitoring systems or monitor-
Ing devices when the owner or operator can
demonstrate that Installation at alternative
locations will enable accurate and repre-
sentative measurements.
3.9.3 Alternative procedures for perform-
ing calibration checks (e.g., some Instru-
ments may demonstrate superior drift char-
acteristics that require checking at less fre-
quent Intervals).
3.9.4 Alternative monitoring require-
ments when the effluent from one affected
B-3
-------
Chapter I—Environmental Protection Agency
facility or the combined effluent from two
or more identical affected facilities is re-
leased to the atmosphere through more
than one point (e.g.. an extractive, gaseous
monitoring system used at several points
may be approved if the procedures recom-
mended are suitable for generating accurate
emission averages).
3.9.5 Alternative continuous monitoring
systems that do not meet the spectral re-
sponse requirements in Performance Speci-
fication 1, Appendix B of Part 60. but ade-
quately demonstrate a definite and consist-
ent relationship between their measure-
ments and the opacity measurements of a
system complying with the requirements in
Performance Specification 1. The State may
require that such demonstration be per-
formed for each affected facility.
4.0 Minimum data requirements.
The following paragraphs set forth the
minimum data reporting requirements nec-
essary to comply with 5 51.19(e) (3) and (4).
4.1 The State plan shall require owners
or operators of facilities required to Install
continuous monitoring systems to submit a
written report of excess emissions for each
calendar quarter and the nature and cause
of the excess emissions, if known. The aver-
aging period used for data reporting should
be established by the State to correspond to
the averaging period specified in the emis-
sion test method used to determine compli-
ance with an emission standard for the pol-
lutant/source category in question. The re-
quired report shall include, as a minimum,
the data stipulated in this Appendix.
4.2 For opacity measurements, the sum-
mary shall consist of the magnitude in
actual percent opacity of all one-minute (or
such other time period deemed appropriate
by the State) averages of opacity greater
than the opacity standard in the applicable
plan for each hour of operation of the facili-
ty. Average values may be obtained by inte-
gration over the averaging period or by
arithmetically averaging a minimum of four
equally spaced, instantaneous opacity meas-
urements per minute. Any time period
exempted shall be considered before deter-
mining the excess averages of opacity (e.g..
whenever a regulation allows two minutes
of opacity measurements in excess of the
standard, the State shall require the source
to report all opacity averages, in any one
hour, in excess of the standard, minus the
two-minute exemption). If more than one
opacity standard applies, excess emissions
data must be submitted in relation to all
such standards.
4.3 For gaseous measurements the sum-
mary shall consist of emission averages, in
the units of the applicable standard, for
each averaging period during which the ap-
plicable standard was exceeded.
4.4 The date and time identifying each
period during which the continuous moni-
toring system was inoperative, except for
zero and span checks, and the nature of
system repairs or adjustments shall be re-
ported. The State may require proof of con-
tinuous monitoring system performance
whenever system repairs or adjustments
have been made.
4.5 When no excess emissions have oc-
curred and the continuous monitoring
system(s) have not been inoperative, re-
paired, or adjusted, such information shall
be included in the report.
4.6 The State plan shall require owners
or operators of affected facilities to main-
tain a file of all information reported in the
quarterly summaries, and all other data col-
lected either by the continuous monitoring
system or as necessary to convert monitor-
ing data to the units'of the applicable stand-
ard for a minlmurr. of two years from the
date of collection of such data or submission
of such summaries.
5.0 Data Reduction.
The State plan shall require owners or op-
erators of affected facilities to use the fol-
lowing procedures for converting monitor-
ing data to units of the standard where nec-
essary.
5.1 For fossil fuel-fired steam generators
the following procedures shall be used to
convert gaseous emission monitoring data in
parts per million to g/million cal (Ib/million
BTU) where necessary:
5.1.1 When the owner or operator of a
fossil fuel-fired steam generator elects
under subparagraph 2.1.4 of this Appendix
to measure oxygen in the flue gases, the
measurements of the pollutant concentra-
tion and oxygen concentration shall each be
on a dry basis and the following conversion
procedure used:
E=CP [20.9/20.9-%O,]
5.1.2 When the owner or operator elects
under paragraph 2.1.4 of this Appendix to
measure carbon dioxide in the flue gases.
the measurement of the pollutant concen-
tration and the carbon dioxide concentra-
tion shall each be on a consistent basis (wet
or dry) and the following conversion proce-
dure used:
E=CFt(100/% CO,)
5.1.3 The values used in the equations
under paragraph 5.1 are derived as follows:
E=pollutant emission, g/milllon cal (Ib/mil-
lion BTU),
C = pollutant concentration, g/dscm
-------
APP.P
%Oi. %CO,=Oxygen or carbon dioxide
volume (expressed as percent) deter-
mined with equipment specified under
paragraph 4.1.4 of this appendix.
P. F,-a factor representing a ratio of the
volume of dry flue gases generated to
the calorific value of the fuel combusted
(F). and a factor representing a ratio of
the volume of carbon dioxide generated
to the calorific value of the fuel com-
busted (P.) respectively. Values of F and
Ft are given in S 60.4S(f > of Part 60, as
applicable.
5.2 For sulfuric acid plants the owner or
operator shall;
5.2.1 establish a conversion factor three
times daily according to the procedures to
i 60.84(b) of this chapter;
5.2.2 multiply the conversion factor by
the average sulfur dioxide concentration In
the flue gases to obtain average sulfur diox-
ide emissions In Kg/metric ton (Ib/short
ton): and
5.2.3 report the average sulfur dioxide
emission for each averaging period in excess
of the applicable emission standard in the
quarterly summary.
5.3 For nitric acid plants the owner or
operator shall;
5.3.1 establish a conversion factor accord-
ing to the procedures of J60.73(b) of this
chapter;
5.3.2 multiply the conversion factor by
the average nitrogen oxides concentration
in the flue gases to obtain the nitrogen
oxides emissions in the units of the applica-
ble standard;
5.3.3 report the average nitrogen oxides
emission for each averaging period in excess
of the applicable emission standard, In the
quarterly summary.
5.4 Any State may allow data reporting
or reduction procedures varying from those
set forth in this Appendix if the owner or
operator of a source shows to the satisfac-
tion of the State that his procedures are at
least as accurate as those in this Appendix.
Such procedures may Include but are not
limited to. the following:
5.4.1 Alternative procedures for comput-
ing emission averages that do not require in-
tegration of data (e.g.. some facilities may
demonstrate that the variability of their
emissions is sufficiently small to allow accu-
rate reduction of data based upon comput-
Titl* 40—Protection of Environment
Ing averages from equally spaced data
points over the averaging period).
5.4.2 Alternative methods of converting
pollutant concentration measurements to
the units of the emission standards.
6.0 Special Consideration.
The State plan may provide for approval,
on a case-by-case basis, of alternative moni-
toring requirements different from the pro-
visions of Parts 1 through 5 of this Appen-
dix if the provisions of this Appendix (I.e.,
the Installation of a continuous emission
monitoring system) cannot be implemented
by a source due to physical plant limitations
or extreme economic reasons. To make use
of this provision. States must include in
their plan specific criteria for determining
those physical limitations or extreme eco-
nomic situations to be considered by the
State. In such cues, when the State
exempts any source subject to this Appen-
dix by use of this provision from installing
continuous emission monitoring systems.
the State shall set forth alternative emis-
sion monitoring and reporting requirements
(e.g., periodic manual stack tests) to satisfy
the intent of these regulations. Examples of
such special cases include, but are not limit-
ed to, the following:
6.1 Alternative monitoring requirements
may be prescribed when installation of a
continuous monitoring system or monitor-
ing device specified by this Appendix would
not provide accurate determinations of
emissions (e.g.. condensed, uncombined
water vapor may prevent an accurate deter-
mination of opacity using commercially
available continuous monitoring systems).
6.2 Alternative monitoring requirements
may be prescribed when the affected facili-
ty is infrequently operated (e.g., some af-
fected facilities may operate less than one
month per year).
6.3 Alternative monitoring requirements
may be prescribed when the State deter-
mines that the requirements of this Appen-
dix would impose an extreme economic
burden on the source owner or operator.
6.4 Alternative monitoring requirements
may be prescribed when the State deter-
mines that monitoring systems prescribed
by this Appendix cannot be installed due to
physical limitations at the facility.
[40 FR 46247. Oct. 6. 1975]
APPENDIX Q [Reserved]
B-5
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APPENDIX C. NOTICES OF SIP CHANGES AFFECTING S02 REGULATIONS
Since the compilation of this document, numerous revisions have
been made to the approved SIP regulations for sulfur dioxide. Listed
below are the affected States, as well as the date of each revision
and the appropriate Federal Register citation. For further information,
contact the appropriate State control agency or EPA Regional Office.
State
Date
Federal Register Volume 46
Massachusetts
New Jersey
Rhode Island
Indiana
Massachusetts
Michigan
New York
Ohio
D.C.
Ohio
Massachusetts
Ohio
New York
Minnesota
Ohio
Connecticut
Ohio
Michigan
Ohio
Michigan
Ohio
Ohio
Kentucky
Michigan
Ohio
Massachusetts
Ohio
New Mexico
1/19/81
1/19/81
1/21/81
1/27/81
1/27/81
1/27/81
1/27/81
1/27/81
1/30/81
3/19/81
3/19/81
3/19/81
3/19/81
4/8/81
4/14/81
4/27/81
4/29/81
5/1/81
5/4/81
5/14/81
5/26/81
6/12/81
6/15/81
7/2/81
7/22/81
8/11/81
8/26/81
8/27/81
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P-
P.
P-
P-
P-
4916
4918
5980
8474
8475
8476
8477
8481
9947
17554
17551
17550
17555
20996
21767
23412
23926
24560
24926
26641
28157
31012
31260
34584
37642
40678
43045
43152
C-l
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State
Pennsylvania
Virgin Islands
Maryland
Massachusetts
Pennsylvania
New York
Ohio
Connecticut
New Jersey
Alabama
Pennsylvania
Connecticut
Date
8/28/81
9/3/81
9/4/81
9/17/81
9/17/81
9/24/81
10/6/81
10/23/81
11/3/81
11/6/81
11/13/81
11/18/81
Federal Register Volume 46
p. 43423
p. 44188
p. 44448
p. 46131
p. 46133
p. 47069
p. 49123
p. 51914
p. 54542
p. 55105
p. 55975
p. 56612
C-2
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