[Federal Register Volume 69, Number 176 (Monday, September 13, 2004)]
[Rules and Regulations]
[Pages 55218-55286]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-11221]
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Part II
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for
Industrial, Commercial, and Institutional Boilers and Process Heaters;
Final Rule
Federal Register / Vol. 69, No. 176 / Monday, September 13, 2004 /
Rules and Regulations
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[OAR-2002-0058; FRL-7633-9]
RIN 2060-AG69
National Emission Standards for Hazardous Air Pollutants for
Industrial, Commercial, and Institutional Boilers and Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The EPA is promulgating national emission standards for
hazardous air pollutants (NESHAP) for industrial, commercial, and
institutional boilers and process heaters. The EPA has identified
industrial, commercial, and institutional boilers and process heaters
as major sources of hazardous air pollutants (HAP) emissions. The final
rule will implement section 112(d) of the Clean Air Act (CAA) by
requiring all major sources to meet HAP emissions standards reflecting
the application of the maximum achievable control technology (MACT).
The final rule is expected to reduce HAP emissions by 50,600 to 58,000
tons per year (tpy).
The HAP emitted by facilities in the boiler and process heater
source category include arsenic, cadmium, chromium, hydrogen chloride
(HCl), hydrogen fluoride, lead, manganese, mercury, nickel, and various
organic HAP. Exposure to these substances has been demonstrated to
cause adverse health effects such as irritation to the lung, skin, and
mucus membranes, effects on the central nervous system, kidney damage,
and cancer. These adverse health effects associated with the exposure
to these specific HAP are further described in this preamble. In
general, these findings only have been shown with concentrations higher
than those typically in the ambient air.
The final rule contains numerous compliance provisions including
health-based compliance alternatives for the hydrogen chloride and
total selected metals emission limits.
DATES: The final rule is effective November 12, 2004. The incorporation
by reference of certain publications listed in the final rule is
approved by the Director of the Federal Register as of November 12,
2004.
ADDRESSES: The official public docket is the collection of materials
that is available for public viewing at the Office of Air and Radiation
Docket and Information Center (Air Docket) in the EPA Docket Center,
Room B-102, 1301 Constitution Avenue, NW., Washington, DC.
FOR FURTHER INFORMATION CONTACT: For information concerning
applicability and rule determinations, contact your State or local
representative or appropriate EPA Regional Office representative. For
information concerning rule development, contact Jim Eddinger,
Combustion Group, Emission Standards Division (C439-01), U.S. EPA,
Research Triangle Park, North Carolina 27711, telephone number (919)
541-5426, fax number (919) 541-5450, electronic mail address
[email protected].
SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities
potentially regulated by this action include:
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Examples of potentially regulated
Category NAICS code SIC code entities
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Any industry using a boiler or process 211 13 Extractors of crude petroleum and
heater as defined in the final rule. natural gas.
321 24 Manufacturers of lumber and wood
products.
322 26 Pulp and paper mills.
325 28 Chemical manufacturers.
324 29 Petroleum refineries, and
manufacturers of coal products.
316, 326, 339 30 Manufacturers of rubber and
miscellaneous plastic products.
331 33 Steel works, blast furnaces.
332 34 Electroplating, plating,
polishing, anodizing, and
coloring.
336 37 Manufacturers of motor vehicle
parts and accessories.
221 49 Electric, gas, and sanitary
services.
622 80 Health services.
611 82 Educational services.
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This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists examples of the types of entities EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed could also be affected. To determine whether your
facility, company, business, organization, etc., is regulated by this
action, you should examine the applicability criteria in Sec. 63.7485
of the final rule. If you have any questions regarding the
applicability of this action to a particular entity, consult the person
listed in the preceding FOR FURTHER INFORMATION CONTACT section.
Docket. The EPA has established an official public docket for this
action under Docket ID No. OAR-2002-0058 and Docket ID No. A-96-47. The
official public docket consists of the documents specifically
referenced in this action, any public comments received, and other
information related to this action. All items may not be listed under
both docket numbers, so interested parties should inspect both docket
numbers to ensure that they have received all materials relevant to the
final rule. Although a part of the official docket, the public docket
does not include Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute. The official
public docket is the collection of materials that is available for
public viewing at the Office of Air and Radiation Docket and
Information Center (Air Docket) in the EPA Docket Center, Room B102,
1301 Constitution Ave., NW., Washington, DC. The EPA Docket Center
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Reading
Room is (202) 566-1744, and the telephone number for the Air and
Radiation Docket is (202)
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566-1742. A reasonable fee may be charged for copying docket materials.
Electronic Access. You may access this Federal Register document
electronically through the EPA Internet under the ``Federal Register''
listings at http://www.epa.gov/fedrgstr/.
An electronic version of the public docket is available through
EPA's electronic public docket and comment system, EPA Dockets. You may
use EPA Dockets at http://www.epa.gov/edocket/ to view public comments,
access the index listing of the contents of the official public docket,
and to access those documents in the public docket that are available
electronically. Once in the system, select ``search,'' then key in the
appropriate docket identification number.
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of the final rule is also available on the WWW
through the Technology Transfer Network (TTN). Following signature, a
copy of the final rule will be posted on the TTN policy and guidance
page for newly proposed or promulgated rules at the following address:
http://www.epa.gov/ttn/oarpg. The TTN provides information and
technology exchange in various areas of air pollution control. If more
information regarding the TTN is needed, call the TTN HELP line at
(919) 541-5384.
Judicial Review. Under section 307(b)(1) of the CAA, judicial
review of the NESHAP is available by filing a petition for review in
the U.S. Court of Appeals for the District of Columbia Circuit by
November 12, 2004. Only those objections to the final rule that were
raised with reasonable specificity during the period for public comment
may be raised during judicial review. Under section 307(b)(2) of the
CAA, the requirements that are the subject of the final rule may not be
challenged later in civil or criminal proceedings brought by EPA to
enforce these requirements.
Background Information Document. The EPA proposed the NESHAP for
industrial, commercial, and institutional boilers and process heaters
on January 13, 2003 (68 FR 1660) and received 218 comment letters on
the proposal. A memorandum ``National Emission Standards for Hazardous
Air Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters, Summary of Public Comments and Responses,''
containing EPA's responses to each public comment is available in
Docket No. OAR-2002-0058.
Outline. The information presented in this preamble is organized as
follows:
I. Background Information
A. What is the statutory authority for the final rule?
B. What criteria are used in the development of NESHAP?
C. How was the final rule developed?
D. What is the relationship between the final rule and other
combustion rules?
E. What are the health effects of pollutants emitted from
industrial, commercial, and institutional boilers and process
heaters?
II. Summary of the Final Rule
A. What source categories and subcategories are affected by the
final rule?
B. What is the affected source?
C. What pollutants are emitted and controlled?
D. Does the final rule apply to me?
E. What are the emission limitations and work practice
standards?
F. What are the testing and initial compliance requirements?
G. What are the continuous compliance requirements?
H. What are the notification, recordkeeping and reporting
requirements?
I. What are the health-based compliance alternatives, and how do
I demonstrate eligibility?
III. What are the significant changes since proposal?
A. Definition of Affected Source
B. Sources Not Covered by the NESHAP
C. Emission Limits
D. Definitions Added or Revised
E. Requirements for Sources in Subcategories Without Emission
Limits or Work Practice Requirements
F. Carbon Monoxide Work Practice Emission Levels and
Requirements
G. Fuel Analysis Option
H. Emissions Averaging
I. Opacity Limit
J. Operating Limit Determination
K. Revision of Compliance Dates
IV. What are the responses to significant comments?
A. Applicability
B. Format
C. Compliance Schedule
D. Subcategorization
E. MACT Floor
F. Beyond the MACT Floor
G. Work Practice Requirements
H. Compliance
I. Emissions Averaging
J. Risk-based Approach
V. Impacts of the Final Rule
A. What are the air impacts?
B. What are the water and solid waste impacts?
C. What are the energy impacts?
D. What are the control costs?
E. What are the economic impacts?
F. What are the social costs and benefits of the final rule?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act of 1995
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations that
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Congressional Review Act
I. Background Information
A. What Is the Statutory Authority for the Final Rule?
Section 112 of the CAA requires us to list categories and
subcategories of major sources and area sources of HAP and to establish
NESHAP for the listed source categories and subcategories. Industrial
boilers, commercial and institutional boilers, and process heaters were
listed on July 16, 1992 (57 FR 31576). Major sources of HAP are those
that have the potential to emit greater than 10 tpy of any one HAP or
25 tpy of any combination of HAP.
B. What Criteria Are Used in the Development of NESHAP?
Section 112(c)(2) of the CAA requires that we establish NESHAP for
control of HAP from both existing and new major sources, based upon the
criteria set out in CAA section 112(d). The CAA requires the NESHAP to
reflect the maximum degree of reduction in emissions of HAP that is
achievable, taking into consideration the cost of achieving the
emission reduction, any non-air quality health and environmental
impacts, and energy requirements. This level of control is commonly
referred to as the MACT.
The minimum control level allowed for NESHAP (the minimum level of
stringency for MACT) is the ``MACT floor,'' as defined under section
112(d)(3) of the CAA. The MACT floor for existing sources is the
emission limitation achieved by the average of the best-performing 12
percent of existing sources for categories and subcategories with 30 or
more sources, or the average of the best-performing five sources for
categories or subcategories with fewer than 30 sources. For new
sources, the MACT floor cannot be less stringent than the emission
control achieved in practice by the best-controlled similar source.
C. How Was the Final Rule Developed?
We proposed standards for industrial, commercial, and institutional
boilers and process heaters on January 13, 2003 (68 FR 1660). Public
comments were solicited at the time of proposal. The public comment
period lasted from January 13, 2003, to March 14, 2003.
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We received a total of 218 public comment letters on the proposed
rule. Comments were submitted by industry trade associations, owners/
operators of boilers and process heaters, State regulatory agencies and
their representatives, and environmental groups. Today's final rule
reflects our consideration of all of the comments and additional
information received. Major public comments on the proposed rules,
along with our responses to those comments, are summarized in this
preamble.
D. What Is the Relationship Between the Final Rule and Other Combustion
Rules?
The final rule regulates source categories covering industrial
boilers, institutional and commercial boilers, and process heaters.
These source categories potentially include combustion units that are
already regulated by other MACT standards. Therefore, we are excluding
from the final rule any combustion units that are already or will be
subject to regulation under another MACT standard under 40 CFR part 63.
Combustion units that are regulated by other standards and are
therefore excluded from the final rule include solid waste incineration
units covered by section 129 of the CAA; boilers or process heaters
required to have a permit under section 3005 of the Solid Waste
Disposal Act or covered by the hazardous waste combustor NESHAP in 40
CFR part 63, subpart EEE \1\; and recovery boilers or furnaces covered
by 40 CFR part 63, subpart MM.
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\1\ Please note that boilers that burn small quantities of
hazardous waste under the exemptions provided by 40 CFR 266.108 are
subject to today's final rule.
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With regards to solid waste incineration units covered by section
129 of the CAA, EPA solicited on February 17, 2004 (69 FR 7390) public
comments on the definition of ``commercial and industrial solid waste
incineration unit'' for the purpose of determining which combustion
sources to regulate under section 129 and which to regulate under
section 112 (e.g., boilers and process heaters). As stated above,
combustion units covered under section 129 are not subject to the final
rule.
Electric utility steam generating units are not subject to the
final rule. An electric utility steam generating unit is a fossil fuel-
fired combustion unit of more than 25 megawatts that serves a generator
that produces electricity for sale. A fossil fuel-fired unit that
cogenerates steam and electricity and supplies more than one-third of
its potential electric output capacity and more than 25 megawatts
electrical output to any utility power distribution system for sale is
considered an electric utility steam generating unit. Non-fossil fuel-
fired utility boilers and electric utility steam generating units less
than 25 megawatts are covered by the final rule.
In 1986, EPA codified the NSPS for industrial boilers (40 CFR part
60, subparts Db and Dc) and revised portions of them in 1999. The NSPS
regulates emissions of particulate matter (PM), sulfur dioxide, and
nitrogen oxides from boilers constructed after June 19, 1984. Sources
subject to the NSPS are also subject to the final rule because the
final rule regulates sources of hazardous air pollutants while the NSPS
does not. However, in developing the final rule for industrial,
commercial, and institutional boilers and process heaters, EPA
minimized the monitoring requirements, testing requirements, and
recordkeeping requirements to avoid duplicating requirements.
Because of the broad applicability of the final rule due to the
definition of a process heater, certain process heaters could appear to
fit the applicability of another existing MACT rule. We have,
therefore, included in the list of combustion units not subject to the
final rule refining kettles subject to the secondary lead MACT rule (40
CFR part 63, subpart X); ethylene cracking furnaces covered by 40 CFR
part 63, subpart YY; and blast furnace stoves described in the EPA
document entitled ``National Emission Standards for Hazardous Air
Pollutants for Integrated Iron and Steel Plants--Background Information
for Proposed Standards'' (EPA-453/R-01-005).
E. What Are the Health Effects of Pollutants Emitted From Industrial,
Commercial, and Institutional Boilers and Process Heaters?
The final rule protects air quality and promotes the public health
by reducing emissions of some of the HAP listed in section 112(b)(1) of
the CAA. As noted above, emissions data collected during development of
the proposed rule show that HCl emissions represent the predominant HAP
emitted by industrial boilers. Industrial boilers emit lesser amounts
of hydrogen fluoride, chlorine, metals (arsenic, cadmium, chromium,
mercury, manganese, nickel, and lead), and organic HAP emissions.
Although numerous organic HAP may be emitted from industrial boilers
and process heaters, only a few account for essentially all the mass of
organic HAP emissions. These organic HAP are: Formaldehyde, benzene,
and acetaldehyde.
Exposure to high levels of these HAP is associated with a variety
of adverse health effects. These adverse health effects include chronic
health disorders (e.g., irritation of the lung, skin, and mucus
membranes, effects on the central nervous system, and damage to the
kidneys), and acute health disorders (e.g., lung irritation and
congestion, alimentary effects such as nausea and vomiting, and effects
on the kidney and central nervous system). We have classified three of
the HAP as human carcinogens and five as probable human carcinogens.
Our screening assessment for respiratory HAP and for central nervous
system (CNS) HAP, using health protective assumptions, indicates that
manganese and chlorine are the only boiler-related HAP that are
reasonably expected to approach health based criteria concentrations at
receptor locations at or beyond facility boundaries. Emissions of all
other HAP modeled on an individual basis appears to be insignificant
relative to the concentration that would produce the health effects
that they represent. The maximal hazard index (HI) for summation of the
HAP modeled in the screening assessment for respiratory effects,
including chlorine, was less than 3. The maximal HI for summation of
the HAP modeled in the screening assessment for CNS effects, including
manganese, was less than 3. Therefore, effects noted below for HAP at
high concentrations are not expected to occur prior or after regulation
as a result of emissions from these facilities, and are provided to
illustrate the nature of the contaminant's effects at high dose. A
screening assessment was also conducted for acute effects, and no
exceedances were seen. Therefore, potential acute effects are not
discussed below. However, to the extent the adverse effects do occur,
the final rule will reduce emissions and subsequent exposures.
Acetaldehyde
Acetaldehyde is ubiquitous in the environment and may be formed in
the body from the breakdown of ethanol (ethyl alcohol). In humans,
symptoms of chronic (long-term) exposure to acetaldehyde resemble those
of alcoholism. Long-term inhalation exposure studies in animals
reported effects on the nasal epithelium and mucous membranes, and
increased kidney weight. The EPA has classified acetaldehyde as a
probable human carcinogen (Group B2) based on animal studies that have
shown nasal tumors in rats and laryngeal tumors in hamsters.
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Arsenic
Chronic (long-term) inhalation exposure to inorganic arsenic in
humans is associated with irritation of the skin and mucous membranes.
Human data suggest a relationship between inhalation exposure for women
working at or living near metal smelters and an increased risk of
reproductive effects. Inorganic arsenic exposure in humans by the
inhalation route has been shown to be strongly associated with lung
cancer, while ingestion of inorganic arsenic in humans has been linked
to a form of skin cancer and also to bladder, liver, and lung cancer.
The EPA has classified inorganic arsenic as a Group A, human
carcinogen.
Benzene
Chronic (long-term) inhalation exposure has caused various
disorders in the blood, including reduced numbers of red blood cells.
Increased incidence of leukemia (cancer of the tissues that form white
blood cells) has been observed in humans occupationally exposed to
benzene. The EPA has classified benzene as a Group A, known human
carcinogen.
Beryllium
Chronic (long-term) inhalation exposure of humans to high levels of
beryllium has been reported to cause chronic beryllium disease
(berylliosis), in which granulomatous (noncancerous) lesions develop in
the lung. Inhalation exposure to high levels of beryllium has been
demonstrated to cause lung cancer in rats and monkeys. Human studies
are limited, but suggest a causal relationship between beryllium
exposure and an increased risk of lung cancer. We have classified
beryllium as a Group B1, probable human carcinogen, when inhaled; data
are inadequate to determine whether beryllium is carcinogenic when
ingested.
Cadmium
Chronic (long-term) inhalation or oral exposure to cadmium leads to
a build-up of cadmium in the kidneys that can cause kidney disease.
Cadmium has been shown to be a developmental toxicant at high doses in
animals, resulting in fetal malformations and other effects, but no
conclusive evidence exists in humans. Animal studies have demonstrated
an increase in lung cancer from long-term inhalation exposure to
cadmium. The EPA has classified cadmium as a Group B1, probable
carcinogen.
Chlorine
Chlorine is a commonly used household cleaner and disinfectant.
Chlorine is an irritant to the eyes, the upper respiratory tract, and
lungs. Chronic (long-term) exposure to chlorine gas in workers has
resulted in respiratory effects, including eye and throat irritation
and airflow obstruction. No information is available on the
carcinogenic effects of chlorine in humans from inhalation exposure. A
National Toxicology Program (NTP) study showed no evidence of
carcinogenic activity in male rats or male and female mice, and
equivocal evidence in female rats, from ingestion of chlorinated water.
The EPA has not classified chlorine for potential carcinogenicity.
Chromium
Chromium may be emitted by industrial boilers in two forms,
trivalent chromium (chromium III) or hexavalent chromium (chromium VI).
The respiratory tract is the major target organ for chromium VI
toxicity for inhalation exposures. Bronchitis, decreased pulmonary
function, pneumonia, and other respiratory effects have been noted from
chronic high dose exposure in occupational settings to chromium VI.
Limited human studies suggest that chromium VI inhalation exposure may
be associated with complications during pregnancy and childbirth, while
animal studies have not reported reproductive effects from inhalation
exposure to chromium VI. Human and animal studies have clearly
established that inhaled chromium VI is a carcinogen, resulting in an
increased risk of lung cancer. The EPA has classified chromium VI as a
Group A, human carcinogen.
Chromium III is less toxic than chromium VI. The respiratory tract
is also the major target organ for chromium III toxicity, similar to
chromium VI. Chromium III is an essential element in humans, with a
daily intake of 50 to 200 micrograms per day recommended for an adult.
The body can detoxify some amount of chromium VI to chromium III. The
EPA has not classified chromium III with respect to carcinogenicity.
Formaldehyde
Exposure to formaldehyde irritates the eyes, nose, and throat.
Reproductive effects, such as menstrual disorders and pregnancy
problems, have been reported in female workers exposed to high levels
of formaldehyde. Limited human studies have reported an association
between formaldehyde exposure and lung and nasopharyngeal cancer.
Animal inhalation studies have reported an increased incidence of nasal
squamous cell cancer. The EPA considers formaldehyde a probable human
carcinogen (Group B2).
Hydrogen chloride
Hydrogen chloride, also called hydrochloric acid, is corrosive to
the eyes, skin, and mucous membranes at high concentration. Chronic
(long-term) occupational exposure to high levels of hydrochloric acid
has been reported to cause gastritis, bronchitis, and dermatitis in
workers. Prolonged exposure to lower concentrations may also cause
dental discoloration and erosion. No information is available on the
reproductive or developmental effects of hydrochloric acid in humans.
In rats exposed to high levels of hydrochloric acid by inhalation,
altered estrus cycles have been reported in females and increased fetal
mortality and decreased fetal weight have been reported in offspring.
The EPA has not classified hydrochloric acid for carcinogenicity.
Hydrogen fluoride
Chronic (long-term) exposure to fluoride at low levels has a
beneficial effect of dental cavity prevention and may also be useful
for the treatment of osteoporosis. Exposure to higher levels of
fluoride may cause dental fluorosis. One study reported menstrual
irregularities in women occupationally exposed to fluoride. The EPA has
not classified hydrogen fluoride for carcinogenicity.
Lead
Lead can cause a variety of effects at low dose levels. Chronic
(long-term) exposure to high levels of lead in humans results in
effects on the blood, central nervous system (CNS), blood pressure, and
kidneys. Children are particularly sensitive to the chronic effects of
lead, with slowed cognitive development, reduced growth and other
effects reported. Reproductive effects, such as decreased sperm count
in men and spontaneous abortions in women, have been associated with
lead exposure. The developing fetus is at particular risk from maternal
lead exposure, with low birth weight and slowed postnatal
neurobehavioral development noted. Human studies are inconclusive
regarding lead exposure and cancer, while animal studies have reported
an increase in kidney cancer from high-dose lead exposure by the oral
route. The EPA has classified lead as a Group B2, probable human
carcinogen.
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Manganese
Health effects in humans have been associated with both
deficiencies and excess intakes of manganese. Chronic (long-term)
exposure to low levels of manganese in the diet is considered to be
nutritionally essential in humans, with a recommended daily allowance
of 2 to 5 milligrams per day (mg/d). Chronic exposure to high levels of
manganese by inhalation in humans results primarily in CNS effects.
Visual reaction time, hand steadiness, and eye-hand coordination were
affected in chronically-exposed workers. Impotence and loss of libido
have been noted in male workers afflicted with manganism attributed to
high-dose inhalation exposures. The EPA has classified manganese in
Group D, not classifiable as to carcinogenicity in humans.
Mercury
Mercury exists in three forms: Elemental mercury, inorganic mercury
compounds (primarily mercuric chloride), and organic mercury compounds
(primarily methyl mercury). Each form exhibits different health
effects. Various major sources may release elemental or inorganic
mercury; environmental methyl mercury is typically formed by biological
processes after mercury has precipitated from the air.
Chronic (long-term) exposure to elemental mercury in humans also
affects the CNS, with effects such as increased excitability,
irritability, excessive shyness, and tremors. The EPA has not
classified elemental mercury with respect to cancer.
The major effect from chronic exposure to inorganic mercury is
kidney effects. Reproductive and developmental animal studies have
reported effects such as alterations in testicular tissue, increased
embryo resorption rates, and abnormalities of development. Mercuric
chloride (an inorganic mercury compound) exposure has been shown to
result in tumors in experimental animals. The EPA has classified
mercuric chloride as a Group C, possible human carcinogen.
Nickel
Nickel is an essential element in some animal species, and it has
been suggested it may be essential for human nutrition. Nickel
dermatitis, consisting of itching of the fingers, hand and forearms, is
the most common effect in humans from chronic (long-term) skin contact
with nickel. Respiratory effects have also been reported in humans from
inhalation exposure to nickel. No information is available regarding
the reproductive or developmental effects of nickel in humans, but
animal studies have reported such effects, although a consistent dose-
response relationship has not been seen. Nickel forms released from
industrial boilers include soluble nickel compounds, nickel subsulfide,
and nickel carbonyl. Human and animal studies have reported an
increased risk of lung and nasal cancers from exposure to nickel
refinery dusts and nickel subsulfide. Animal studies of soluble nickel
compounds (i.e., nickel carbonyl) have reported lung tumors. The EPA
has classified nickel refinery subsulfide as Group A, human carcinogens
and nickel carbonyl as a Group B2, probable human carcinogen.
Selenium
Selenium is a naturally occurring substance that is toxic at high
concentrations but is also a nutritionally essential element. Studies
of humans chronically (long-term) exposed to high levels of selenium in
food and water have reported discoloration of the skin, pathological
deformation and loss of nails, loss of hair, excessive tooth decay and
discoloration, lack of mental alertness, and listlessness. The
consumption of high levels of selenium by pigs, sheep, and cattle has
been shown to interfere with normal fetal development and to produce
birth defects. Results of human and animal studies suggest that
supplementation with some forms of selenium may result in a reduced
incidence of several tumor types. One selenium compound, selenium
sulfide, is carcinogenic in animals exposed orally. We have classified
elemental selenium as a Group D, not classifiable as to human
carcinogenicity, and selenium sulfide as a Group B2, probable human
carcinogen.
II. Summary of the Final Rule
A. What Source Categories and Subcategories Are Affected by the Final
Rule?
The final rule affects industrial boilers, institutional and
commercial boilers, and process heaters. In the final rule, process
heater means an enclosed device using controlled flame, that is not a
boiler, and the unit's primary purpose is to transfer heat indirectly
to a process material (liquid, gas, or solid) or to heat a transfer
material for use in a process unit, instead of generating steam.
Process heaters are devices in which the combustion gases do not
directly come into contact with process materials. Process heaters do
not include units used for comfort heat or space heat, food preparation
for on-site consumption, or autoclaves. Boiler means an enclosed device
using controlled flame combustion and having the primary purpose of
recovering thermal energy in the form of steam or hot water. Waste heat
boilers are excluded from the definition of boiler. A waste heat boiler
(or heat recovery steam generator) means a device, without controlled
flame combustion, that recovers normally unused energy and converts it
to usable heat. Waste heat boilers incorporating duct or supplemental
burners that are designed to supply 50 percent or more of the total
rated heat input capacity of the waste heat boiler are considered
boilers and not waste heat boilers. Emissions from a combustion unit
with a waste heat boiler are regulated by the applicable standards for
the particular type of combustion unit. For example, emissions from a
commercial or industrial solid waste incineration unit, or other
incineration unit with a waste heat boiler are regulated by standards
established under section 129 of the CAA.
Hot water heaters also are not regulated under the final rule. A
hot water heater is a closed vessel, with a capacity of no more than
120 U.S. gallons, in which water is heated by combustion of gaseous or
liquid fuel and is withdrawn for use external to the vessel at
pressures not exceeding 160 pounds per square inch gauge and water
temperatures not exceeding 210 degree Fahrenheit (99 degrees Celsius).
Temporary boilers also are not regulated under the final rule. A
temporary boiler is any gaseous or liquid fuel-fired boiler that is
designed, and is capable of, being carried or moved from one location
to another, and remains at any one location for less than 180
consecutive days. Additionally, any new temporary boiler that replaces
an existing temporary boiler and is intended to perform the same or
similar function will be included in the determination of the
consecutive 180-day time period.
Boilers or process heaters that are used specifically for research
and development are not regulated under the final rule. However, units
that only provide steam to a process at a research and development
facility are still subject to the final rule.
B. What Is the Affected Source?
In the final rule, the affected source is defined as follows: (1)
The collection of all existing industrial, commercial, or institutional
boilers and process heaters within a subcategory located at a major
source; or (2) each new or reconstructed industrial, commercial or
institutional
[[Page 55223]]
boiler and process heater located at a major source.
The affected source does not include combustion units that are
subject to another standard under 40 CFR part 63, or covered by other
standards listed in this preamble.
C. What Pollutants Are Emitted and Controlled?
Boilers and process heaters can emit a wide variety of HAP,
depending on the material burned. Because of the large number of HAP
potentially present in emissions and the disparity in the quantity and
quality of the emissions information available, we use several
surrogates to control multiple HAP in the final rule. This will reduce
the burden of implementation and compliance on both regulators and the
regulated community.
We grouped the HAP into four common categories: mercury, non-
mercury metallic HAP, inorganic HAP, and organic HAP. In general, the
pollutants within each group have similar characteristics and can be
controlled with the same techniques.
Next, we identified compounds that could be used as surrogates for
all the compounds in each pollutant category. For the non-mercury
metallic HAP, we chose to use PM as a surrogate. Most, if not all, non-
mercury metallic HAP emitted from combustion sources will appear on the
flue gas fly-ash. Therefore, the same control techniques that would be
used to control the fly-ash PM will control non-mercury metallic HAP.
Particulate matter was also chosen instead of specific metallic HAP
because all fuels do not emit the same type and amount of metallic HAP
but most generally emit PM. The use of PM as a surrogate will also
eliminate the cost of performance testing to comply with numerous
standards for individual metals.
However, we are sensitive to the fact that some sources burn fuels
containing very little metals, but would have sufficient PM emissions
to require control under the PM provisions of the proposed rule. In
such cases, PM would not be an appropriate surrogate for metallic HAP.
Therefore, in the final rule, an alternative metals emission limit is
included. A source may choose to comply with the alternative metals
emissions limit instead of the PM limit to meet the final rule.
For inorganic HAP, we chose to use HCl as a surrogate. The
emissions test information available indicate that the primary
inorganic HAP emitted from boilers and process heaters are acid gases,
with HCl present in the largest amounts. Other inorganic compounds
emitted are found in much smaller quantities. Also, control
technologies that would reduce HCl would also control other inorganic
compounds that are acid gases. Thus, the best controls for HCl would
also be the best controls for other inorganic HAP that are acid gases.
Therefore, HCl is a good surrogate for inorganic HAP because
controlling HCl will result in a corresponding control of other
inorganic HAP emissions.
For organic HAP, we chose to use carbon monoxide (CO) as a
surrogate to represent the variety of organic compounds, including
dioxins, emitted from the various fuels burned in boilers and process
heaters. Because CO is a good indicator of incomplete combustion, there
is a direct correlation between CO emissions and the formation of
organic HAP emissions. Monitoring equipment for CO is readily
available, which is not the case for organic HAP. Also, it is
significantly easier and less expensive to measure and monitor CO
emissions than to measure and monitor emissions of each individual
organic HAP. Therefore, using CO as a surrogate for organic HAP is a
reasonable approach because minimizing CO emissions will result in
minimizing organic HAP emissions.
D. Does the Final Rule Apply to Me?
The final rule applies to you if you own or operate a boiler or
process heater located at a major source meeting the requirements in
the final rule.
E. What Are the Emission Limitations and Work Practice Standards?
You must meet the emission limits and work practice standards for
the subcategories in Table 1 of this preamble for each of the
pollutants listed. Emission limits and work practice standards were
developed for new and existing sources; and for large, small, and
limited use solid, liquid, and gas fuel-fired units. Large units are
those watertube boilers and process heaters with heat input capacities
greater than 10 million British thermal units per hour (MMBtu/hr).
Small units are any firetube boilers or any boiler and process heater
with heat input capacities less than or equal to 10 MMBtu/hr. Limited
use units are those large units with capacity utilizations less than or
equal to 10 percent as required in a federally enforceable permit.
If your new or existing boiler or process heater is permitted to
burn a solid fuel (either as a primary fuel or a backup fuel), or any
combination of solid fuel with liquid or gaseous fuel, the unit is in
one of the solid subcategories. If your new or existing boiler or
process heater burns a liquid fuel, or a liquid fuel in combination
with a gaseous fuel, the unit is in one of the liquid subcategories,
except if the unit burns liquid only during periods of gas curtailment.
If your new or existing boiler or process heater burns a gaseous fuel
not combined with any liquid or solid fuels, or burns liquid fuel only
during periods of gas curtailment or gas supply emergencies, the unit
is in the gaseous subcategory.
Table 1--Emission Limits and Work Practice Standards for Boilers and Process Heaters
[(Pounds per million British thermal units (lb/MMBtu)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total
Source Subcategory Particulate or Selected Hydrogen Mercury (Hg) Carbon Monoxide (CO) (ppm)
Matter (PM) Metals Chloride (HCl)
--------------------------------------------------------------------------------------------------------------------------------------------------------
New or reconstructed Boiler or Solid Fuel, 0.025 or 0.0003 0.02 0.000003 400 (@7% oxygen).
Process Heater. Large Unit.
Solid Fuel, 0.025 or 0.0003 0.02 0.000003 ...........................
Small Unit.
Solid Fuel, 0.025 or 0.0003 0.02 0.000003 400 (@7% oxygen).
Limited Use.
Liquid Fuel, 0.03 ..... ............. 0.0005 ................ 400 (@3% oxygen).
Large Unit.
[[Page 55224]]
Liquid Fuel, 0.03 ..... ............. 0.0009 ................ ...........................
Small Unit.
Liquid Fuel, 0.03 ..... ............. 0.0009 ................ 400 (@3% oxygen).
Limited Use.
Gaseous Fuel, ............... ..... ............. ................ ................ 400 (@3% oxygen).
Large Unit.
Gaseous Fuel, ............... ..... ............. ................ ................ ...........................
Small Unit.
Gaseous Fuel ............... ..... ............. ................ ................ 400 (@3% oxygen).
Limited Use.
Existing Boiler or Process Solid Fuel, 0.07 or 0.001 0.09 0.000009 ...........................
Heater. Large Unit.
Solid Fuel, ............... ..... ............. ................ ................ ...........................
Small Unit.
Solid Fuel, 0.21 or 0.004 ................ ................ ...........................
Limited Use.
Liquid Fuel, ............... ..... ............. ................ ................ ...........................
Large Unit.
Liquid Fuel, ............... ..... ............. ................ ................ ...........................
Small Unit.
Liquid Fuel, ............... ..... ............. ................ ................ ...........................
Limited Use.
Gaseous Fuel.... ............... ..... ............. ................ ................ ...........................
--------------------------------------------------------------------------------------------------------------------------------------------------------
For solid fuel-fired boilers or process heaters, sources may choose
one of two emission limit options: (1) Existing and new affected units
may choose to limit PM emissions to the level listed in Table 1 of this
preamble, or (2) existing and new affected units may choose to limit
total selected metals emissions to the level listed in Table 1 of this
preamble. Sources meeting the emission limits must also meet operating
limits.
We have provided several compliance alternatives in the final rule.
Sources may choose to demonstrate compliance based on the fuel
pollutant content. Sources are also allowed to demonstrate compliance
for existing large solid fuel units using emissions averaging.
F. What Are the Testing and Initial Compliance Requirements?
As the owner or operator of a new or existing boiler or process
heater, you must conduct performance tests (i.e. stack testing) or an
initial fuel analysis to demonstrate compliance with any applicable
emission limits. The applicable emission limits and, therefore, the
required performance tests and fuel analysis are different depending on
the subcategory classification of the unit. Existing units in the small
solid fuel subcategory and existing units in any of the liquid or
gaseous fuel subcategories do not have applicable emission limits and,
therefore, are not required to conduct stack tests or fuel analyses.
Other units are required to conduct the following compliance tests or
fuel analyses where applicable:
(1) Conduct initial and annual stack tests to determine compliance
with the PM emission limits using EPA Method 5 or Method 17 in appendix
A to part 60 of this chapter.
(2) Affected sources in the solid fuel subcategories may choose to
comply with an alternative total selected metals emission limit instead
of PM. Sources would conduct initial and annual stack tests to
determine compliance with the total selected metals emission limit
using EPA Method 29 in appendix A to part 60 of this chapter.
(3) Conduct initial and annual stack tests to determine compliance
with the mercury emission limits using EPA Method 29 in appendix A to
part 60 of this chapter or the ASTM D6784-02.
(4) Conduct initial and annual stack tests to determine compliance
with the HCl emission limits using EPA Method 26 in appendix A to part
60 of this chapter (for boilers without wet scrubbers) or EPA Method
26A in appendix A to part 60 of this chapter (for boilers with wet
scrubbers).
(5) For new boilers and process heaters in any of the limited use
subcategories and new boilers and process heaters in any of the large
subcategories with heat input capacities greater than 10 MMBtu/hr but
less than 100 MMBtu/hr, conduct initial and annual stack tests to
determine compliance with the CO work practice limit using EPA Method
10, 10A, or 10B in appendix A to part 60 of this chapter.
(6) Use EPA Method 19 in appendix A to part 60 of this chapter to
convert measured concentration values to pounds per million British
thermal units (MMBtu) values.
(7) For new units in any of the liquid fuel subcategories that do
not burn residual oil, instead of conducting an initial and annual
compliance test you may submit a signed statement in the Notification
of Compliance Status report that indicates that you only burn liquid
fossil fuels other than residual oil.
(8) For affected sources that choose to meet the emission limits
based on fuel analysis, conduct the fuel analysis using method ASTM
D5865-01ae1 or ASTM E711-87 to determine heat content; ASTM D3684-01
(for coal), SW-846-7471A (for solid samples) or SW-846-7470A (for
liquid samples) to determine mercury levels; SW-846-6010B or ASTM
D3683-94 (for coal) or ASTM E885-88 (for biomass) to determine total
selected metals concentration; SW-846-9250 or ASTM E776-87 (for
biomass) to determine chlorine concentration; and ASTM D3173 or ASTM
E871 to determine moisture content.
As part of the initial compliance demonstration, you must monitor
specified operating parameters during the initial performance tests
that demonstrate compliance with the PM (or metals), mercury, and HCl
emission limits. You must calculate the average parameter values
measured during each
[[Page 55225]]
test run over the 3-run performance test. The minimum or maximum of the
three average values (depending on the parameter measured) for each
applicable parameter establishes the site-specific operating limit. The
applicable operating parameters for which operating limits must be
established are based on the emissions limits applicable to your unit
as well as the types of add-on controls on the unit. A summary of the
operating limits that must be established for the various types of
controls are as follows:
(1) For boilers and process heaters without wet scrubbers that must
comply with the mercury emission limit and either a PM emission limit
or a total selected metals emission limit, you must meet an opacity
limit of 20 percent for existing sources (based on 6-minute averages),
except for one 6-minute period per hour of not more than 27 percent, or
10 percent for new sources (based on 1-hour block averages). Or, if the
unit is controlled with a fabric filter, instead of meeting an opacity
operating limit, you may elect to operate the fabric filter using a bag
leak detection system such that corrective actions are initiated within
1 hour of a bag leak detection system alarm and you operate and
maintain the fabric filter such that the alarm is not engaged for more
than 5 percent of the total operating time in a 6-month reporting
period.
(2) For boilers and process heaters without wet or dry scrubbers
that must comply with an HCl emission limit, you must determine the
average chloride content level in the input fuel(s) during the HCl
performance test. This is your maximum chloride input operating limit.
(3) For boilers and process heaters with wet scrubbers that must
comply with a mercury, PM (or total selected metals) and/or an HCl
emission limit, you must measure pressure drop and liquid flow rate of
the scrubber during the performance test and calculate the average
value for each test run. The minimum test run average establishes your
site-specific pressure drop and liquid flow rate operating levels. If
different average parameter levels are measured during the mercury, PM
(or metals) and HCl tests, the highest of the minimum test run average
values establishes your site-specific operating limit. If you are
complying with an HCl emission limit, you must measure pH during the
performance test for HCl and determine the average for each test run
and the minimum value for the performance test. This establishes your
minimum pH operating limit.
(4) For boilers and process heaters with dry scrubbers that must
comply with an HCl emission limit, you must measure the sorbent
injection rate during the performance test for mercury and HCl and
calculate the average for each test run. The minimum test run average
during the performance test establishes your site-specific minimum
sorbent injection rate operating limit.
(5) For boilers and process heaters with fabric filters in
combination with wet scrubbers that must comply with a mercury emission
limit, PM (or total selected metals) emission limit and/or an HCl
emission limit, you must measure the pH, pressure drop, and liquid
flowrate of the wet scrubber during the performance test and calculate
the average value for each test run. The minimum test run average
establishes your site-specific pH, pressure drop, and liquid flowrate
operating limits for the wet scrubber. Furthermore, the fabric filter
must be operated such that the bag leak detection system alarm does not
sound more than 5 percent of the operating time during any 6-month
period.
(6) For boilers and process heaters with electrostatic
precipitators (ESP) in combination with wet scrubbers that must comply
with a mercury, PM (or total selected metals) and/or an HCl emission
limit, you must measure the pH, pressure drop, and liquid flow rate of
the wet scrubber during the HCl performance test, and you must measure
the voltage and secondary current of the ESP collection plates or total
power input during the mercury and PM (or metals) performance test.
Calculate the average value of these parameters for each test run. The
minimum test run averages establish your site-specific minimum pH,
pressure drop, and liquid flowrate operating limit for the wet scrubber
and the minimum voltage and current operating limits for the ESP.
(7) For boilers and process heaters that choose to comply with the
alternative total selected metals emission limit instead of PM, you
must determine the total selected metals content of the inlet fuels
that were burned during the total selected metals performance test.
This value is your maximum fuel inlet metals content operating limit.
(8) For boilers and process heaters that burn a mixture of multiple
fuels, you must determine the mercury content of the inlet fuels that
were burned during the mercury performance test. This value is your
maximum fuel inlet mercury operating limit. Units burning only a single
fuel type (not including start-up fuels) do not need to determine, by
fuel analysis, the fuel inlet operating limit when conducting
performance tests.
(9) For new boilers and process heaters in any of the large
subcategories and with heat input capacities greater or equal to 100
MMBtu/hr, you must monitor CO to demonstrate that average CO emissions,
on a 30-day rolling average, are at or below an exhaust concentration
of 400 parts per million (ppm) by volume on a dry basis corrected to 3
percent oxygen for units in the liquid subcategories and corrected to 7
percent for units in the solid subcategories. For new boilers and
process heaters in any of the limited use subcategories or with heat
input capacities less than 100 MMBtu/hr, you must conduct initial test
of CO emissions to demonstrate compliance with the CO work practice
limit.
The final rule also provides you another compliance alternative.
You may demonstrate compliance by emissions averaging for existing
large solid fuel boilers in States that choose to allow emissions
averaging in their operating permit program.
G. What Are the Continuous Compliance Requirements?
To demonstrate continuous compliance with the emission limitations,
you must monitor and comply with the applicable site-specific operating
limits established during the performance tests or fuel analysis. Upon
detecting an excursion or exceedance, you must restore operation of the
unit to its normal or usual manner of operation as expeditiously as
practicable in accordance with good air pollution control practices for
minimizing emissions. The response shall include minimizing the period
of any startup, shutdown or malfunction and taking any necessary
corrective actions to restore normal operation and prevent the likely
recurrence of the cause of an excursion or exceedance. Such actions may
include initial inspections and evaluation, recording that operations
returned to normal without operator action, or any necessary follow-up
actions to return operation to below the work practice standard.
(1) For boilers and process heaters without wet scrubbers that must
comply with a mercury emission limit and either a PM emission limit or
a total selected metals emission limit, you must continuously monitor
opacity and maintain the opacity at or below the maximum opacity
operating limit for new and existing sources. Or, if the unit is
controlled with a fabric filter, instead of continuous monitoring
opacity, the fabric filter may be continuously operated such that the
bag leak detection system alarm does not sound
[[Page 55226]]
more than 5 percent of the operating time during any 6-month period.
(2) For boilers and process heaters without wet or dry scrubbers
that must comply with an HCl emission limit, you must maintain monthly
records of fuel use that demonstrate that you have burned no new fuel
types or new mixtures such that you have maintained the fuel HCl
content level at or below your site-specific maximum HCl input
operating limit. If you plan to burn a new fuel type or a new mixture
than what was burned during the initial performance test, then you must
re-calculate the maximum HCl input anticipated from the new fuels based
on supplier data or your own fuel analysis. If the results of re-
calculating the HCl input exceeds the average HCl content level
established during the initial test, then you must conduct a new
performance test to demonstrate continuous compliance with the HCl
emission limit.
(3) For boilers and process heaters with wet scrubbers that must
comply with a mercury, PM (or total selected metals) and/or an HCl
emission limit, you must monitor pressure drop and liquid flow rate of
the scrubber and maintain the 3-hour block averages at or above the
operating limits established during the performance test. You must
monitor the pH of the scrubber and maintain the 3-hour block average at
or above the operating limit established during the performance test to
demonstrate continuous compliance with the HCl emission limits.
(4) For boilers and process heaters with dry scrubbers that must
comply with a PM (or total selected metals) or mercury emission limit,
and/or an HCl emission limit, you must continuously monitor the sorbent
injection rate and maintain it at or above the operating limits
established during the HCl performance test.
(5) For boilers and process heaters with fabric filters in
combination with wet scrubbers, you must monitor the pH, pressure drop,
and liquid flow rate of the wet scrubber and maintain the levels at or
above the operating limits established during the HCl performance test.
You must also maintain the operation of the fabric filter such that the
bag leak detection system alarm does not sound more than 5 percent of
the operating time during any 6-month period.
(6) For boilers and process heaters with ESP in combination with
wet scrubbers that must comply with a mercury, PM and/or an HCl
emission limit, you must monitor the pH, pressure drop, and liquid flow
rate of the wet scrubber and maintain the 3-hour block averages at or
above the operating limits established during the HCl performance test.
Also, you must monitor the voltage and secondary current of the ESP
collection plates or total power input and maintain the 3-hour block
averages at or above the operating limits established during the
mercury or PM (or metals) performance test.
(7) For boilers and process heaters that choose to comply with the
alternative total selected metals limit instead of PM emission limit,
you must maintain monthly fuel records that demonstrate that you burned
no new fuel type or new mixtures such that the total selected metals
content of the inlet fuel was maintained at or below your maximum fuel
inlet metals content operating limit set during the metals performance
test. If you plan to burn a new fuel type or new mixture, then you must
re-calculate the maximum metals input anticipated from the new fuels
based on supplier data or own fuel analysis. If the results of re-
calculating the metals input exceeds the average metals content level
established during the initial test, then you must conduct a new
performance test to demonstrate continuous compliance with the
alternate selected metals emission limit.
(8) For boilers and process heaters that must comply with the
mercury emission limit, you must maintain monthly fuel records that
demonstrate that you burned no new fuel type or new mixture such that
the total selected mercury content of the inlet fuel was maintained at
or below your maximum fuel inlet metals content operating limit set
during the mercury performance test. If you plan to burn a new fuel
type or new mixture than what was burned during the initial performance
test, then you must re-calculate the maximum mercury input anticipated
from the new fuels based on supplier data or own fuel analysis. If the
results of re-calculating the mercury input exceeds the average mercury
content level established during the initial test, then you must
conduct a new performance test to demonstrate continuous compliance
with the mercury emission limit.
(9) For boilers and process heaters that choose to comply with any
emission limit based on fuel analysis, you must maintain monthly fuel
records to demonstrate that the content of fuel is maintained below the
appropriate applicable emission limit.
(10) For new boilers and process heaters in any of the large
subcategories with heat input capacities greater or equal to 100 MMBtu/
hr, you must continuously monitor CO and maintain the 30-day rolling
average CO emissions at or below 400 ppm by volume on a dry basis
(corrected to 3 percent oxygen for units in the liquid or gaseous
subcategories, and 7 percent for units in the solid fuel subcategories)
to demonstrate compliance with the work practice standards at all times
except during startup, shutdown, and malfunction and when the unit is
operating less than 50 percent of the rated capacity.
If a control device other than the ones specified in this section
is used to comply with the final rule, you must establish site-specific
operating limits and establish appropriate continuous monitoring
requirements, as approved by the EPA Administrator.
If you choose to comply using emissions averaging, you must
demonstrate on a monthly basis that mercury, metals, PM, and HCl
emission limits can be met over a 12-month period.
H. What Are the Notification, Recordkeeping and Reporting Requirements?
If your boiler or process heater is in the existing large gaseous
fuel subcategory, or existing limited use gaseous fuel subcategory, or
existing large liquid fuel subcategory, or existing limited use liquid
fuel subcategory, or a new small liquid fuel unit that only burn
gaseous fuels or distillate oil, you only have to submit the initial
notification report. If your boiler or process heater is in the
existing small gaseous, liquid, or solid fuel subcategories or new
small gaseous fuel subcategory, you are not required to keep any
records or submit any reports.
If your boiler or process heater is in any other subcategory, then
you must keep the following records:
(1) All reports and notifications submitted to comply with the
final rule.
(2) Continuous monitoring data as required in the final rule.
(3) Each instance in which you did not meet each emission limit
work practice and operating limit, including periods of startup,
shutdown, and malfunction (i.e., deviations from the final rule).
(4) Monthly hours of operation by each source that is in a limited
use subcategory.
(5) Monthly fuel use by each boilers and process heaters subject to
an emission limit including a description of the type(s) of fuel(s)
burned, amount of each fuel type burned, and units of measure.
(6) Calculations and supporting information of chloride fuel input,
as required in the final rule.
[[Page 55227]]
(7) Calculations and supporting information of total selected
metals and mercury fuel input, as required in the final rule, if
applicable.
(8) A copy of the results of all performance tests, fuel analysis,
opacity observations, performance evaluations, or other compliance
demonstrations conducted to demonstrate initial or continuous
compliance with the final rule.
(9) A copy of any federally enforceable permit that limits the
annual capacity factor of the source to less than or equal to 10
percent.
(10) A copy of your site-specific startup, shutdown, and
malfunction plan.
(11) A copy of your site-specific monitoring plan developed for the
final rule, if applicable.
(12) A copy of your site-specific fuel analysis plan developed for
the final rule, if applicable.
(13) A copy of the emissions averaging plan, if applicable.
You must submit the following reports and notifications:
(1) Notifications required by the General Provisions.
(2) Initial Notification no later than 120 calendar days after you
become subject to the final rule.
(3) Notification of Intent to conduct performance tests and/or
compliance demonstration at least 30 calendar days before the
performance test and/or compliance demonstration is scheduled.
(4) Notification of Compliance Status 60 calendar days following
completion of the performance test and/or compliance demonstration.
(5) Notification of intent to demonstrate compliance by emissions
averaging.
(6) Notification of intent to demonstrate eligibility for either
health-based compliance alternative.
(7) Compliance reports semi-annually.
I. What Are the Health-Based Compliance Alternatives, and How Do I
Demonstrate Eligibility?
HCl Compliance Alternative
As an alternative to the requirement for each large solid fuel-
fired boiler to demonstrate compliance with the HCl emission limit in
the final rule, you may demonstrate compliance with a health-based HCl
equivalent allowable emission limit.
The procedures for demonstrating eligibility for the HCl compliance
alternative (as outlined in appendix A of the final rule) are:
(1) You must include in your demonstration every emission point
covered under the final rule.
(2) You must conduct HCl and chlorine emissions tests for every
emission point covered under the final rule.
(3) You must determine the total maximum hourly mass HCl-equivalent
emission rate for your affected source by summing the maximum hourly
emission rates of HCl and chlorine for each of the affected units at
your facility covered under the final rule.
(4) Use the look-up table in the appendix A of the final rule to
determine if your facility is in compliance with the health-based HCl-
equivalent emission limit.
(5) Select the maximum allowable HCl-equivalent emission rate from
the look-up table in appendix A of the final rule for your affected
source using the average stack height of your emission units covered
under the final rule as your stack height and the minimum distance
between any affected emission point and the property boundary as your
property boundary.
(6) Your facility is in compliance if your maximum HCl-equivalent
emission rate does not exceed the value specified in the look-up table
in appendix A of the final rule.
(7) As an alternative to using the look-up table, you may conduct a
site-specific compliance demonstration (as outlined in appendix A of
the final rule) which demonstrates that the subpart DDDDD units at your
facility are not expected to cause an individual chronic inhalation
exposure from HCl and chlorine which can exceed a Hazard Index (HI)
value of 1.0.
Total Selected Metals Compliance Alternative
In lieu of complying with the emission standard for total selected
metals (TSM) in the final rule based on the sum of emissions for the
eight selected metals, you may demonstrate eligibility for complying
with the TSM standard based on excluding manganese emissions from the
summation of TSM emissions for the affected source unit(s).
The procedures for demonstrating eligibility for the TSM compliance
alternative (as outlined in appendix A of the final rule) are:
(1) You must include in your demonstration every emission point
covered under the final rule that emits manganese.
(2) You must conduct manganese emissions tests for every emission
point covered under the final rule that emits manganese.
(3) You must determine the total maximum hourly manganese emission
rate from your affected source by summing the maximum hourly manganese
emission rates for each of the affected units at your facility covered
under the final rule.
(4) Use the look-up table in appendix A of the final rule to
determine if your facility is eligible for complying with the
alternative TSM limit based on the sum of emissions for seven metals
(excluding manganese) for the affected source units.
(5) Select the maximum allowable manganese emission rate from the
look-up table in appendix A of the final rule for your affected source
using the average stack height of your emission units covered under the
final rule as your stack height and the minimum distance between any of
those emission points and the property boundary as your property
boundary.
(6) Your facility is eligible if your maximum manganese emission
rate does not exceed the value specified in the look-up table in
appendix A of the final rule.
(7) As an alternative to using look-up table to determine if your
facility is eligible for the TSM compliance alternative, you may
conduct a site-specific compliance demonstration (as outlined in
appendix A of the final rule) which demonstrates that the subpart DDDDD
units at your facility are not expected to cause an individual chronic
inhalation exposure from manganese which can exceed a Hazard Quotient
(HQ) value of 1.0.
If you elect to demonstrate eligibility for either of the health-
based compliance alternatives, you must submit certified documentation
supporting compliance with the procedures at least 1 year before the
compliance date.
You must submit supporting documentation including documentation of
all maximum capacities, existing control devices used to reduce
emissions, stack parameters, and property boundary distances to each
affected source of HCl-equivalent and/or manganese emissions.
You must keep records of the information used in developing the
eligibility demonstration for your affected source.
To be eligible for either health-based compliance alternative, the
parameters that defined your affected source as eligible for the
health-based compliance alternatives (including, but not limited to,
fuel type, type of control devices, process parameters reflecting the
emission rates used for your eligibility demonstration) must be
incorporated as Federally enforceable limits into your title V permit.
If you do not meet these criteria, then your affected source is subject
to the applicable emission
[[Page 55228]]
limits, operating limits, and work practice standards in the final
rule.
If you intend to change key parameters (including distance of stack
to the property boundary) that may result in lower allowable health-
based emission limits, you must recalculate the limits under the
provisions of this section, and submit documentation supporting the
revised limits prior to initiating the change to the key parameter.
If you intend to install a new solid fuel-fired boiler or process
heater or change any existing emissions controls that may result in
increasing HCl-equivalent and/or manganese emissions, you must
recalculate the total maximum hourly HCl-equivalent and/or manganese
emission rate from your affected source, and submit certified
documentation supporting continued eligibility under the revised
information prior to initiating the new installation or change to the
emissions controls.
III. What Are the Significant Changes Since Proposal?
A. Definition of Affected Source
The definition of affected source in Sec. 63.7490 has been revised
to be: (1) The collection of all existing industrial, commercial, or
institutional boilers or process heaters within a subcategory located
at a major source; and/or (2) each new or reconstructed industrial,
commercial, or institutional boiler or process heater located at a
major source.
B. Sources Not Covered by the NESHAP
The applicability section of the final rule (Sec. 63.7490(c)) has
been written to clarify that the following are not subject to the final
rule: Blast furnace stoves, any boiler or process heater specifically
listed as an affected source in another MACT standard, temporary
boilers, and blast furnace gas fuel-fired boilers and process heaters.
C. Emission Limits
The emission limit for mercury in the existing large solid fuel
subcategories has been written as 0.000009 lb/MMBtu (from 0.000007 lb/
MMBtu at proposal).
D. Definitions Added or Revised
The EPA has written the definitions of large, limited use, and
small gaseous subcategories to include gaseous fuel-fired boilers and
process heaters that burn liquid fuel during periods of gas curtailment
or gas supply emergencies.
The final rule also includes a definition of fuel type which is
used in the fuel analysis compliance options. Fuel type means each
category of fuels that share a common name of classification. Examples
include, but are not limited to: bituminous coal, subbituminous coal,
lignite, anthracite, biomass, construction/demolition material, salt
water laden wood, creosote treated wood, tires, and residual oil.
Individual fuel types received from different suppliers are not
considered new fuel types except for construction/demolition material.
Construction/demolition material means waste building material that
result from the construction or demolition operations on houses and
commercial and industrial buildings.
Unadulterated wood, component of biomass, means wood or wood
products that have not been painted, pigment-stained, or pressure
treated with compounds such as chromate copper arsenate,
pentachlorophenol, and creosote. Plywood, particle board, oriented
strand board, and other types of wood products bound by glues and
resins are included in this definition.
We have included a definition for temporary boiler to mean any
gaseous or liquid fuel-fired boiler that is designed, and is capable
of, being carried or moved from one location to another. A temporary
boiler that remains at a location for more than 180 consecutive days is
no longer considered to be a temporary boiler. Any temporary boiler
that replaces a temporary boiler at a location and is intended to
perform the same or similar function will be included in calculating
the consecutive time period.
The final rule also contains a definition written for waste heat
boiler that identifies waste heat boilers incorporating duct or
supplemental burners that are designed to supply 50 percent or more of
the total rated heat input capacity of the waste heat boiler as not
being waste heat boilers, but are considered boilers and subject to the
final rule.
E. Requirements for Sources in Subcategories Without Emission Limits or
Work Practice Requirements
In the final rule, we have clarified that sources in the existing
large and limited use gaseous fuel subcategories, existing large and
limited use liquid fuel subcategories, and new small liquid fuel
subcategory that burn only distillate oil are only subject to the
initial notification requirements in Sec. 63.9(b) of subpart A of this
part and are not required to submit as startup, shutdown, and
malfunction (SSM) plan as part of their initial notification. We have
written the final rule to state that sources in the existing small
gaseous fuel, liquid fuel, and solid fuel subcategories and in the new
small gaseous fuel subcategory are not subject to any requirements in
the final rule or of subpart A of this part.
F. Carbon Monoxide Work Practice Emission Levels and Requirements
The final rule provides revisions to the CO work practice emission
levels. For new sources in the solid fuel subcategory, the work
practice standard has been written to be corrected to 7 percent oxygen
rather than 3 percent. Units in the gaseous and liquid fuel
subcategories still have to correct to 3 percent oxygen.
The final rule also allows sources with heat input capacities
greater than 10 MMBtu/hr but less than 100 MMBtu/hr to conduct initial
and annual compliance tests to demonstrate compliance with the CO
limit. Sources greater than 100 MMBtu/hr must still demonstrate
compliance using CO continuous emission monitors (CEMS).
The final rule also does not allow you to calculate data average
using data recorded during periods where your boiler or process heater
is operating at less than 50 percent of its rated capacity, monitoring
malfunctions, associated repairs, out-of-control periods, or required
quality assurance or control activities. You must use all data
collected during all other periods in assessing compliance.
G. Fuel Analysis Option
We have clarified the fuel analysis options in the final rule. You
are not required to conduct performance tests for hydrogen chloride,
mercury, or total selected metals if you demonstrate compliance with
the hydrogen chloride, mercury, or total selected metals limits based
on the fuel pollutant content. Your operating limit is then the
emission limit of the applicable pollutant. You are not required to
conduct emission tests.
If you demonstrate compliance with the HCl, mercury, or TSM limit
by performance tests, then your operating limits are the operating
limits of the control device (if used) and the fuel pollutant content
of the fuel type/mixture burned. Units burning multiple fuel types are
required to determine by fuel analysis, the fuel pollutant content of
the fuel/mixture burned during the performance test.
The final rule specifies the testing and initial and continuous
compliance requirements to be used when complying with the fuel
analysis options. Fuel analysis tests for total chloride, gross
calorific value, mercury, metal analysis, sample collection, and sample
preparation are included in the final rule.
[[Page 55229]]
We have written the requirement to remove the need for conducting
additional tests if you receive fuel from a new supplier. You are
required to conduct another performance test, if you demonstrated
compliance through performance testing, only when you burn a new fuel
type or mixture and the results of recalculating the fuel pollutant
content are higher than the level established during the initial
performance test.
H. Emissions Averaging
We have included a compliance alternative in the final rule to
allow emissions averaging between existing large solid fuel boilers.
Compliance must be demonstrated on a 12-month rolling average basis,
determined at the end of every month. If you elect to comply with the
emissions averaging compliance alternative, you must use equations
provided in the final rule to demonstrate that particulate matter or
TSM, HCl, or mercury from all applicable units do not exceed the
emission limits specified in the final rule. If you use this option,
you must also develop and submit an implementation plan no later than 6
months before the date that the facility intends to demonstrate
compliance.
I. Opacity Limit
At proposal, we required sources meeting the PM and mercury limits
to determine site-specific opacity operating limits based on levels
during the initial performance test. To demonstrate continuous
compliance with the opacity limit, the opacity operating limits have
been established to be 20 percent (based on 6-minute averages) except
for one 6-minute period per hour of not more than 27 percent for
existing sources and 10 percent (based on 1-hour block averages) for
new sources.
J. Operating Limit Determination
The final rule defines maximum and minimum operating parameters
that must be met. For sources complying with the alternative opacity
requirement of establishing opacity limits during the initial
performance test, the maximum opacity operating limit is 110 percent of
the highest test-run average opacity measured according to the final
rule during the most recent performance test demonstrating compliance
with the applicable emission limit. For sources meeting the standards
using scrubbers or ESP, the minimum pressure drop, scrubber effluent
pH, scrubber flow rate, sorbent flow rate, voltage or amperage means 90
percent of the lowest test run average pressure drop, scrubber effluent
pH, scrubber flow rate, sorbent flow rate, voltage or amperage measured
according to the most recent performance test demonstrating compliance
with the applicable emission limits.
The final rule clarifies that operation above the established
maximum or below the established minimum operating parameters
constitute a deviation of established operating parameters.
K. Revision of Compliance Dates
In Sec. 63.7510, we have also written the date by which you have
to complete a compliance demonstration to be 180 days after the
compliance date instead of at the compliance date.
IV. What Are the Responses to Significant Comments?
We received 218 public comment letters on the proposed rule.
Complete summaries of all the comments and responses are found in the
Response-to-Comments document (see SUPPLEMENTARY INFORMATION section).
A. Applicability
Comment: Many commenters requested that EPA exempt units that are
not subject to emission limits or work practice requirements from
monitoring, recordkeeping, and reporting requirements.
Response: Sources in subcategories that do not have any emission
limitations and work practices are not required to keep records or
reports other than the initial notification. This is appropriate
because no reports other than the initial notification would apply to
these units. The SSM plan is not necessary nor required for these units
because Sec. 63.6(e)(3) of subpart A of this part requires an affected
source to develop an SSM plan for control equipment used to comply with
the relevant standard. The proposed rule was not intended to require
monitoring, recordkeeping, and reporting (including startup, shutdown,
and malfunction plans), other than the initial notification for sources
not subject to an emission limit. We have clarified this decision in
the final rule. We have also determined that existing small units and
new small gaseous fuel units, which are not subject to emission limits
or work practices in this standard, and which are also not subject to
such requirements in any other Federal regulation, should also not have
to provide an initial notification. These small sources are generally
gas-fired and since they have minimal emissions, they are usually
considered as insignificant emission units by State permitting
agencies.
Comment: Several commenters requested that EPA specifically exclude
portable/transportable units from the final rule. The commenters stated
that facilities periodically use these units to supply or supplement
other site steam supplies when there is a mechanical problem that takes
a unit out of service or during planned outages. The commenters added
that because they are used on a limited basis, portable units are not
fully integrated with site control systems and most portable/
transportable units are owned by a rental company and may not be
operated by the facility owner/operator.
Response: We agree with the commenters that temporary/portable
units are used only on a limited basis and are not integrated into a
facility's control system. These units are gas or oil fired units.
Units in the existing gaseous or liquid subcategories are not subject
to emission limits or work practice standards. Consequently, we have
decided that temporary/portable units are not subject to the final
rule. We have added a definition for temporary boiler to mean any
gaseous or liquid fuel-fired boiler that is designed, and is capable
of, being carried or moved from one location to another. A temporary
boiler that remains at a location for more than 180 consecutive days is
no longer considered to be a temporary boiler. Any temporary boiler
that replaces a temporary boiler at a location and is intended to
perform the same or similar function will be included in calculating
the consecutive time period. We chose the 180-day time frame because
that is the length of time a new source has after startup to conduct
the initial performance test.
Comment: Several commenters requested EPA provide a lower size cut-
off for the small unit subcategory. Several commenters argued that the
benefits from requiring smaller units to install controls would be
minimal given the overall monitoring, recordkeeping, and reporting
burden. Several commenters also requested lower size cutoffs to make
the final rule similar to others established by EPA (e.g., NSPS
Nitrogen Oxide (NOX) SIP Call). Several commenters noted
several recent court decisions in which the court has decided that a de
minimis exemption is appropriate since the regulation of small sources
would yield a gain of trivial or no value yet would impose significant
regulatory burden. A wide range of lower size cutoffs were suggested.
However, one commenter said that EPA should not develop de minimis
exemptions. The commenter noted that de minimis exemptions do not spare
EPA's resources for use on other
[[Page 55230]]
purposes and are not justified by reductions in industry burden or
inconvenience. The commenter noted that EPA did not establish any
administrative record justifying the de minimis exemption.
Response: We have reviewed the commenters arguments and all the
data provided in the comment letters. There is no justification for
developing a lower size cut-off or de minimis level. We would also note
the designation of large and small subcategories was not based solely
on size of the unit. Large and small subcategories were developed
because small units less than 10 MMBtu/hr heat input typically use a
combustor design that is not common in larger units. Large boilers
generally use the watertube combustor design. The design of the boiler
or process heater will influence the completeness of the combustion
process which will influence the formation of organic HAP emissions.
Additionally, the vast majority of small units use natural gas as fuel.
The EPA chose to develop large and small subcategories to account for
these differences and their affect on the type of emissions. The cut-
off between the large and small subcategories of 10 MMBtu/hr was based
on typical sizes for fire tube units, and also when considering cut-
offs in State and Federal rules. Lastly, we would like to note that the
final rule does not impose any requirements for existing units in any
of the small subcategories.
Comment: Many commenters asked EPA to clarify which sources are not
covered by the final rule.
Response: We have included an extensive list of sources that are
not subject to the final rule. The final rule clarifies that boilers
and process heaters that are included as part of the affected source in
any other NESHAP are not subject to the NESHAP for industrial boilers
and process heaters. However, we do not exclude boilers and process
heaters that are used as control devices unless they are specifically
considered part of any other NESHAP's definition of affected source.
Incinerators, thermal oxidizers, and flares do not generally fall under
the definition of a boiler or process heater and would not be subject
to the final rule. The final rule excludes waste heat boilers and waste
heat boilers with supplemental firing, as long as the supplemental
firing does not provide more than 50 percent of the waste heat boiler's
heat input. If your waste heat boiler does receive 50 percent of its
total heat input from supplemental firing, it would be subject to the
NESHAP for industrial boilers unless it is subject to any other NESHAP.
We specifically exclude comfort heaters from the final rule. However,
this exclusion does not include boilers used to make steam or heated
water for comfort heat. If your boiler meets the definition of a hot
water heater, then it would not be subject to the final rule. However,
if the temperature, pressure, or capacity specifications of your boiler
exceed the criteria specified for hot water heaters, then your boiler
would be subject to the final rule. We recognize the unique properties
of blast furnace gas having high CO concentrations and none to almost
no organic compounds. Consequently, we agree that for these sources CO
is not a surrogate for organic HAP emissions since CO is the primary
component of blast furnace gas and virtually no organic HAP are
generated in its combustion. As a result, we exclude from the final
rule units that receive 90 percent or more of their total heat input
from blast furnace gas. In addition, research and development (R&D)
operations are not subject to the final rule. However, units that only
provide steam to a process or for heating at a research and development
facility are still subject to the final rule. This should address the
commenters' concern over overlapping applicability.
Comment: Several commenters suggested that EPA revise the proposed
definition of affected source to be consistent with the definition of
affected source in the General Provisions. The definition in the rule
as proposed is much more narrow than that in the General Provisions,
even though the General Provisions states that each standard will
redefine affected source based on published justification as to why the
definition would result in significant administration, practical or
implementation problems. The commenters argued that EPA failed to
provide justification for the proposed definition of affected source,
which is narrower than the definition of affected source in the General
Provisions.
Response: We agree with the commenters and in the final rule have
incorporated the broader definition of affected source from the revised
General Provisions. The General Provisions define the affected source
as ``the collection of equipment, activities, or both within a single
contiguous area and under common control that is included in a section
112(c) source category or subcategory * * *'' Therefore, the definition
of existing affected source in the final rule is the collection of
existing industrial, commercial, or institutional boilers and process
heaters within a subcategory located at a major source of HAP
emissions.
B. Format
Comment: Several commenters opposed using one or more surrogates
for the HAP regulated. Some commenters stated that EPA must set
emission standards for each HAP emitted by this category. One commenter
explained that the use of surrogates is acceptable if: (1) The
surrogates reflect the actual emissions of the represented pollutants,
(2) the emission limit set for the surrogate is consistent with the
emission limit calculated for the represented pollutants, and (3) the
surrogates have substantially the same properties as the represented
pollutants and is controlled by the same mechanism. Based on these
criteria, the commenter argued that EPA's selection of surrogates is
inadequate. One commenter specifically contended that CO is not an
adequate surrogate for dioxin because dioxin emissions are affected by
the temperature of the emissions, how quickly the temperature is
lowered, and the levels of chlorine in the materials that are being
combusted and control devices. Other commenters supported the use of
surrogates to represent the HAP list.
Response: As discussed in the proposal preamble, the use of
surrogates for the HAP regulated is appropriate. Because of the large
number of HAP potentially present, the disparity in the quality and
quantity of the emissions information available, particularly for
different fuel types, we chose to group HAP into four categories:
Mercury, non-mercury metallic HAP, inorganic HAP, and organic HAP. In
general, the pollutants within each group have similar characteristics
and can be controlled with the same techniques. We then chose compounds
that could be used as surrogates for all the compounds in each
pollutant category. We have used surrogates in previous NESHAP as a
technique to reduce the performance testing costs, and thus the use of
surrogates is appropriate in the final rule.
For inorganic HAP, we chose to use HCl as a surrogate. The
emissions test information available to us indicated that the primary
inorganic HAP emitted from boilers and process heaters is HCl. Much
smaller amounts of hydrogen fluoride and chlorine are emitted. Control
technologies that would reduce HCl would also control other inorganic
HAP. Additionally, we had limited emissions information for other
inorganic HAP. By focusing on HCl, we have achieved control of the
largest emitted and most widely emitted HAP,
[[Page 55231]]
and control of HCl would also constitute control of other inorganic
HAP.
For non-mercury metallic HAP, we chose to use PM as a surrogate.
Most, if not all, non-mercury metallic HAP emitted from combustion
sources will appear on the flue gas fly-ash. Therefore, the same
control technology that would be used to control fly-ash PM will
control non-mercury metallic HAP. A review of data in the emission
database for PM control devices having both inlet and outlet emissions
results shows control efficiencies for each non-mercury metallic HAP
similar to PM. Particulate matter was also chosen instead of a specific
metallic HAP because all fuels do not emit the same type and amount of
metallic HAP, but most generally emit PM that includes some amount and
combination of metallic HAP. We maintain that particulate matter
reflects the emissions of non-mercury metallic HAP as these compounds
usually comprise a percentage of the emitted particulate matter. Since
the NESHAP program is technology-based, the technologies that have been
developed and implemented to control particulate matter, also control
non-mercury metallic HAP. Furthermore, since non-mercury metallic HAP
is a component of particulate matter, we can use particulate matter as
a surrogate for the purposes of the final rule.
While we did use PM as a surrogate for non-mercury metallic HAP, we
also provided an alternative total selected metals emission limit based
on the sum of the emissions of the eight most common and largest
emitted metallic HAP compounds from boilers and process heaters. Again,
a total selected metals number was used instead of limits for each
individual metallic HAP because sufficient information was not
available for each metallic HAP for every fuel type. However, a total
metals number could be calculated for every fuel type.
We realize that mercury emissions can exist in different forms
depending on combustion conditions and concentrations of other
compounds. That is why we have mercury as a separate pollutant category
in the final rule and do not provide for a surrogate.
For organic HAP, we chose to use CO as a surrogate to represent the
variety of organic compounds emitted from the various fuels burned.
Both organic HAP and CO emissions are the result of incomplete
combustion of the fuel. Because CO is a good indicator of incomplete
combustion, there is a direct correlation between CO emissions and
minimizing organic HAP emissions. The extent to which CO and HAP
emissions are related can also depend on site-specific operating
conditions for each boiler or process heater. This site-specific nature
may result in various degrees of correlation between CO and organic HAP
emissions, but it is proven that reductions in CO emissions result in a
reduction of organic HAP emissions. The control methods for both CO and
organic HAP are the same, i.e., complete combustion. This result would
not have been different if MACT floor analyses were conducted for
specific organic HAP or for a surrogate compound such as CO. For
boilers and process heaters, we have determined that CO is a reasonable
indicator of incomplete combustion. Also, we did not set emission
limits for each specific organic HAP because we lacked sufficient
information for many of the organic HAP for all the fuels combusted. We
acknowledge that there are many factors that affect the formation of
dioxin, but we also recognize that dioxin can be formed in both the
combustion unit and downstream in the associated PM control device.
Minimizing organic HAP emissions can limit the formation of dioxin in
the combustion unit. We reviewed all the good combustion practice (GCP)
information available in the boiler population database and determined
that no floor level of control exists, except for limiting CO
emissions, such that GCP could be incorporated into the standard. One
control technique, controlling inlet temperature to the PM control
device, that has demonstrated controlling downstream formation of
dioxins in other source categories (e.g., municipal waste combustors)
was analyzed for industrial boilers. In all cases, no increase in
dioxins emissions were indicated across the PM control device even at
high inlet temperatures. However, we requested comment on controls that
would achieve reductions of organic HAP, including any additional data
that might be available. The EPA did not receive any additional
supporting information or data. Additionally, more stringent options
beyond the floor level of control were evaluated, but were determined
to be too costly and emissions reductions associated with the options
could not be evaluated because no information was available that
indicated a relationship between the GCP and emission reduction of
organics (including dioxin).
C. Compliance Schedule
Comment: Many commenters requested that EPA provide an additional
year to comply with the final rule. Commenters explained that the time
lines associated with permitting, capital appropriation, project bid,
and construction activities are significant and that the 3-year
deadline would not provide adequate time for the estimated 3,730
existing units at affected sources to be retrofitted as necessary to
meet the new MACT standards. The commenters added that sources subject
to the final rule would also be competing with sources that are subject
to other combustion rules for the same vendors.
Response: The EPA disagrees with the commenters that the 3-year
compliance deadline is too short considering the number of sources that
will be competing for the resources and materials from engineering
consultants, equipment vendors, construction contractors, financial
institutions, and other critical suppliers. The EPA recognizes the
possibility that these same consultants, vendors, etc., may also be
used to comply with the utility MACT standard. However, we know that
many sources will not need to install controls. As a result, since not
everyone will need more than 3 years to actually install controls, the
final rule does not allow an extra year for existing sources to comply
with the final rule. Section 112(i)(3)(B) of the CAA allows EPA or the
permit authority, on a case-by-case basis, to grant an extension
permitting an existing source up to 1 additional year to comply with
standards if such additional period is necessary for the installation
of controls. This provision is sufficient for those sources where the
3-year deadline would not provide adequate time to retrofit as
necessary to comply with the requirements of the standard. We
anticipate that a number of units will seek and be granted the 1-year
extension since construction of needed control devices could be
constrained by the potential impacts on delays in obtaining funding and
potential labor and equipment shortages.
D. Subcategorization
Comment: Two commenters said that EPA does not have the authority
to develop subcategories for the purpose of reducing compliance costs
or weakening the standard. The commenters also noted that costs should
not be considered in subcategorizing and establishing the MACT floor.
One commenter explained that EPA has failed to present a persuasive
rationale for the establishment of new or different subcategories, such
as a wood-fired unit subcategory and noted that EPA cannot
subcategorize based on fuel type, cost, level of emissions reductions,
control technology applicability or effectiveness, achievability of
emissions reductions, or health risks. The
[[Page 55232]]
commenter argued that EPA cannot subcategorize to reduce cost because
that would change CAA section 112 standards into a cost-benefit program
and that is not legally defensible. The commenter noted that the DC
Circuit court recently held that, when confronted with the cost
argument, costs are not relevant when determining MACT floors.
Response: If the commenters are referring to the request for
comment regarding further subcategorizations than what was proposed,
the EPA agrees that there is no justification for any further
subcategories. The final rule maintains the subcategories presented in
the proposed rule. If the commenters are referring to subcategories
presented in the proposed rule, section 112(d)(1) of the CAA states
``the Administrator may distinguish among classes, types, and sizes of
sources within a category or subcategory'' in establishing emission
standards. Thus, we have discretion in determining appropriate
subcategories based on classes, types, and sizes of sources. We used
this discretion in developing subcategories for the industrial,
commercial, and institutional boilers and process heaters source
category. Through subcategorization, we are able to define subsets of
similar emission sources within a source category if differences in
emissions characteristics, processes, air pollution control device
(APCD) viability, or opportunities for pollution prevention exist
within the source category. We first subcategorized boilers and process
heaters based on the physical state of the fuel (solid, liquid, or
gaseous), which will affect the type of pollutants emitted and controls
applicable, and the design and operation of the boiler, which
influences the formation of organic HAP emissions. We then further
subcategorized boilers and process heaters based on size. Our
distinctions are based on technological differences in the equipment.
For example, small units are package units typically having capacities
less than 10 million Btu per hour heat input and use a combustor design
which is not common in large units. A review of the information
gathered on boilers also shows that a number of units operate as
backup, emergency, or peaking units that operate infrequently. The
boiler database indicates that these infrequently operated units
typically operate 10 percent of the year or less. These limited use
boilers, when called upon to operate, must respond without failure and
without lengthy periods of startup. Since their use and operation are
different compared to typical industrial, commercial, and institutional
boilers, we decided that such limited use units should have their own
subcategory.
Neither the subcategories or MACT floor analysis was conducted
considering costs, either in the proposed rule or in the final rule.
Comment: Many commenters requested EPA to develop a separate
subcategory for small municipal electric utilities. Reasons for
creating a subcategory for small electrical utility steam generating
units included: (1) EPA has authority to establish such a subcategory
of sources to be regulated under CAA section 112 and is meant to
address control costs and feasibility, (2) past EPA practice supports
subcategorization in this instance, (3) differences between municipal
utility boilers and non-utility boilers justify subcategorization, and
(4) EPA cannot properly account for cost and energy concerns mandated
in the MACT standard setting process without subcategorization for
municipal utility boilers. The commenters added that the unique
physical attributes of municipally-owned utilities, as well as their
significant and direct impact on municipal tax base, support a separate
subcategorization.
Response: The EPA sees no technical or legal justification for
creating a separate subcategory for municipal utilities. Boilers at
municipal utilities fire the same type of fuels, have the same type of
combustor designs, and can use the same type of controls as other units
in the large subcategory. Consequently, the subcategories that are in
the final rule are the same as at proposal. We would also like to
clarify that subcategories were developed based on combustor design and
not on industrial sector. Also, had we gone beyond-the-floor, we would
have considered cost in the final determination. Since we did not go
beyond-the-floor level of control, cost did not play a role in the
analysis.
Comment: Many commenters requested EPA add a subcategory for medium
sized boilers and process heaters.
Response: The EPA does not see justification for creating a
separate subcategory for medium sized units. The designation of large
and small subcategories was not based
Response: The EPA does not see justification for creating a
separate subcategory for medium sized units. The designation of large
and small subcategories was not based solely on size of the unit. Large
and small subcategories were developed because small units less than 10
MMBtu/hr heat input typically use a combustor design that is not common
in larger units. Large boilers generally use the watertube combustor
design. The design of the boiler or process heater will influence the
completeness of the combustion process which will influence the
formation of organic HAP emissions. The EPA developed large and small
subcategories to account for these differences and their affect on the
type of emissions. The proposed size break between the large and small
subcategories of 10 MMBtu/hr was based on typical sizes for firetube
and cast iron units and considering cut-offs in State and Federal
permitting requirements and rules. The EPA does not view medium sized
boilers as being different than larger boilers. Combustor designs,
applicable air pollution control devices, fuels used, and operation are
similar for large and medium. While actual pollution controls used and
monitoring equipment may be different, the CAA does not allow EPA to
subcategorize on these parameters.
Section 112(d)(1) of the CAA allows EPA to distinguish among
classes, types, and size in establishing MACT standards. As indicated
above, at proposal, the size break selected between large and small
units of 10 MMBtu/hr was based on typical sizes for fire tube units and
also considering cut-offs in State and Federal permitting requirements
and emission rules. Based on comments, we have examined information in
the docket regarding the population and characteristics of industrial,
commercial, and institutional boilers. It is correct that boilers below
10 MMBtu/hr are generally not required to be permitted and are either
firetube or cast iron boilers. Based on review of the thousands of
responses received on an information collection request (ICR) conducted
during the rulemaking process, it is obvious and appropriate that the
distinction between small and large units needs to include size. It is
apparent from the ICR responses that facilities know the size of their
units but do not generally know the exact type of the units. Many
responses indicated that the boiler was both firetube and watertube.
Many more responses did not list the boiler type at all. Therefore, the
inclusion of size in the definition of small and large subcategories is
appropriate.
Based on review of the 1979 EPA document on boiler population and
the ICR survey database, the appropriate size break between small and
large type units is 10 MMBtu/hr. In the EPA document, 99 percent of the
boilers listed as being below 10 MMbtu/hr are either firetube or cast
iron. Since these trends are from a 25 year old report, we
[[Page 55233]]
analyzed our ICR survey database which confirmed these findings.
E. MACT Floor
Comment: Several commenters supported EPA's finding that the MACT
floor level for existing gas and liquid fuel-fired units is no
emissions reductions. Other commenters contended that EPA has legal
authority to set the MACT floor as ``no emissions control'' for
particular HAP categories. A commenter noted that EPA has a clear
statutory obligation to set emission standards for each listed HAP. One
commenter specifically challenged EPA's determination that ``no
control'' is the MACT floor for organic pollutants. The commenter noted
that the U.S. Court of Appeals for the DC Circuit had squarely held, in
the National Lime case, that EPA was not allowed to make a ``no
control'' determination for a pollutant emitted by a listed category of
sources.
Response: First, the MACT floor methodology we use is consistent
with DC Circuit's holding in the National Lime case. The DC Circuit
held that by focusing only on technology EPA ignored the directive in
CAA section 112(d)(2) to consider pollution-reducing measures including
process changes and substitution of materials.
The EPA has ample legal authority to set the MACT floor at ``no
emissions reductions.'' This is because the statute requires EPA to set
standards that are duplicable by others. In the National Lime case, the
court threw out EPA's determination of a no control floor because it
was based only on a control technology approach. The court stated that
EPA must look at what the best performers achieve, regardless of how
they achieve it. Therefore, our determination that the MACT floor for
certain subcategories or HAP is ``no emissions reductions'' is lawful
because we determined that the best-performing sources were not
achieving emissions reductions through the use of an emission control
system and there were no other appropriate methods by which boilers and
process heaters could reduce HAP emissions. Furthermore, setting
emissions standards on the basis of actual emissions data alone where
facilities have no way of controlling their HAP emissions would
contravene the plain statutory language as well as Congressional intent
that affected sources not be forced to shut down.
The EPA agrees with the commenter that all factors which might
control HAP emissions must be considered in making a floor
determination for each subcategory. However, EPA disagrees that it must
express the floor as a quantitative emission level in those instances
where the source on which the floor determination is based has not
adopted or implemented any measure that would reduce emissions.
A detailed discussion of the MACT floor methodology is presented in
the memorandum ``MACT Floor Analysis for New and Existing Sources in
the Industrial, Commercial, and Institutional Boilers and Process
Heaters Source Categories'' in the docket. In summary, we considered
several approaches to identifying MACT floor for existing industrial,
commercial, and institutional boilers and process heaters. Based on
recent court decisions, in most cases the most acceptable approach for
determining the MACT floor is likely to involve primarily the
consideration of available emissions test data. However, after review
of the available HAP emission test data, we determined that it was
inappropriate to use this MACT floor approach to establish emission
limits for boilers and process heaters. The main problem with using
only the HAP emissions data is that, based on the test data alone,
uncontrolled units (or units with low efficiency add-on controls) were
frequently identified as being among the best performing 12 percent of
sources in a subcategory, while many units with high efficiency
controls were not. However, these uncontrolled or poorly controlled
units are not truly among the best controlled units in the category.
Rather, the emissions from these units are relatively low because of
particular characteristics of the fuel that they burn, that can not
reasonably be replicated by other units in the category or subcategory.
A review of fuel analyses indicate that the concentration of HAP
(metals, HCl, mercury) vary greatly, not only between fuel types, but
also within each fuel type. Therefore, a unit without any add-on
controls, but burning a fuel containing lower amounts of HAP, can have
emission levels that are lower than the emissions from a unit with the
best available add-on controls. If only the available HAP emissions
data are used, the resulting MACT floor levels would, in most cases, be
unachievable for many, if not most, existing units, even those that
employ the most effective available emission control technology.
Another problem with using only emissions data is that there is very
limited or no HAP emissions information available to the Agency for the
subcategories. This is consistent with the fact that units in these
source categories have not historically been required to test for HAP
emissions.
We also considered using HAP emission limits contained in State
regulations and permits as a surrogate for actual emission data in
order to identify the emissions levels from the best performing units
in the category for purposes of establishing MACT standards. However,
we found no State regulations or State permits which specifically limit
HAP emissions from these sources.
Consequently, we concluded that the most appropriate approach for
determining MACT floors for boilers and process heaters is to look at
the control options used by the units within each subcategory in order
to identify the best performing units. Information was available
regarding the emission control options employed by the population of
boilers identified by the EPA. We considered several possible control
techniques (i.e., factors that influence emissions), including fuel
substitution, process changes and work practices, and add-on control
technologies.
We first considered whether fuel switching would be an appropriate
control option for sources in each subcategory. We considered the
feasibility of both fuel switching to other fuels used in the
subcategory and to fuels from other subcategories. This consideration
included determining whether switching fuels would achieve lower HAP
emissions. A second consideration was whether fuel switching could be
technically achieved by boilers and process heaters in the subcategory
considering the existing design of boilers and process heaters. We also
considered the availability of various types of fuel. After considering
these factors, we determined that fuel switching was not an appropriate
control technology for purposes of determining the MACT floor level of
control for any subcategory. This decision was based on the overall
effect of fuel switching on HAP emissions, technical and design
considerations, and concerns about fuel availability.
We also concluded that process changes or work practices were not
appropriate criteria for identifying the MACT floor level of control
for units in the boilers and process heaters category. The HAP
emissions from boilers and process heaters are either fuel dependent
(i.e., mercury, metals, and inorganic HAP) or combustion related (i.e.,
organic HAP). Fuel dependent HAP are typically controlled by removing
them from the flue gas after combustion. Therefore, they are not
affected by the operation of the boiler or process heater.
Consequently, process changes would be ineffective in reducing these
fuel-related HAP emissions.
On the other hand, organic HAP can be formed from incomplete
combustion
[[Page 55234]]
of the fuel. Good combustion practice (GCP), in terms of boilers and
process heaters, could be defined as the system design and work
practices expected to minimize organic HAP emissions. While few sources
in EPA's database specifically reported using good combustion
practices, the data that we have suggests that boilers and process
heaters within each subcategory might use any of a wide variety of
different work practices, depending on the characteristics of the
individual unit. The lack of information, and lack of a uniform
approach to assuring combustion efficiency, is not surprising given the
extreme diversity of boilers and process heaters, and given the fact
that no applicable Federal standards, and most applicable State
standards, do not include work practice requirements for boilers and
process heaters. Even those States that do have such requirements do
not require the same work practices. For example, CO emissions are
generally a good indicator of incomplete combustion, and, therefore,
low CO emissions might reflect good combustion practices. (As discussed
in the proposal, CO is considered a surrogate for organic HAP
emissions.) Therefore, we considered whether existing CO emission
limits might be used to establish good combustion practice standards
for boilers and process heaters. We reviewed State regulations
applicable to boilers and process heaters, and then for each
subcategory we matched the applicability of State CO emission limits
with information on the locations and characteristics of the boilers
and process heaters in the population database. Ultimately, we found
that very few units (less than 6 percent) in any subcategory were
subject to CO emission limits. We concluded that this information did
not allow EPA to identify a level of performance that was
representative of good combustion across the various units in any
subcategory. Therefore, we did not establish a CO emission limit, as a
surrogate for organic HAP emissions, as a part of the MACT floor for
existing units. However, we have considered the appropriateness of such
requirements in the context of evaluation possible beyond-the-floor
options.
In general, boilers and process heaters are designed for good
combustion. Facilities have an economic incentive to ensure that fuel
is not wasted, and the combustion device operates properly and is
appropriately maintained. In fact, existing boilers and process heaters
are used typically as high efficiency control devices to control
(reduce) emission streams containing organic HAP compounds from various
process operations. Therefore, EPA's inability to establish a
combustion practice requirement as part of the MACT floor for existing
sources in this category should not reduce the incentive for owners and
operators to run their boilers and process heaters at top efficiency.
As a result of the evaluation of the feasibility of establishing
emission limits based on control techniques such as fuel switching and
good combustion practices, we concluded that add-on control technology
should be the primary factor for purposes of identifying the best
controlled units within each subcategory of boilers and process
heaters. We identified the types of air pollution control techniques
currently used. We ranked those controls according to their
effectiveness in removing the different HAP categories of pollutants;
including metallic HAP and PM, inorganic HAP such as acid gases,
mercury, and organic HAP. We then listed all the boilers and process
heaters in the population database in order of decreasing control
device effectiveness within each subcategory for each pollutant type.
Then we identified the top 12 percent of units within each category
based on this ranking, and determined what kind of emission control
technology, or combination of technologies, the units in the top 12
percent employed. Finally, we looked at the emissions test data from
boilers and process heaters that used the same control technology, or
technologies, as the units in the top 12 percent to estimate the
average emissions limitation achieved by these units.
This approach reasonably ensures that the emission limit selected
as the MACT floor adequately represents the average level of control
actually achieved by units in the top 12 percent. The analysis of the
measured emissions from units representative of the top 12 percent is
reasonably designed to provide a meaningful estimate of the average
performance, or central tendency, of the best controlled 12 percent of
units in a given subcategory. For existing subcategories where less
than 12 percent of units in the subcategory use any type of control
technology, we looked to see if we could estimate the central tendency
of the best controlled units by looking at the unit occupying the
median point in the top 12 percent (the unit at the 94th percentile).
If the median unit of the top 12 percent is using some control
technology, we might use the measured emission performance of that
individual unit as the basis for estimating an appropriate average
level of control of the top 12 percent. For subcategories where less
than 6 percent of the units in a HAP grouping used controls or limited
emissions, the median unit for that HAP grouping reflects no emissions
reductions. Therefore, in these circumstances, EPA has appropriately
established the MACT floor emission levels for these sources as no
emission reduction.
Comment: Many commenters opposed EPA using emissions data from
units in the large subcategory to develop emission limits for units in
the small or limited use subcategories. Some commenters stated that it
was not appropriate to assume that emissions rates achievable by large
units are achievable by small units, even the best controlled units.
Other commenters argued that the use of large unit data in MACT
determinations for other subcategories would defeat the purpose of the
subcategorization and violate the requirements of CAA section 112
because the use of this data does not represent sources in the relevant
category or subcategory.
Response: The EPA disagrees with the commenters and maintains that
it has conducted the MACT floor analysis appropriately. Section 112(d)
of the CAA requires us to establish emission limits for new sources
based on the performance of the best-controlled similar source. The CAA
does not specify that the similar source must be within the same source
category or subcategory. To the contrary, our interpretation of section
112(d) is that we are obligated to consider similar sources from other
source categories or subcategories in determining the best-controlled
similar source for establishing MACT for new sources.
For new limited use and small units, we concluded that the best-
controlled similar sources are found in the large subcategory. First,
EPA determined the control technology used by the best controlled
sources in the subcategory. For example, only units in the population
database less than 10 MMBtu/hr (and not in the limited use subcategory)
were used to determine the MACT floor control technology for units in
the small subcategories. Second, EPA used information in the emissions
test database to establish the emission level associated with the MACT
floor control technology. The emissions test database did not contain
test data for limited use or small boilers and process heaters. Section
112(d) of the CAA requires EPA to use information from similar sources
to set the MACT floor. Such sources may not be in the same subcategory.
Although the units in the small and
[[Page 55235]]
limited use subcategories are different enough to warrant their own
subcategory (i.e., different purposes and operation), emissions of the
specific types of HAP for which limits are being proposed are expected
to be related more to the type of fuel burned and the type of control
used, than to unit operation. Consequently, EPA determined that
emissions information from large fuel-fired units could be used to
establish MACT floor levels for the small and limited use subcategories
because the fuels and controls are similar. The proposal preamble
requested additional information from commenters to refine/revise the
approach if necessary. No commenters provided emissions information for
limited use or small subcategory boilers or process heaters.
Comment: Several commenters requested that EPA account for
variability in fuel composition as MACT floors are established and to
provide adequate allowances for inherent fuel supply variability. Some
commenters argued that there is no flexibility in the rule to account
for this variability and noted that coal composition can vary by
location and also within an individual seam.
Response: As described in the memorandum ``Revised MACT Floor
Analysis for the Industrial, Commercial, and Institutional Boilers and
Process Heater National Emission Standards for Hazardous Air Pollutants
Based on Public Comments'' in the docket, the calculation of numerical
emission limits was a two-step analysis. The first step involved
calculating a numerical average of the appropriate subset of emission
test data. The second step involved generating and applying an
appropriate variability factor to account for unavoidable variations in
emissions due to uncontrollable variations in fuel characteristics and
ordinary operational variability. Accounting for variability is
appropriate in order to generate a more accurate estimation of the
actual, long term, performance of a source (e.g., the source occupying
the median point in the top 12 percent). An emission test provides a
momentary snapshot, not an estimation of continuous performance. In
order to translate the former into the latter, we must account for that
ordinary and unavoidable variability that the source is likely to
experience over time. This gives us a more reasonable estimate of the
actual level of emissions control that the unit is achieving. The EPA
contends that by considering the variability of emissions information,
we have indirectly incorporated variability in fuel, operating
conditions, and sampling and analytical conditions because these
parameters vary from emission tests conducted from one unit to another,
and even within each test set of three measurements at a single unit.
The most elementary measure of variation is range. Range is defined as
the difference between the largest and smallest values. This is the
variability methodology used in the proposed rule. That is, for each
unit with multiple emissions tests conducted over time, the variability
was calculated by dividing the highest three-run test result by the
lowest three-run test result. The overall variability was calculated by
averaging all the individual unit variability factors. This overall
variability factor was multiplied by the overall average emission level
to derive a MACT floor limit representative of the average emission
limitation achieved by the top 12 percent of units. This approach
adequately accounts for inherent fuel supply variability. Based on
comments, EPA did conduct a more robust statistical analysis (t-test)
of the mercury emissions data used in the MACT floor analysis to
identify the 97.5th percent confidence limit. This analysis provided
similar results to the variability analysis conducted in the proposed
rule. Consequently, EPA decided not to change its variability
methodology. A detailed discussion of the statistical analysis
conducted is provided in the memorandum ``Statistical Analysis of
Mercury Test Data Variability in Response to Public Comments on
Determination of the MACT Floor for Mercury Emissions'' in the docket.
Comment: Several commenters supported EPA's finding that the MACT
floor level of control for existing gaseous and liquid fuel units is no
control. Other commenters noted that EPA has a clear statutory
obligation to set emission standards for each listed HAP (the commenter
cited legal briefs). One commenter specifically challenged EPA's
determination of the MACT floor for organic pollutants. The commenter
explained that EPA should rank the units for which emissions data is
available according to the best performing units, not based on the add-
on control level of 6 percent of the total population. The commenter
noted that the U.S. Court of Appeals for the DC Circuit had squarely
held, in the National Lime case, that EPA was not allowed to make a
``no control'' determination for a pollutant emitted by a listed
category of sources.
Response: The EPA agrees that all factors which might control HAP
emissions must be considered in making a floor determination for each
subcategory. However, EPA disagrees that it must express the floor as a
quantitative emission level in those instances where the sources on
which the floor determination is based has not adopted or implemented
any measure that would reduce emissions. For several subcategories and
certain HAP, EPA has not identified any adjustments or other
operational modifications that would materially reduce emissions by
these units, and EPA had determined that no add-on controls are
presently in use. In these circumstances, EPA has established
appropriately the MACT floors for these sources as no emission
reduction.
Comment: One commenter pointed out that the variability factor used
to make the calculated MACT floor less stringent is not allowed by
section 112 of the CAA. The commenter mentioned that the variability
factors are not consistent, as one factor considers the fuel
variability and the other factor considers the test data variability.
Response: Section 112(d)(2) of the CAA requires that emissions
standards promulgated shall require the maximum degree of reductions in
emissions that the EPA Administrator, taking into consideration the
costs of achieving such emission reduction, determines is achievable
for new and existing sources in the subcategory to which such emission
standards applies. Accounting for variability is appropriate in order
to generate a more accurate estimation of the actual, long term,
performance of a source (e.g., the source occupying the median point in
the top 12 percent). An emission test provides a momentary snapshot,
not an estimation of continuous performance. In order to translate the
former into the latter, we must account for that ordinary and
unavoidable variability that the source is like to experience over
time. This give us a more reasonable estimate of the actual level of
emissions control that the unit is achieving. As such, due to
variations in fuel burned, and ordinary operational variability any
emission limit set from a point source measurement alone may not be
indicative of normal emissions or operations of the unit. Attempting to
base a standard (either a floor standard, or a beyond-the-floor
standard) solely on point measurements would lead to unachievable
standards for all sources. Limits set by EPA must be achieved at all
times, and it is important that the MACT floor limit adequately account
for the normal and unavoidable variability in the process and in the
operation of the control device.
Variability was assessed two ways. For existing subcategories,
variability in emissions information was used to develop variability
factors for all
[[Page 55236]]
subcategories where emissions information was available. Variability in
fuel content was used only in situations regarding determining the
achievable MACT floor level for new sources from the emission test
result on the best controlled similar source. This approach is
appropriate since the main uncertainty associated with the emission
test result from the best controlled similar source is fuel
variability. Corresponding fuel analysis results were not available for
the emissions test results from the best controlled similar source.
Whereas, the average emission level of the best 12 percent of the units
has, besides fuel variability, the uncertainty associated with
operational and design variability of the various control devices
installed on units that represent the best 12 percent of the units. For
example, available fuel analysis information shows that mercury content
of coal varies by a factor of 12.54. Dividing the highest mercury
emission test result by the lowest mercury test results from coal-fired
units included in units that represent the best 12 percent results in a
variability factor of 20. Therefore, we concluded that fuel
availability was inherently considered in the MACT floor analysis
approach used for existing subcategories.
Comment: Many commenters requested that EPA revise the MACT floor
methodology for mercury emission limits. The commenters contended that
the variability factor was calculated inappropriately. Other commenters
stated that EPA should account for variability in fuel composition in
the MACT floor analysis. Other commenters expressed concern that the
floor level of control was based on fabric filters, which has not been
proven at all sources to reduce mercury.
Response: As discussed in the proposal preamble, the MACT floor
analysis for mercury was based on a two step process. First the
percentage of units with control technologies that could achieve
mercury emissions reductions was determined using the boiler population
databases. If the control technology analysis indicated that at least
12 percent of sources in the subcategory used a control device that
could achieve mercury emissions reductions, then the control technology
present at the median (6th percentile) was identified as the MACT floor
control technology. The MACT floor level of control for mercury was
identified as a fabric filter. The control effectiveness of fabric
filters was based on emissions information for utility boilers that
indicated that mercury emissions reductions were being achieved with
this technology. In this case, we could use control efficiency
information from another similar source category to supplement the
information available in this source category because of the similarity
in fuel burned, combustor type, and control methodology and operation.
We maintain that fabric filters are still the appropriate level of
control for the MACT floor.
Second, the emission limit associated with the MACT floor control
technology was calculated using emissions information for units in the
subcategory, whenever possible. For most of the subcategories
developed, emissions information was adequate. Only for the emission
limit for new source liquids and the variability factor for new source
solids was fuel pollutant content incorporated into the MACT floor
analyses. The mercury fuel content of coal from the utility industry
was used in developing the variability factors for new solid fired
units. This was done because mercury emissions are dependent on the
quantity of mercury in the fuel burned. Coal available to utilities and
industrial boilers and process heaters is expected to be similar, and
coal is the solid fuel that is routinely used in such units that has
generally the greatest degree of HAP variability. We maintain that the
utility database used at proposal to develop the variability factor for
new sources was adequate in establishing the MACT floor emission limit.
The EPA recognizes that the mercury emissions database for
industrial boilers is limited. However, EPA is directed by the CAA to
develop standards for sources using whatever data is available. Prior
to proposal and during the Industrial Combustion Coordinated Rulemaking
(ICCR) process, EPA conducted a thorough search for HAP emission test
reports. This search was supported by industry, trade groups, and
States. For criteria pollutants, such as PM, substantial emission
information was available and gathered. For mercury and other HAP, this
was not the case. Industrial boilers have not generally been required
to test for HAP emissions. In the proposed rule, EPA requested
commenters to provide additional emissions information. However, only
one source provided any additional mercury emissions data. This
information (test results from three additional coal-fired industrial
boilers) was used to revise the mercury emission limit for existing
sources. We also reviewed the mercury emission database used to develop
the MACT floor emission limit for existing sources. After review, we
determined that a revision to the variability factor was appropriate.
The additional data and the revised variability factor was used to re-
calculate the mercury emission limit to be 0.000009 lb/MMBtu (from
0.000007 lb/MMBtu at proposal). A detailed discussion of the revised
MACT floor analysis conducted is provided in the memorandum ``Revised
MACT Floor Analysis for the Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for Hazardous
Air Pollutants Based on Public Comments'' in the docket.
Variability of the emissions data were incorporated into the final
emission limits. The EPA contends that by considering the variability
of emissions information, we have indirectly incorporated variability
in fuel, operating conditions, and sampling and analytical conditions
because these parameters vary from emission tests conducted from one
unit to another, and even within one unit. The EPA does not consider it
appropriate or feasible to incorporate variability from a multitude of
parameters because such information is not available and cannot be
correlated to the emissions information in the emissions test database.
For the final rule, EPA did conduct a statistical analysis of the data
to identify the 97.5th percent confidence interval. This analysis
provided similar results to the variability analysis conducted in the
proposed rule. Consequently, EPA decided not to change its variability
methodology. A detailed discussion of the statistical analysis
conducted is provided in the memorandum ``Statistical Analysis of
Mercury Test Data Variability in Response to Public Comments on
Determination of the MACT Floor for Mercury Emissions'' in the docket.
Comment: Several commenters contended that the California standards
which the CO requirements are based on do not require CO CEMS, but
require initial compliance testing and periodic subsequent performance
testing.
Response: The commenters are correct that the California CO
regulations do not require CO CEMS. The regulations do provide sources
with the option of conducting annual testing or installing CO CEMS to
demonstrate compliance with the CO emission limit. Because the
regulations that were the basis of the MACT floor do not provide
specifics on which boilers should conduct annual testing and which
should use CO CEMS, we reviewed the cost information provided by the
commenters to make this determination. In considering the additional
cost information and reviewing the cost information used in the
proposed rule, the EPA decided that
[[Page 55237]]
changes to the CO compliance requirements were warranted. The final
rule requires that new units with heat input capacities less than 100
MMBtu/hr conduct initial and annual performance tests for CO emissions.
New units with heat input capacities greater or equal to 100 MMBtu/hr
are still required to install, operate, and maintain a CO CEMS.
Regardless of whether the California regulations do or do not
require CO CEMS, we would have reviewed the need for continuous
monitoring and operating limits in order to ensure the most accurate
indication of proper operation of the control system. The purpose of
all of the minimum operating parameter limits in the standard is to
ensure continuous compliance by ensuring that the air pollution control
equipment is operating as they were during the latest performance test
demonstrating compliance with the emission limits. The operating
parameters are established as ``minimum'' to provide enforceable
boundaries in their operation. Operating outside the bounds of the
minimum parameters may lead to increased air emissions.
The EPA would also like to clarify that operation above the CO
limit constitutes a deviation of the work practice standard. However,
the determination of what deviations constitute violations of the
standard is up to the discretion of the entity responsible for
enforcement of the standards.
F. Beyond the MACT Floor
Comment: Many commenters contended that carbon injection should
have been required as a beyond-the-floor option. Other commenters
supported EPA's decision to not require any controls beyond-the-floor.
Response: For the final rule, EPA maintains that options beyond the
MACT floor are not appropriate for the standard. The EPA is required by
the CAA to set the standard at a minimum on the best controlled 12
percent of sources (for existing units) or best controlled similar
source (for new units). The CAA also requires EPA to consider costs and
non-air quality impacts and energy requirements when considering more
stringent requirements than the MACT floor. As documented in the
memorandum ``Methodology for Estimating Costs and Emissions Impacts for
Industrial, Commercial, and Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants'' in the
docket, EPA did consider the cost and emission impacts of a variety of
regulatory options more stringent than the MACT floor for each
subcategory. The EPA recognizes that for some subcategories, more
stringent controls than the MACT floor can be applied and achieve
additional emissions reductions. However, EPA also determined that the
cost impacts of such controls were very high. Considering both the
costs and emissions reductions, EPA determined that it would be
infeasible to require any options more stringent than the floor level.
For the final rule, EPA maintains that carbon injection should not
be required as an above the floor technology. As discussed in the
proposal preamble, we identified one existing industrial boiler that
was using carbon injection. The emissions data that we obtained from
the boiler indicated that this carbon injection unit was not achieving
mercury emissions reductions. This result led us to conclude that it
was not the new source floor level of control. However, there may have
been other reasons for the ineffectiveness of this system (e.g., low
inlet mercury levels, insufficient carbon injection rate, ESP instead
of fabric filter for PM control). Therefore, we considered carbon
injection as a beyond-the-floor option, but decided that while this
control technique has been used in other source categories, there is no
demonstrated evidence that it would work for industrial boilers and
process heaters because the type of mercury emitted and properties of
the emission streams are sufficiently different for boilers and process
heaters and other source categories.
G. Work Practice Requirements
Comment: Many commenters requested EPA consider exceedences of the
CO limit to be a trigger for corrective action rather than a violation.
Response: In the final rule, we have clarified that an exceedence
of the CO limit constitutes a deviation of the work practice standard.
An observed exceedence of a monitoring parameter is not an automatic
violation. You are required to report any deviation from an applicable
emission limitation (including operating limit). We will review the
information in your report along with other available information to
determine if the deviation constitutes a violation. The determination
of what emission or operating limit deviation constitutes violations of
the standard is up to the discretion of the entity responsible for
enforcement of the standard.
H. Compliance
Comment: Many commenters requested that EPA simplify and write the
fuel monitoring requirements to not require retesting of fuel for
changes in fuel supplier.
Response: We agree that the fuel monitoring requirements in the
proposal needed to be clarified and explained further. Therefore, we
have clarified the fuel analysis options in the final rule. If you
elect to demonstrate compliance with the HCl, mercury, or total
selected metals limit by using fuel which has a statistically lower
pollutant content than the emission limit, then your operating limit is
the emission limit of the applicable pollutant. Under this option, you
are not required to conduct performance tests (i.e. stack tests).
If you demonstrate compliance with the HCl, mercury, or total
selected metals limit by using fuel with a statistically higher
pollutant content than the applicable emission limit, but performance
tests demonstrate that you can meet the emission limits, then your
operating limits are the operating limits of the control device (if
used) and the fuel pollutant content of the fuel type/mixture burned.
The final rule specifies the testing methodology and procedures and
the initial and continuous compliance requirements to be used when
complying with the fuel analysis options. Fuel analysis tests for total
chloride, gross calorific value, mercury, metal analysis, sample
collection, and sample preparation are included in the final rule.
If you elect to comply based on fuel analysis, you are required to
statistically analyze, using the z-test, the data to determine the 90th
percentile confidence level. It is the 90th percentile confidence level
that is required to be used to determine compliance with the applicable
emission limit. The statistical approach is required to assist in
ensuring continuous compliance by statistically accounting for the
inherent variability in the fuel type.
You are required to recalculate the fuel pollutant content only if
you burn a new fuel type or fuel mixture. You are required to conduct
another performance test if you demonstrate compliance through
performance testing, you burn a new fuel type or mixture, and the
results of recalculating the fuel pollutant content are higher than the
level established during the initial performance test.
Comment: Many commenters requested EPA consider exceedences of
[[Page 55238]]
parametric limits to be a trigger for corrective action rather than a
violation.
Response: In the final rule, we have clarified that an exceedence
of the parametric limits constitute a deviation of the operating
limits. An observed exceedence of a monitoring parameter is not an
automatic violation. You are required to report any deviation from an
applicable emission limitation (including operating limit). We will
review the information in your report along with other available
information to determine if the deviation constitutes a violation. The
determination of what emission or operating limit deviation constitutes
violations of the standard is up to the discretion of the entity
responsible for enforcement of the standard.
Comment: Many commenters requested EPA revise the opacity
requirements. Commenters objected to the provision in the proposed
NESHAP that would establish an opacity ``operating limit'' based on the
initial performance test. Some commenters contended that EPA has
provided no data or references demonstrating a relationship between
opacity and particulate, total metals, or mercury emissions. Other
commenters argued that the proposed opacity limit approach for dry
control devices is unworkable due to the inherent inability of
continuous opacity monitors (COMS) to accurately measure opacity at
levels less than 10 percent. Some commenters argued that the
performance and opacity achieved during the initial test may not be
representative of the unit's performance. Other commenters explained
that equipment condition, fuel and operating variations, and other
uncontrollable parameters may result in varying emissions and emissions
control equipment efficiencies over time. Commenters suggested
requiring the NSPS limits for opacity rather than setting opacity based
on the initial compliance test.
Response: We have reviewed the information provided by the
commenters, and agree that the opacity operating limit requirements in
the proposed rule are not appropriate for this source category. Because
of the variability in fuels burned, the combination of fuels burned,
and the typical operation of boilers and process heaters, we have
decided that an opacity limit set based on the initial performance test
may not be representative of the units typical performance.
We have revised the opacity operating limit provision by requiring
existing units to maintain opacity to less than or equal to 20 percent
(based on 6-minute averages) except for one 6-minute period per hour of
not more than 27 percent. This is the opacity limit contained in the
current NSPS for industrial boilers, which has a similar PM emission
limit as the final rule. Therefore, it was determined that it was
appropriate to include a similar opacity level as the control device
operating limit for existing units. New sources can maintain their
opacity operating limit to less than or equal to 10 percent (based on
1-hour block averages). This level appears to be the lowest opacity
level currently applicable to industrial boilers in State regulations.
Comment: Several commenters objected to the requirement to conduct
performance testing at worst case conditions. The commenters found this
requirement to be unrealistic because stack testing must be scheduled
well in advance and worst-case conditions depend on fuel, load, and
many other variables, making it impossible to assure that the testing
will occur during worst-case conditions. Two commenters contended there
can be no guarantee that mineral properties for a fuel source at the
time of the baseline test can be guaranteed beyond the content
identified during purchase contract negotiations with a fuel supplier.
Two commenters suggested that EPA define what worst case conditions are
because sources do not have the experience to determine worst-case
representative process conditions.
Response: We agree that more direction and clarification is needed
regarding testing at worst case conditions. We have modified fuel
sampling requirements and performance testing fuel use requirements to
simplify compliance. During performance testing, sources are required
to burn the type of fuel or mixture of fuel types that have the highest
concentration of regulated HAP. This, in combination with revised fuel
sampling requirements (e.g., based on fuel type and not on supplier,
etc.), will simplify the determination of the fuel blend during the
performance test. Sources are also required to conduct performance
tests under representative full load operating conditions.
Comment: Several commenters objected to the requirement for annual
performance tests because they felt that it is overly burdensome given
the ongoing compliance demonstrations required by the NESHAP. Several
commenters suggested that initial performance testing should be
required with subsequent performance testing occurring every 3 to 5
years. Some commenters stated that 5-year test intervals are consistent
with title V permits and have been allowed in other MACT standards
(e.g. Hazardous Waste Combustors).
Response: We have worked to minimize the testing and monitoring
requirements of the final rule while retaining the ability to ensure
compliance with the emission limits and work practice requirements. We
are providing an option for sources to conduct performance testing once
every 3 years if they conduct successful performance testing for 3
consecutive years. We are also allowing sources to demonstrate
compliance with the HCl, mercury, and total selected metals emission
limits through fuel testing if they do not need emission control
devices to achieve the standard.
I. Emissions Averaging
In the proposal preamble, we solicited comments on an emissions
averaging or bubbling compliance alternative, as part of the EPA's
general policy of encouraging the use of flexible compliance approaches
where they can be properly monitored and enforced, and whether EPA
should include emissions averaging in the final rule. Emissions
averaging can provide sources the flexibility to comply in the least
costly manner while still maintaining regulation that is workable and
enforceable. We requested comment on an averaging approach for
determining compliance with the non-mercury metallic HAP, HCl, mercury,
and/or PM standards for existing sources. We indicated that averaging
would allow owners and operators to submit non-mercury metals, mercury,
HCl, and/or PM emissions limits to the EPA Administrator for approval
for each existing boiler in the averaging group such that if these
emission limits are met, the total emissions from all existing boilers
in the averaging group are less than or equal to emission limits (for
non-mercury metals, mercury, HCl, or PM) applicable to units in the
particular subcategory. We indicated also that averaging would not be
applicable to new sources and could only be used between boilers and
process heaters in the same subcategory. Also, owners or operators of
existing sources subject to the Industrial Boiler New Source
Performance Standards NSPS (40 CFR part 60, subparts Db and Dc) would
be required to continue to meet the PM emission standard of that NSPS
regardless of whether or not they are averaging.
Emissions averaging has been incorporated into the final rule as an
alternative means of complying with the final rule. Emissions averaging
allows an individual affected unit emitting
[[Page 55239]]
above the allowable emission limit required by the final rule to comply
with that emission limit by averaging its emissions with other affected
units at the same facility emitting below the allowable emission limit
required by the final rule.
Comment: Many commenters supported including averaging in the final
rule. Commenters cited numerous reasons, including cost effectiveness,
energy efficiency, greater flexibility in compliance, and greater
environmental benefit. Commenters also cited 40 CFR part 63, subpart
MM, Pulping Chemical Recovery Combustion MACT as a precedent for
including emissions averaging in MACT standards. Two commenters
disagreed with allowing emissions averaging, stating that it would
complicate compliance determinations, does not fit within the CAA
mandate, and is inconsistent with the purpose of CAA section 112. Many
of those commenters who supported emissions averaging recommended
additional flexibility, such as including new units, and bubbling
across subcategories.
Response: The final rule includes an emissions averaging compliance
alternative because emissions averaging represents an equivalent, more
flexible, and less costly alternative to controlling certain emission
points to MACT levels. We have concluded that a limited form of
averaging could be implemented and not lessen the stringency of the
standard. We agree with the commenters that some type of emissions
averaging would provide flexibility in compliance, cost and energy
savings to owners and operators. We also recognize that we must ensure
that any emissions averaging option can be implemented and enforced,
will be clear to sources, and most importantly, will achieve no less
emissions reductions than unit by unit implementation of the MACT
requirements.
The final rule is not the first NESHAP to include provisions
permitting emission averaging. In general, EPA has concluded that it is
permissible to establish within a NESHAP a unified compliance regimen
that permits averaging across affected units subject to the standard
under certain conditions. Averaging across affected units is permitted
only if it can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of a contiguous
major source that is subject to the NESHAP will not be greater under
the averaging mechanism than it would be if each individual affected
unit complied separately with the applicable standard. Under this
rigorous test, the practical outcome of averaging is equivalent in
every respect to compliance by the discrete units, and the statutory
policy embodied in the MACT floor provisions is, therefore, fully
effectuated.
The EPA has generally imposed certain limits on the scope and
nature of emissions averaging programs. These limits include: (1) No
averaging between different types of pollutants, (2) no averaging
between sources that are not part of the same major source, (3) no
averaging between sources within the same major source that are not
subject to the same NESHAP, and (4) no averaging between existing
sources and new sources.
The final rule fully satisfies each of these criteria. Accordingly,
EPA has concluded that the averaging of emissions across affected units
permitted by the final rule is consistent with the CAA. In addition,
EPA notes that the provision in the final rule that requires each
facility that intends to utilize emission averaging to submit an
emission averaging plan provides additional assurance that the
necessary criteria will be followed. In this emission averaging plan,
the facility must include the identification of (1) all units in the
averaging group, (2) the control technology installed, (3) the process
parameter that will be monitored, (4) the specific control technology
or pollution prevention measure to be used, (5) the test plan for the
measurement of particulate matter (or selected total metals), hydrogen
chloride, or mercury emissions, and (6) the operating parameters to be
monitored for each control device. Upon receipt, the regulatory
authority will not approve an emission averaging plan containing
averaging between emissions of different types of pollutants or between
sources in different subcategories.
The final rule excludes new affected sources from the emissions
averaging provision. New sources have historically been held to a
stricter standard than existing sources because it is most cost
effective to integrate state-of-the-art controls into equipment design
and to install the technology during construction of new sources. One
reason we allow emissions averaging is to give existing sources
flexibility to achieve compliance at diverse points with varying
degrees of add-on control already in place in the most cost-effective
and technically reasonable fashion. This concern does not apply to new
sources which can be designed and constructed with compliance in mind.
Only existing large solid fuel units, as defined in the final rule,
can be included in the emissions averaging compliance alternative. Of
the nine subcategories established for existing sources, existing large
solid fuel units is the only subcategory for which multiple HAP
emissions limits apply. For the existing small solid fuel subcategory
and the six existing gaseous and liquid fuel subcategories, no HAP
emissions limits are included in the final rule and, thus, it would not
be appropriate to allow these units to average emissions. As for the
existing limited use solid fuel subcategory, since these units, as
defined in the final rule, operated on a limited basis (capacity factor
of less than 10 percent) and are subject only to a less stringent PM
emissions limit (as a surrogate for non-mercury metals), it would be
inappropriate to allow these units to average emissions.
With concern about the equivalency of emissions reductions from
averaging and non-averaging in mind, the EPA Administrator is also
imposing under the emission averaging provision caps on the current
emissions from each of the sources in the averaging group. The
emissions for each unit in the averaging group would be capped at the
emission level being achieved on the effective date of the final rule.
These caps would ensure that emissions do not increase above the
emission levels that sources currently are designed, operated, and
maintained to achieve. In the absence of performance tests, in
documenting these caps, these sources will documented the type, design,
and operating specification of control devices installed on the
effective date of the final rule to ensure that existing controls are
not removed or lessen. By including this provision in the final rule,
the EPA Administrator has taken yet another step to assist in ensuring
that emission averaging results in environmental benefits equivalent or
better over what would have happened without emission averaging.
The inclusion of emissions averaging into rules and the decision on
how to design an emission averaging approach for a particular source
category must be evaluated for each source category.
J. Risk-based Approach
Comment: Multiple commenters supported EPA's incorporation of risk-
based concepts into the MACT Program. One commenter stated that
providing risk-based applicability criteria for sources whose HAP
emissions do not pose a significant risk is appropriate. Several
commenters stated that there is clear legal authority in the CAA to
construct NESHAP based on risk, and such an approach is very
appropriate in the case of the Industrial Boiler MACT. The commenter
also noted that the regulatory framework exists within their
[[Page 55240]]
State to implement such an approach. Several commenters added that
risk-based alternatives will function as indirect emission limits that
must be maintained by the facilities to assure that the criteria are
met, and, thus, such alternatives for low-risk facilities are
supportable by EPA's authority under section 112(d)(4) and 112(c)(9) of
the CAA and EPA's inherent de minimis authority. Another commenter
asserted that there are ways to structure the rule to focus on
facilities that pose significant risks and avoid imposition of high
costs on facilities that pose little risk. An appropriate approach
would be to allow individual facilities to conduct a risk assessment to
show that they pose insignificant risks to the public. However, one
commenter stated that it is not appropriate for State and local
programs to determine which facilities should be exempted from MACT.
Several commenters supported a risk-based compliance alternative for
HCl.
Response: The EPA has determined that it can establish applicable
health-based emission standards for HCl and manganese for affected
sources in this category pursuant to its authority under section
112(d)(4) of the CAA. As a result, EPA has included such standards in
the final rule as alternative compliance requirements. Under this
approach, affected sources can choose to comply with either the MACT-
based emission limits or the health-based emission limits. Sources
which choose to comply with the health-based emission limit(s) will
remain subject to those limits, but will need to comply with testing,
monitoring and reporting requirements commensurate with the compliance
option they have chosen. Such health-based standards are consistent
with both the commenters' support for an approach that minimizes the
impact on low-risk facilities and EPA's statutory mandate under section
112.
Section 112(d)(4) of the CAA authorizes EPA to consider established
health thresholds, with an ample margin of safety, when promulgating
emission standards under section 112. Hydrogen chloride and Mn are two
pollutants for which health thresholds have been established. Issues
concerning our legal authority to establish health-based emission
standards under section 112(d)(4) are discussed in detail below.
We are not using CAA section 112(c)(9) for the final rule, and
there is no delisting of categories or subcategories, as would be
consistent with section 112(c)(9).
The criteria defining how affected sources demonstrate that they
meet the threshold emissions levels for the health-based compliance
alternative(s) is included in appendix A to the final rule. The
criteria in appendix A to the final rule were developed for and apply
only to the Boiler and process heater source category and are not
applicable to other source categories. The final rule provides two ways
that an affected source may demonstrate compliance with the health-
based emission limits. The first option is through the use of lookup
tables which allow facilities to determine, using a limited number of
site-specific input parameters, whether emissions from boilers and
process heaters might cause a hazard index (HI) limit for non-
carcinogens to be exceeded. The second option is a modeling approach
which allows those facilities that do not match the site-specific input
parameters on which the lookup tables are based to demonstrate
compliance with the health-based emission limits by modeling using
site-specific information.
The affected source will have to demonstrate that it meets the
criteria established by today's final rule and then assume Federally
enforceable limitations, as described in appendix A of the final rule,
that ensure their specified HAP emissions do not subsequently increase
to exceed levels reflected in their demonstrations.
Comment: Multiple commenters are opposed to the risk-based
exemptions. Some noted that the proposal to include risk-based
exemptions is critically flawed and opposes adoption of the risk-based
exemptions.
One commenter stated that the inclusion of case-by-case risk-based
exemptions into the first phase of the MACT program will negate the
legislative mandate and jeopardize the effectiveness of the national
air toxics program to adequately protect public health and the
environment and to establish a level playing field. The commenter was
very concerned that EPA referenced a fundamentally flawed
interpretation of CAA section 112(d)(4) written by an industry (AF&PA)
subject to regulation. Of particular concern was AF&PA's unprecedented
proposal to include ``de minimis exemptions'' and ``cost'' in the MACT
standard process.
One commenter stated that the use of risk-based concepts to evade
MACT applicability is contrary to the intent of the CAA and is based on
a flawed interpretation of section 112(d)(4) of the CAA. The commenter
added that the CAA requires a technology-based floor level of control
and does not provide exclusions for risk or secondary impacts from
applying the MACT floor.
One commenter stated that in separate rulemakings and lawsuits, EPA
has adopted legal positions and policies that refute and contradict the
very risk-based and cost-based approaches contained in the proposals.
In these other arenas, the commenter contended that EPA has properly
rejected risk assessment to alter the establishment of MACT standards.
The EPA also has properly rejected cost in determining MACT floors and
in denying a basis for avoiding the MACT floor.
Several commenters stated that the preamble discussion of the risk-
based approaches is not sufficient to allow for complete public comment
and, therefore, it would not be appropriate for EPA to go directly to a
final rule (without reproposal) with any of the approaches outlined in
the proposal.
Response: We are not identifying and deleting a subcategory of
sources in this source category pursuant to the authority of CAA
section 112(c)(9). Legal issues associated with the health-based
provisions are addressed below and in the comment/response memorandum.
As discussed above, we are, however, including in the final rule
alternative health-based emission standards for HCl and TSM based on
our authority under CAA section 112(d)(4). Section 112(d)(4) authorizes
EPA to consider health thresholds, with an ample margin of safety, in
establishing emission standards. The analysis necessary to do this can
generally be characterized as a risk analysis. Thus, we disagree with
the commenter that we must wait for implementation of CAA section
112(f) before utilizing risk analysis.
Comment: Many commenters stated that the proposal to include risk-
based exemptions is contrary to the 1990 CAA Amendments (CAAA) which
calls for MACT standards based on technology rather than risk as a
first step. They added that congress incorporated the residual risk
program under CAA section 112(f) to follow the MACT standards (not to
replace them). The commenters added that the need for the technology-
based approach has been recently reinforced by the results of the
National Air Toxics Assessment (NATA), which indicates that exposure to
air toxics is very high throughout the country in urban and remote
areas. Several commenters added that risk-based approaches will be used
separately to augment and improve technology-based standards that do
not adequately provide protection to the public. One commenter added
that they have been unable to substantiate the basis for EPA's support
of the regulatory relief sought by industry through risk-based
exemptions and that, in fact, the use of risk assessment at this stage
of the
[[Page 55241]]
MACT program is directly opposed to title III of the CAA.
Response: We disagree that inclusion of health-based compliance
alternatives, in the form of emission standards based on the authority
of section 112(d)(4) of the CAA, in the final rule is contrary to the
1990 CAAA. The final rule is a technology-based standard developed
using the procedures dictated by section 112 of the CAA. The only
difference between the final rule and other MACT is that we used our
discretion under section 112(d)(4) to base appropriate parts of the
final rule on established health thresholds, with an ample margin of
safety. The final rule is particularly well-suited for a health-based
compliance alternative, established pursuant to the criteria set forth
in section 112(d)(4). In addition to the fact that there are
established health thresholds for HCl and manganese, EPA has determined
that many of the facilities in this source category do not emit these
pollutants in amounts that pose a significant risk to the surrounding
population. Those sources that can demonstrate that the emissions of
acid gases and manganese meet the threshold emission levels will be in
compliance with the MACT. The criteria are based on health-protective
estimates of risk and the threshold emission levels will provide ample
protection of human health and the environment.
Inclusion of health-based compliance alternatives in the final rule
does not alter the MACT program. Rather, it merely represents EPA
availing itself, in appropriate circumstances, of the authority
Congress granted it in section 112(d)(4) of the CAA. We recognize that
such provisions are only appropriate for certain HAP, and our decision-
making process required source category-specific input from
stakeholders.
Although the NATA modeling study may show measurable concentrations
of toxic air pollution across the country, these data do not suggest
that EPA should not establish health-based emission standards pursuant
to its authority under CAA section 112(d)(4) when it determines that it
is appropriate to do so. The alternative health-based emission
standards included in the final rule will ensure that affected sources
which choose to comply with those standards do not emit HCl and/or
manganese at levels that are harmful to public health.
Comment: Many commenters stated that the proposal to allow risk-
based exemptions would divert back to the time-consuming NESHAP
development process that existed prior to the CAAA of 1990. The
commenters asserted that under this process, which began with a risk
assessment step, only eight NESHAP were promulgated during a 20-year
period. The commenters continued that if the proposed approaches are
inserted into upcoming standards, the commenters fear the MACT program
(which is already far behind schedule) would be further delayed. One
commenter supported EPA efforts to determine alternative MACT setting
methodologies but strongly recommended that these be pursued separately
from the final rule. The commenter contended that this will provide for
timely issuance of final RICE and Boiler/Process Heater MACT rules
relative to the settlement deadline. Two commenters stated that delays
could be exacerbated by litigation following legal challenges to the
rules, and such delays would trigger the MACT hammer, which would
unnecessarily burden the State and local agencies and the industries.
The commenters concluded that further delay is unacceptable. The
commenters did not want to be in a position of implementing the CAA
section 112(j) program and urged EPA to not delay the issuance of any
MACT standard. The commenters noted that according to a recently
proposed EPA rule regarding section 112(j), the regulated community and
State and local agencies would have to proceed with part 2 permit
applications, followed by case-by-case MACT, if EPA misses the newly
agreed-upon MACT deadlines by as little as 2 months. This would be time
consuming, costly, and burdensome for both regulators and the regulated
community.
Response: We disagree that allowing health-based compliance
alternatives in the final rule will alter the MACT program or affect
the schedule for promulgation of the remaining MACT standards. We do
not anticipate any further delays in completing the remaining MACT
standards. The setting of alternative health-based emission standards
in the final rule affects only the final rule.
The approach taken in the final rule is particularly well-suited to
acid gases and manganese, which are the only pollutants included in the
health-based compliance alternatives. For many facilities, these
pollutants are currently emitted in amounts that do not expose anyone
in surrounding population to concentrations above the established
health thresholds. As a result, emissions of HCl and/or manganese at
these facilities do not pose a significant risk to the surrounding
population. Only those Boiler facilities that demonstrate that their
emissions are below the health-based emission standard(s), are eligible
for the compliance alternatives.
Including health-based compliance alternatives for boiler sources
does not mean that EPA will automatically provide such alternatives for
other industries. Rather, as has been the case throughout the MACT rule
development process, EPA will undertake in each individual rule to
determine whether it is appropriate to exercise its discretion to use
its authority under CAA section 112(d)(4) in developing applicable
emission standards. The Boilers NESHAP is being promulgated by the
February 2004 court-ordered deadline.
Comment: Many commenters stated that the risk-based proposal
removes the level-playing field that would result from the proper
implementation of technology-based MACT standards. The commenters added
that establishing a baseline level of control is essential to prevent
industry from moving to areas of the country that have the least
stringent air toxics programs, which was one of the primary goals of
developing a uniform national air toxics program under section 112 of
the 1990 CAA amendments. The risk-based approaches would jeopardize
future reductions of HAP in a uniform and consistent manner across the
nation.
Response: Providing health-based compliance alternatives for
sources that can meet them in the final rule will assure the
application of a uniform set of requirements across the nation. The
final rule and its criteria for demonstrating eligibility for the
health-based compliance alternatives apply uniformly to boilers across
the nation in the large solid fuel-fired subcategories. The final rule
establishes a two baseline levels of emission reduction for HCl and
manganese, one based on a traditional MACT analysis and the other based
on EPA's evaluation of the health threat posed by emissions of these
two pollutants. All Boiler facilities must meet one of these baseline
levels, and all facilities with boilers in the applicable subcategories
have the same opportunity to demonstrate that they can meet the
alternative health-based emission standards. The criteria for
qualifying to comply with the alternative health-based emission
standards are not dependent on local air toxics programs. Therefore,
concerns regarding facilities moving to areas of the country with less-
stringent air toxics programs should be alleviated.
Comment: Multiple commenters stated that section 112(d)(4) of the
CAA provides EPA with authority to exclude sources that emit threshold
pollutants from regulation. The commenters indicated that section
112(d)(4) allows for discretion in developing MACT standards for HAP
with health
[[Page 55242]]
thresholds. The commenters added that the use of section 112(d)(4)
authority also is supported by CAA's legislative history, which
emphasizes that Congress included section 112(d)(4) in the CAA to
prevent unnecessary regulation of source categories.
One commenter pointed out that Congress does not differentiate
between technology-based ``emission standards'' set under CAA section
112(d)(3) versus ``health threshold'' based ``emission standards'' set
under CAA section 112(d)(4). Instead, the statute explicitly treats
emission standards promulgated under section 112(d)(3) and 112(d)(4) as
equivalent by not distinguishing between those emission standards under
the residual risk provisions of CAA section 112(f). One commenter added
that EPA is permitted to establish alternative standards as long as it
ensures that ambient concentrations are less than the health thresholds
plus a margin of safety and the emissions do not cause adverse
environmental effects. Multiple commenters pointed out that EPA has
exercised such authority and cited the NESHAP for Chemical Recovery
Combustion Sources at Kraft, Soda, Sulfite, and Stand-Alone
Semichemical Pulp Mills. In addition, the commenters added that in that
NESHAP, EPA identified circumstances in which they would decline to
exercise 112(d)(4) authority-where significant or widespread
environmental harm would occur as a result of emissions from the
category and the estimated health thresholds are subject to substantial
scientific uncertainty. The commenters concluded that EPA determined
that these considerations were not relevant to emissions from the pulp
and paper source category, and the commenters stated that the same is
true for their source categories and that the same treatment is
warranted for many facilities within the source categories. The
commenters noted that facilities that cannot meet the risk criteria
would remain subject to the MACT requirements.
One commenter added that the risk-based approaches are squarely in
line with the plain meaning of section CAA 112(d)(4). The commenters
cited the Senate report (Sen Rep. No. 228, 101st Congress, 1st Sess
175-6 (1990)) showed that Congress contemplated that sources within the
same category or subcategory would be subject to varied regulatory
requirements, depending on the risk they pose to public health. The
commenters added that nothing in the statutory definition of ``emission
standard'' suggests that the term is limited to a requirement for the
installation of control technology. The commenters added that the risk-
based compliance alternatives would meet this requirement because they
would apply to an entire source category or subcategory. The EPA could
create a subcategory for low-risk sources and tailor an emission
standard to this subcategory, or apply to all sources in the category a
NESHAP containing multiple compliance options, one or more being risk-
based.
Multiple commenters stated that the plain meaning of CAA section
112(d)(4) does not allow EPA to make MACT standards for individual
sources. Two commenters noted that section 112(d)(4) states that ``with
respect to pollutants for which a health threshold has been
established, the EPA Administrator may consider such threshold level,
with ample margin of safety, when establishing emission standards under
this subsection.''
Several commenters contended that EPA has misinterpreted the
provision in CAA section 112(d)(4) in that section 112(d)(4) does not
state that EPA can use applicability thresholds ``in lieu of'' the CAA
section 112(d)(3) MACT floor requirements. The commenter interpreted
section 112(d)(4) to state that health based thresholds can be
considered when establishing the degree of the MACT floor requirements,
but it should not be used to supplant the requirements established
pursuant to section 112(d)(3).
Many commenters stated that the legislative history of CAA section
112(d)(4) clearly rejects EPA's proposed facility-by-facility MACT
exemptions. The commenters noted that Congress considered and rejected
the applicability cutoffs upon which EPA now solicits comment. The
commenters noted that the House version of the 1990 Amendments allowed
States to issue permits that exempted a source from compliance with
MACT rules if the source presented sufficient evidence to demonstrate
negligible risk, and the Senate version of the 1990 Amendments
contained no such provision. In conference, Congress considered both
the House and Senate versions and rejected the House bill's exemption
for specific facilities in favor of the Senate bill's language.
Response: The EPA has properly exercised the authority granted to
it pursuant to CAA section 112(d)(4) of the CAA in establishing health-
based emission standards for HCl and manganese which are applicable to
the large solid fuel-fired subcategory. Section 112(d)(4) authorizes it
to by-pass the mandate in section 112(d)(3) in appropriate
circumstances. Those circumstances are present in the large solid fuel-
fired Boiler subcategories.
Section 112(d)(4) of the CAA provides EPA with authority, at its
discretion, to develop health-based emission standards for HAP ``for
which a health threshold has been established,'' provided that the
standard reflects the health threshold ``with an ample margin of
safety.'' (The full text of the section 112(d)(4): ``[with respect to
pollutants for which a health threshold has been established, the
Administrator may consider such threshold level, within an ample margin
of safety, when establishing emission standards under this
subsection.'')
Both the plain language of CAA section 112(d)(4) and the
legislative history cited above indicate that EPA has the discretion
under section 112(d)(4) to develop health-based standards for some
source categories emitting threshold pollutants, and that those
standards may be less stringent than the corresponding ``floor''-based
MACT standard would be. The EPA's use of such standards is not limited
to situations where every source in the category or subcategory can
comply with them. As is the case with technology-based standards, a
particular source's ability to comply with a health-based standard will
depend on its individual circumstances, as will what it must do to
achieve compliance.
In developing health-based emission standards under CAA section
112(d)(4), EPA seeks to assure that those standards ensure that the
concentration of the particular HAP to which an individual exposed at
the upper end of the exposure distribution is exposed does not exceed
the health threshold. The upper end of the exposure distribution is
calculated using the ``high end exposure estimate,'' defined as ``a
plausible estimate of individual exposure for those persons at the
upper end of the exposure distribution, conceptually above the 90th
percentile, but not higher than the individual in the population who
has the highest exposure'' (EPA Exposure Assessment Guidelines, 57 FR
22888, May 29, 1992). Assuring protection to persons at the upper end
of the exposure distribution is consistent with the ``ample margin of
safety'' requirement in section 112(d)(4).
We agree that section 112(d)(4) is appropriate for establishing
emission standards for HCl and manganese applicable to the large solid
fuel-fired subcategories, and, therefore, we have established such
standards as an alternate compliance requirement for affected sources
in those subcategories. Affected sources in the large solid fuel-fired
subcategories which believe that
[[Page 55243]]
they can demonstrate compliance with one or both of the health-based
emission standards may choose to comply with those standards in lieu of
the otherwise applicable MACT-based standard.
For purposes of the final rule, we are not considering background
HAP emissions in developing the section CAA 112(d)(4) compliance
alternatives. As we indicated in the Residual Risk Report to Congress,
however, the Agency intends to consider facility-wide HAP emissions in
future CAA section 112(f) residual risk actions.
Comment: Many commenters contended that the proposal will place a
very intensive resource demand on State and local agencies to review
source's risk assessments, and State/local agencies may not have
expertise in risk assessment methodology or the resources needed to
verify information (e.g., emissions data and stack parameters)
submitted with each risk assessment.
Other commenters stated that a risk-based program can be structured
and implemented in a manner that does not adversely impact limited
State resources. One commenter asserted that EPA should work closely
with States and industry to implement the risk-based approach in a non-
burdensome manner. Another commenter stated that the risk-based
approaches, like other MACT standards, would simply be incorporated
into each State's existing title V program. The commenter concluded
that because the title V framework already exists, the addition of a
risk-based MACT standard would not require States to overhaul existing
permitting programs. Another commenter contended that the final MACT
rule itself should set forth the applicability criteria--including the
threshold levels of exposure--that sources must meet to qualify for a
risk-based determination. Each source would have the burden of
demonstrating that its exposures are below this limit and, therefore,
the States would not be required to develop their own risk assessment
guidance or to conduct source-specific risk assessments.
Response: The health-based emission limits for HCl and TSM which
EPA has adopted in the final rule should not impose significant
resource burdens on States. Further, the required compliance
demonstration methodology is structured in such a way as to avoid the
need for States to have significant expertise in risk assessment
methodology. We have considered the commenters' concerns in developing
the criteria defining eligibility for these compliance alternatives,
and the approach that is included in the final rule provides clear,
flexible requirements and enforceable compliance parameters. The final
rule provides two ways that a facility may demonstrate eligibility for
complying with the alternative health-based emission standard. First,
look-up tables, which are included as Tables 2 (HCl) and 3 (manganese)
in appendix A of the final rule, allow facilities to determine, using a
limited number of site-specific input parameters, whether emissions
from their sources might cause a hazard index limit (hazard quotient in
the case of manganese) to be exceeded. If a facility cannot demonstrate
eligibility using a look-up table, a modeling approach can be followed.
Appendix A to the final rule presents the criteria for performing this
modeling.
Regarding commenters' concerns with looking for a threshold level
for carcinogens, the compliance alternatives only apply to HCl and
manganese, which are not currently expected to be carcinogens. Also,
the concern expressed by a commenter about exempting a facility based
on limited emission data if EPA established a subcategory listing low-
risk sources is not relevant here, because we have not used CAA section
112(c)(9) authority to establish a low-risk subcategory for the
Industrial/Commercial/Institutional Boilers and Process Heaters source
category. With respect to guidance for performing site-specific
modeling, all of the procedures for performing such modeling are
available in peer-reviewed scientific literature and, therefore, no
additional guidance needs to be developed.
Only a portion of the major facilities in the large solid fuel-
fired boilers and process heaters subcategory will submit eligibility
demonstrations for the compliance alternatives. Of this portion of
major sources, most will be able to demonstrate eligibility based on
simple analyses (e.g., using the look-up tables provided in appendix A
of the final rule). However, it is likely that some facilities will
require more detailed modeling. The criteria for demonstrating
eligibility for the compliance alternatives are clearly spelled out in
the final rule. Because these requirements are clearly spelled out and
because any standards or requirements created under CAA section 112 are
considered applicable requirements under 40 CFR part 70, the compliance
alternatives would be incorporated into title V programs, and States
would not have to overhaul existing permitting programs.
Finally, with respect to the burden associated with ongoing
assurance that facilities which opt to do so continue to comply with
the health-based compliance alternatives, the burden to States will be
minimal. In accordance with the provisions of title V of the CAA and
part 70 of 40 CFR (collectively ``title V''), the owner or operator of
any affected source opting to comply with the health-based emission
standards will be required to certify compliance with those standards
on an annual basis. Additionally, before changing key parameters that
may impact an affected source's ability to continue to meet one or both
of the health-based emission standards, the affected source is required
to evaluate its ability to continue to comply with the health-based
emission standard(s) and submit documentation to the permitting
authority supporting continued eligibility for the compliance
alternative.
The promulgation of specific alternative health-based emission
limits and a uniform methodology for demonstrating compliance with
those alternatives alleviates any concern regarding the public process
required in reviewing/approving the proposed approaches and making
substantial changes to existing regulations. It also addresses concerns
regarding the costs and resources associated with assuring adequate
public participation in the process of reviewing site-specific risk
analyses.
To ensure that affected sources which choose to comply with the
alternative health-based emission standards continue to comply with
those standards after the initial compliance demonstration, specified
assessment parameters (e.g., HCl and/or manganese emission rate, boiler
heat output, etc.) must be included in their title V permit as
enforceable requirements. Draft permits and permit applications must be
made available to the public from the State or local agency responsible
for issuing the permit, or in the case where EPA is issuing the permit,
from the EPA regional office. Members of the public may request that
the State or local agency include them on their public notice mailing
list, thus providing the public the opportunity to review the
appropriateness of these requirements. Every proposed title V permit
has a 30-day public comment period and a 45-day EPA review period. If
EPA does not object to the permit, any member of the public may
petition EPA to object to the permit within 60 days of the end of the
EPA review period.
Comment: A commenter contended that exempting HCl emissions from
control is inappropriate, particularly since EPA proposed HCl as a
surrogate measure for all the inorganic HAP
[[Page 55244]]
emitted by this source category. Hence, an exemption that excluded HCl
emission points from control requirements would also exclude emissions
of all the other inorganic HAP that would likely include hydrogen
cyanide and hydrogen fluoride.
Response: Facilities attempting to utilize the health-based
compliance alternative for HCl will not be required to evaluate
emissions of other inorganic HAP except for chlorine. We conducted an
assessment of boiler emissions and determined that, of the acid gas HAP
controlled by scrubbing technology, chlorine is responsible for the
great majority of risk and HCl is responsible for the next largest
portion of the total risk. The contributions of other HAP, including
hydrogen fluoride, to the total risk were negligible. Therefore,
facilities attempting to demonstrate eligibility for the health-based
compliance alternative for HCl, either by conducting a lookup table
analysis or by conducting a site-specific compliance demonstration,
must include emission rates of chlorine and HCl from their boilers. We
do not expect hydrogen cyanide emissions from boilers covered under the
final rule.
Comment: Commenters stated that the proposal does not address
ecological risk that may result from uncontrolled HAP emissions,
especially in those areas with sensitive habitats but few people nearby
to be exposed and that EPA provided inadequate discussion of how
environmental risks will be evaluated.
Response: To identify HAP with potential to cause multimedia and/or
environmental effects, the EPA has identified HAP with significant
potential to persist in the environment and to bioaccumulate. This list
does not include HCl or manganese which are the only HAP with health-
based compliance alternatives in the final rule. Additionally, a
screening level analysis conducted by the EPA indicates that acute
impacts of these HAP from industrial boiler facilities are highly
unlikely. For these reasons we do not believe that emissions of HCl or
manganese from industrial boiler facilities will pose a significant
risk to the environment and facilities attempting to comply with the
health-based alternatives for these HAP are not required to perform an
ecological assessment.
V. Impacts of the Final Rule
A. What Are the Air Impacts?
Nationwide emissions of selected HAP (i.e., HCl, hydrogen fluoride,
lead, and nickel) will be reduced by 58,500 tpy for existing units and
73 tpy for new units. Depending on the number of facilities
demonstrating eligibility for the health-based compliance alternatives,
the total HAP reduction for existing units could be 50,600 tpy.
Emissions of HCl will be reduced by 42,000 tpy for existing units and
72 tpy for new units. Depending on the number of facilities
demonstrating eligibility for the health-based compliance alternatives,
the total HCl emissions reduction for existing units could be 36,400
tpy. Emissions of mercury will be reduced by 1.9 tpy for existing units
and 0.006 tpy for new units. Emissions of PM will be reduced by 565,000
tpy for existing units and 480 tpy for new units. Depending on the
number of facilities demonstrating eligibility for the health-based
compliance alternatives, the total PM emissions reduction for existing
units could be 547,000 tpy. Emissions of total selected nonmercury
metals (i.e., arsenic, beryllium, cadmium, chromium, lead, manganese,
nickel, and selenium) will be reduced by 1,100 tpy for existing units
and will be reduced by 1.4 tpy for new units. Depending on the number
of facilities demonstrating eligibility for the health-based compliance
alternatives, the total nonmercury metals emissions reduction for
existing units could be 950 tpy. In addition, emissions of sulfur
dioxide (SO2) are established to be reduced by 113,000 tpy
for existing sources and 110 tpy for new sources. Depending on the
number of facilities demonstrating eligibility for the health-based
compliance alternatives, the total SO2 emissions reduction
for existing units could be 49,000 tpy.
As noted above, use of the health-based compliance alternatives by
eligible facilities will affect reductions in HAP, PM (and total non-
mercury metals that are generally controlled along with PM), and
SO2. Nevertheless, our analysis indicates that the
difference in emissions of HCl and manganese with and without the
compliance alternatives will not affect health risks because the
compliance alternative is available only to those facilities that
demonstrate that their emissions pose little risks. Emissions of PM and
SO2 will still be reduced by the implementation of other
provisions of the Clean Air Act, such as attainment of the health-based
National Ambient Air Quality Standards, which include mechanisms to
control such emissions.
A discussion of the methodology used to estimate emissions and
emissions reductions is presented in ``Estimation of Baseline Emissions
and Emissions Reductions for Industrial, Commercial, and Institutional
Boilers and Process Heaters'' in the docket. To estimate the potential
impacts of the health-based compliance alternatives, we performed a
preliminary ``rough'' assessment of the large solid fuel subcategory to
determine the extent to which facilities might become eligible for the
health-based compliance alternatives. Based on the results of this
rough assessment, 448 coal-fired boilers could potentially be eligible
for the HCl compliance alternative and 386 biomass-fired boilers could
be potentially eligible for the TSM compliance alternative.
B. What Are the Water and Solid Waste Impacts?
The EPA estimates the additional water usage that would result from
the MACT floor level of control to be 110 million gallons per year for
existing sources and 0.6 million gallons per year for new sources. In
addition to the increased water usage, an additional 3.7 million
gallons per year of wastewater will be produced for existing sources
and 0.6 million gallons per year for new sources. The costs of treating
the additional wastewater are $18,000 for existing sources and $2,300
for new sources, in advance of any facility demonstrating eligibility
for the health-based compliance alternatives. These costs are accounted
for in the control costs estimates.
The EPA estimates the additional solid waste that would result from
the MACT floor level of control to be 102,000 tpy for existing sources
and 1 tpy for new sources. The estimated costs of handling the
additional solid waste generated are $1.5 million for existing sources
and $17,000 for new sources, in advance of any facility demonstrating
eligibility for the health-based compliance alternatives. These costs
are also accounted for in the control costs estimates.
A discussion of the methodology used to estimate impacts is
presented in ``Estimation of Impacts for Industrial, Commercial, and
Institutional Boilers and Process Heaters NESHAP'' in the docket.
C. What Are the Energy Impacts?
The EPA expects an increase of approximately 1,130 million kilowatt
hours (kWh) in national annual energy usage as a result of the final
rule, in advance of any facility demonstrating eligibility for the
health-based compliance alternatives. Of this amount, 1,120 million kWh
is estimated from existing sources and 13 million kWh is estimated from
new sources. The increase results from the electricity required to
operate control devices
[[Page 55245]]
installed to meet the final rule, such as wet scrubbers and fabric
filters.
D. What Are the Control Costs?
To estimate the national cost impacts of the final rule for
existing sources, EPA developed several model boilers and process
heaters and determined the cost of control equipment for these model
boilers. The EPA assigned a model boiler or heater to each existing
unit in the database based on the fuel, size, design, and current
controls. The analysis considered all air pollution control equipment
currently in operation at existing boilers and process heaters. Model
costs were then assigned to all existing units that could not otherwise
meet the proposed emission limits. The resulting total national cost
impact of the final rule is $1,790 million in capital expenditures and
$860 million per year in total annual costs. Depending on the number of
facilities demonstrating eligibility for the health-based compliance
alternatives, these costs could be $1,440 million in capital
expenditures and $690 million per year in total annual costs. The total
capital and annual costs include costs for testing, monitoring, and
recordkeeping and reporting. Costs include testing and monitoring
costs, but not recordkeeping and reporting costs.
Using Department of Energy projections on fuel expenditures, EPA
estimated the number of additional boilers that could be potentially
constructed. The resulting total national cost impact of the final rule
in the 5th year is $58 million in capital expenditures and $18.6
million per year in total annual costs, in advance of any facility
demonstrating eligibility for the health-based provisions. Costs are
mainly for testing and monitoring.
A discussion of the methodology used to estimate cost impacts is
presented in ``Methodology for Estimating Control Cost for the
Industrial, Commercial, and Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants'' in the
docket.
E. What Are the Economic Impacts?
The economic impact analysis shows that the expected price increase
for output in the 40 affected industries would be no more than 0.04
percent as a result of the final rule for industrial boilers and
process heaters. The expected change in production of affected output
is a reduction of only 0.03 percent or less in the same industries. In
addition, impacts to affected energy markets show that prices of
petroleum, natural gas, electricity and coal should increase by no more
than 0.05 percent as a result of implementation of the final rule, and
output of these types of energy should decrease by no more than 0.01
percent. These impacts are generated in advance of any facility
demonstrating eligibility for the health-based compliance alternatives.
Depending on the number of affected facilities demonstrating
eligibility for the health-based compliance alternatives, these impacts
on product prices could fall to a 0.03 percent increase, and a decrease
in output of the energy types mentioned previously of less than 0.01
percent. Therefore, it is likely that there is no adverse impact
expected to occur for those industries that produce output affected by
the final rule, such as lumber and wood products, chemical
manufacturers, petroleum refining, and furniture manufacturing.
F. What Are the Social Costs and Benefits of the Final Rule?
Our assessment of costs and benefits of the final rule is detailed
in the ``Regulatory Impact Analysis for the Final Industrial,
Commercial, and Institutional Boilers and Process Heaters MACT.'' The
Regulatory Impact Analysis (RIA) is located in the Docket.
It is estimated that 3 years after implementation of the final
rule, HAP will be reduced by 58,500 tpy (53,200 megagrams per year (Mg/
yr)) due to reductions in arsenic, beryllium, HCl, and several other
HAP from existing affected emission sources. Of these reductions,
42,000 tpy (38,200 Mg/yr) are of HCl. In addition to these reductions,
there are 73 tpy (66 Mg/yr) of HAP reductions expected from new
sources. Of these reductions, virtually all of them are of HCl. The
health effects associated with these HAP are discussed earlier in this
preamble. While it is beneficial to society to reduce these HAP, we are
unable to quantify and provide a monetized estimate of the benefits at
this time.
Despite our inability to quantify and provide monetized benefit
estimates from HAP reductions, it is possible to derive rough estimates
for one of the more important benefit categories, i.e., the potential
number of cancer cases avoided and cancer risk reduced as a result of
the imposition of the MACT level of control on this source category.
Our analysis suggests that imposition of the MACT level of control
would reduce cancer cases at worst case baseline assumptions by
possibly tens of cases per year, on average, starting some years after
implementation of the final rule. This risk reduction estimate is
uncertain, is likely to overestimate benefits, and should be regarded
as an extremely rough estimate. Furthermore, the estimate should be
viewed in the context of the full spectrum of unquantified noncancer
effects associated with the HAP reductions. Noncancer effects
associated with the HAP are presented earlier in this preamble.
The control technologies used to reduce the level of HAP emitted
from affected sources are also expected to reduce emissions of PM
(PM10, PM2.5), and sulfur dioxide
(SO2). It is estimated that PM10 emissions
reductions total approximately 562,000 tpy (510,000 Mg/yr),
PM2.5 emissions reductions total approximately 159,000 tpy
(145,000 Mg/yr), and SO2 emissions reductions total
approximately 113,000 tpy (102,670 Mg/yr). These estimated reductions
occur from existing sources in operation 3 years after the
implementation of the requirements of the final rule and are expected
to continue throughout the life of the sources.
In general, exposure to high concentrations of PM may aggravate
existing respiratory and cardiovascular disease including asthma,
bronchitis and emphysema, especially in children and the elderly.
SO2 is also a contributor to acid deposition, or acid rain,
which causes acidification of lakes and streams and can damage trees,
crops, historic buildings and statues. Exposure to PM2.5 can
lead to decreased lung function, and alterations in lung tissue and
structure and in respiratory tract defense mechanisms which may then
lead to, increased respiratory symptoms and disease, or in more severe
cases, premature death or increased hospital admissions and emergency
room visits. Children, the elderly, and people with cardiopulmonary
disease, such as asthma, are most at risk from these health effects.
Fine PM can also form a haze that reduces the visibility of scenic
areas, can cause acidification of water bodies, and have other impacts
on soil, plants, and materials. As SO2 emissions transform
into PM, they can lead to the same health and welfare effects listed
above.
For PM10 and PM2.5 (including SO2
contributions to ambient concentrations of PM2.5), we
provide a monetary estimate for the benefits associated with the
reduction in emissions associated with the final rule. To do so, we
conducted an air quality assessment to determine the change in ambient
concentrations of PM10 and PM2.5 that result from
reductions of PM and SO2 at existing affected facilities.
Unfortunately, our data are not able to define the exact location of
the reductions for every affected boiler and process heater. Because of
this
[[Page 55246]]
limitation, the benefits assessment is conducted in two phases. First,
an air quality analysis was conducted for emissions reductions from
those emissions sources that have an known link to a specific control
device, which represents approximately 50 percent of the total
emissions reductions mentioned above. Using this subset of information,
we determined the air quality change nationwide. The results of the air
quality assessment served as input to a model that estimates the total
monetary value of benefits of the health effects listed above. Total
benefits associated with this portion of the analysis (in phase one)
are $8.2 billion in the year 2005 (presented in 1999 dollars).
In the second phase of our analysis, for those emissions reductions
from affected sources that do not have a known link to a specific
control device, the results of the air quality analysis in phase one
serve as a reasonable approximation of air quality changes to transfer
to the remaining emissions reductions of the final rule. Because there
is not a reasonable way to apportion the total benefits of the combined
impact of the PM and SO2 reductions from the air quality and
benefit analyses completed above, we performed two additional air
quality analyses. One analysis was performed to evaluate the impact on
air quality of the PM reductions alone (holding SO2
unchanged), and one to evaluate the impact on air quality from the
SO2 reductions alone (holding PM unchanged). With
independent PM and SO2 air quality assessments, we can
determine the total benefit associated with each component of total
pollutant reductions. The total benefit associated with the PM and
SO2 reductions with unspecified location (in phase two) are
$7.9 billion.
The benefit estimates derived from the air quality modeling in the
first phase of our analysis uses an analytical structure and sequence
similar to that used in the benefits analyses for the proposed Nonroad
Diesel rule and proposed Integrated Air Quality Rule (IAQR) and in the
``section 812 studies'' analysis of the total benefits and costs of the
Clean Air Act. We used many of the same models and assumptions used in
the Nonroad Diesel and IAQR analyses as well as other Regulatory Impact
Analyses (RIAs) prepared by the Office of Air and Radiation. By
adopting the major design elements, models, and assumptions developed
for the section 812 studies and other RIAs, we have largely relied on
methods which have already received extensive review by the independent
Science Advisory Board (SAB), the National Academies of Sciences, by
the public, and by other federal agencies.
The benefits transfer method used in the second phase of the
analysis is similar to that used to estimate benefits at the proposal
of the rule, and in the proposed Reciprocating Internal Combustion
Engines NESHAP. A similar method has also been used in recent benefits
analyses for the proposed Nonroad Large Spark-Ignition Engines and
Recreational Engines standards (67 FR 68241, November 8, 2002).
The sum of benefits from the two phases of analysis provide an
estimate of the total benefits of the rule. Total benefits of the final
rule are approximately $16.3 billion (1999$). This economic benefit is
associated with approximately 2,270 avoided premature mortalities,
5,100 avoided cases of chronic bronchitis, thousands of avoided
hospital and emergency room visits for respiratory and cardiovascular
diseases, tens of thousands of avoided days with respiratory symptoms,
and millions of avoided work loss and restricted activity days. This
estimate is generated in advance of any facility demonstrating
eligibility for the health-based compliance alternatives.
Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited, to some
extent, by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Deficiencies in the scientific literature often result in the inability
to estimate changes in health and environmental effects. Deficiencies
in the economics literature often result in the inability to assign
economic values even to those health and environmental outcomes that
can be quantified. While these general uncertainties in the underlying
scientific and economics literatures are discussed in detail in the RIA
and its supporting documents and references, the key uncertainties
which have a bearing on the results of the benefit-cost analysis of
today's action are the following:
1. The exclusion of potentially significant benefit categories
(e.g., health and ecological benefits of reduction in hazardous air
pollutants emissions);
2. Errors in measurement and projection for variables such as
population growth;
3. Uncertainties in the estimation of future year emissions
inventories and air quality;
4. Uncertainties associated with the extrapolation of air quality
monitoring data to some unmonitored areas required to better capture
the effects of the standards on the affected population;
5. Variability in the estimated relationships of health and welfare
effects to changes in pollutant concentrations; and
6. Uncertainties associated with the benefit transfer approach.
7. Uncertainties in the size of the effect estimates linking air
pollution and health endpoints.
8. Uncertainties about relative toxicity of different components
within the complex mixture.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the final rule under a given set of assumptions.
Based on estimated compliance costs (control + administrative costs
associated with Paperwork Reduction Act requirements associated with
the rule and predicted changes in the price and output of electricity),
the estimated annualized social costs of the Industrial, Commercial,
and Institutional Boilers and Process Heaters NESHAP are $863 million
(1999$). Depending on the number of affected facilities demonstrating
eligibility for the health-based compliance alternatives, these
annualized social costs could fall to $746 million. Social costs are
different from compliance costs in that social costs take into account
the interactions between affected producers and the consumers of
affected products in response to the imposition of the compliance
costs.
As explained above, we estimate $16.3 billion in benefits from the
final rule, compared to $863 million in costs. It is important to put
the results of this analysis in the proper context. The large benefit
estimate is not attributable to reducing human and environmental
exposure to the HAPs that are reduced by this rule. It arises from
ancillary reductions in PM and SO2 that result from controls
aimed at complying with the NESHAP. Although consideration of ancillary
benefits is reasonable, we note that these benefits are not uniquely
attributable to the regulation. The Agency believes nonetheless that
the key rationale for controlling arsenic, beryllium, HCl, and the
other HAPs associated with this rule is to reduce public and
environmental exposure to these HAPs, thereby reducing risk to public
health and wildlife. Although the available science does not support
quantification of these benefits at this time, the Agency believes the
qualitative
[[Page 55247]]
benefits are large enough to justify substantial investment in these
emission reductions.
It should be recognized, however, that this analysis does not
account for many of the potential benefits that may result from these
actions. Thus, our estimate of total benefits also includes a ``B'' to
represent those additional health and environmental benefits which
could not be expressed in quantitative incidence and/or economic value
terms. The net benefits would be greater if all the benefits of the
other pollutant reductions could be quantified. Notable omissions to
the net benefits include all benefits of HAP reductions, including
reduced cancer incidences, toxic morbidity effects, and cardiovascular
and CNS effects, and all welfare effects from reduction of ambient PM
and SO2. A full appreciation of the overall economic
consequences of the industrial boiler and process heater standards
requires consideration of all benefits and costs expected to result
from the final rule, not just those benefits and costs that could be
expressed here in dollar terms. A full listing of the benefit
categories that could not be quantified or monetized in our base
estimate are provided in Table 2 of this preamble.
Table 2.--Unquantified Benefit Categories
----------------------------------------------------------------------------------------------------------------
Unquantified benefit categories Unquantified benefit categories
associated with HAP reductions associated with PM reductions
----------------------------------------------------------------------------------------------------------------
Health Categories............................ --Airway responsiveness......... --Changes in pulmonary
--Pulmonary inflammation........ function.
--Susceptibility to respiratory --Morphological changes.
infection. Altered host defense
--Acute inflammation and mechanisms.
respiratory cell damage. --Other chronic respiratory
--Chronic respiratory damage/ disease.
Premature aging of lungs. --Emergency room visits for
--Emergency room visits for asthma.
asthma. --Emergency visits for non-
asthma respiratory and
cardiovascular causes.
--Lower and upper respiratory
systems.
--Acute bronchitis.
--Shortness of breath.
Welfare Categories........................... --Ecosystem and vegetation --School absence rates.
effects. --Materials damage.
--Damage to urban ornamentals --Damage to ecosystems (e.g.,
(e.g., grass, flowers, shrubs, acid sulfate deposition).
and trees in urban areas). --Nitrates in drinking water.
--Commercial field crops........ --Visibility in recreational
--Fruit and vegetable crops..... and residential areas.
--Yields of tree seedlings,
commercial and non-commercial
forests.
--Damage to ecosystems..........
--Materials damage..............
----------------------------------------------------------------------------------------------------------------
Using the results of the benefit analysis, we can use benefit-cost
comparison (or net benefits) as another tool to evaluate the
reallocation of society's resources needed to address the pollution
externality created by the operation of industrial boilers and process
heaters. The additional costs of internalizing the pollution produced
at major sources of emissions from industrial boilers and process
heaters are compared to the improvement in society's well-being from a
cleaner and healthier environment. Comparing benefits of the final rule
to the costs imposed by alternative ways to control emissions optimally
identifies a strategy that results in the highest net benefit to
society. In the final rule, we include only one option, the minimal
level of control mandated by the CAA, or the MACT floor. Other
alternatives that lead to higher levels of control (or beyond-the-floor
alternatives) lead to higher estimates of benefits net of costs, but
also lead to additional economic impacts, including more substantial
impacts to small entities. For more details, please refer to the RIA
for the final rule.
Based on estimated compliance costs associated with the final rule
and the predicted change in prices and production in the affected
industries, the estimated annualized social costs of the final rule are
$863 million (1999 dollars). This estimate of social cost is generated
in advance of any facility demonstrating eligibility for the health-
based compliance alternatives. Depending on the number of affected
facilities demonstrating eligibility for the health-based compliance
alternatives, these annualized social costs could fall to $746 million.
Social costs are different from compliance costs in that social costs
take into account the interactions of consumers and producers of
affected products in response to the imposition of the compliance
costs. Therefore, the Agency's estimate of monetized benefits net of
costs is $15.4 billion + B (1999 dollars) in 2005.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the EPA
must determine whether a regulatory action is ``significant'' and,
therefore, subject to review by the OMB and the requirements of the
Executive Order. The Executive Order defines ``significant regulatory
action'' as one that is likely to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, the EPA has
determined that the final rule is a ``significant regulatory action''
because it has an annual effect on the economy of over $100 million. As
such, the final rule was submitted to OMB for review.
[[Page 55248]]
B. Paperwork Reduction Act
The information collection requirements in the final rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
information collection requirements are not enforceable until OMB
approves them.
The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant
to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The final rule requires maintenance inspections of the control
devices, but does not require any notifications or reports beyond those
required by the General Provisions. The recordkeeping requirements
require only the specific information needed to determine compliance.
The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the final rule) is estimated to be $91 million. This includes 1.2
million labor hours per year at a total labor cost of $67 million per
year, and total non-labor capital costs of $24 million per year. This
estimate includes a one-time performance test, semiannual excess
emission reports, maintenance inspections, notifications, and
recordkeeping. The total burden for the Federal government (averaged
over the first 3 years after the effective date of the final rule) is
estimated to be 346,000 hours per year at a total labor cost of $14
million per year. Table 3 of this preamble shows the average annualized
burden for monitoring, reporting, and recordkeeping for each
subcategory.
Table 3.--Summary of the Average Reporting and Recordkeeping Costs
----------------------------------------------------------------------------------------------------------------
Total labor Total capital
Subcategory costs ($) costs ($) Total costs ($)
----------------------------------------------------------------------------------------------------------------
Large Solid Fuel Units.................................... 56,253,000 12,488,000 68,741,000
Limited Use Solid Fuel Units.............................. 2,565,000 2,267,000 4,832,000
Small Solid Fuel Units.................................... 627,000 111,000 738,000
Large Liquid Fuel Units................................... 498,000 491,000 989,000
Limited Use Liquid Fuel Units............................. 214,000 264,000 478,000
Small Liquid Fuel Units................................... 442,000 0 442,000
Large Gaseous Fuel Units.................................. 3,673,000 6,615,000 10,288,000
Limited Use Gaseous Fuel Units............................ 663,000 1,209,000 1,872,000
Small Gaseous Fuel Units.................................. 2,413,000 0 2,413,000
----------------------------------------------------------------------------------------------------------------
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9. When this ICR is approved by
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in
the Federal Register to display the OMB control number for the approved
information collection requirements contained in this final rule.
The EPA requested comments on the need for this information, the
accuracy of the provided burden estimates, and any suggested methods
for minimizing respondent burden, including through the use of
automated collection techniques.
C. Regulatory Flexibility Act
The EPA has determined that it is not necessary to prepare a
regulatory flexibility analysis in connection with the final rule. We
have also determined that the final rule will not have a significant
impact on a substantial number of small entities.
For purposes of assessing the impacts of the final rule on small
entities, small entity is defined as:
(1) A small business according to Small Business Administration
size standards by the North American Industry Classification System
(NAICS) category of the owning entity. The range of small business size
standards for the 40 affected industries ranges from 500 to 1,000
employees, except for petroleum refining and electric utilities. In
these latter two industries, the size standard is 1,500 employees and a
mass throughput of 75,000 barrels/day or less, and 4 million kilowatt-
hours of production or less, respectively;
(2) A small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise that
is independently owned and operated and is not dominant in its field.
After considering the economic impact of the final rule on small
entities, we have determined that the final rule will not have a
significant economic impact on a substantial number of small entities.
Based on SBA size definitions for the affected industries and reported
sales and employment data, EPA identified 185 of the 576 entities, or
32 percent, owning affected facilities as small entities. Although
small entities represent 32 percent of the entities within the source
category, they are expected to incur only 4 percent of the total
compliance costs of $862.7 million (1998 dollars). There are only ten
small entities with compliance costs equal to or greater than 3 percent
of their sales. In addition, there are only 24 small entities with
cost-to-sales ratios between 1 and 3 percent.
[[Page 55249]]
An economic impact analysis was performed to estimate the changes
in product price and production quantities for the final rule. As
mentioned in the summary of economic impacts earlier in this preamble,
the estimated changes in prices and output for affected entities is no
more than 0.05 percent. For more information, consult the docket for
the final rule.
It should be noted that these small entity impacts are in advance
of any facility demonstrating eligibility for the health-based
compliance alternatives. Depending on the number of affected facilities
demonstrating eligibility for the health-based compliance alternatives,
the estimated small entity impacts could fall to eight small entities
with compliance costs equal to or greater than 3 percent of their
sales, and 14 small entities with compliance costs between 1 and 3
percent of their sales.
The final rule will not have a significant economic impact on a
substantial number of small entities as a result of several decisions
EPA made regarding the development of the rule, which resulted in
limiting the impact of the rule on small entities. First, as mentioned
earlier in this preamble, EPA identified small units (heat input of 10
MMBtu/hr or less) and limited use boilers (operate less than 10 percent
of the time) as separate subcategories different from large units. Many
small and limited use units are located at small entities. As also
discussed earlier, the results of the MACT floor analysis for these
subcategories of existing sources was that no MACT floor could be
identified except for the limited use solid fuel subcategory, which is
less stringent than the MACT floor for large units. Furthermore, the
results of the beyond-the-floor analysis for these subcategories
indicated that the costs would be too high to consider them feasible
options. Consequently, the final rule contains no emission limitations
for any of the existing small and limited use subcategories except the
existing limited use solid fuel subcategory. In addition, the
alternative metals emission limit resulted in minimizing the impacts on
small entities since some of the potential entities burning a fuel
containing very little metals are small entities.
D. Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows us to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the EPA
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we must develop a small
government agency plan under section 203 of the UMRA. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of regulatory promulgation with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
We determined that the final rule contains a Federal mandate that
may result in expenditures of $100 million or more for State, local,
and Tribal governments, in the aggregate, or the private sector in any
1 year. Accordingly, we have prepared a written statement (titled
``Unfunded Mandates Reform Act Analysis for the Industrial Boilers and
Process Heaters NESHAP)'' under section 202 of the UMRA, which is
summarized below.
Statutory Authority
As discussed in this preamble, the statutory authority for the
final rulemaking is section 112 of the CAA. Title III of the CAA
Amendments was enacted to reduce nationwide air toxic emissions.
Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups
of chemicals deemed by Congress to be HAP. These toxic air pollutants
are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP, which
require existing and new major sources to control emissions of HAP
using MACT based standards. The final rule applies to all industrial,
commercial, and institutional boilers and process heaters located at
major sources of HAP emissions.
In compliance with section 205(a) of the UMRA, we identified and
considered a reasonable number of regulatory alternatives. Additional
information on the costs and environmental impacts of these regulatory
alternatives is presented in the docket.
The regulatory alternative upon which the final rule is based
represents the MACT floor for industrial boilers and process heaters
and, as a result, it is the least costly and least burdensome
alternative.
Social Costs and Benefits
The regulatory impact analysis prepared for the final rule
including the EPA's assessment of costs and benefits, is detailed in
the ``Regulatory Impact Analysis for the Industrial Boilers and Process
Heaters MACT'' in the docket. Based on estimated compliance costs
associated with the final rule and the predicted change in prices and
production in the affected industries, the estimated social costs of
the final rule are $863 million (1999 dollars). Depending on the number
of affected facilities demonstrating eligibility for the health-based
compliance alternatives, these annualized social costs could fall to
$746 million.
It is estimated that 5 years after implementation of the final
rule, HAP will be reduced by 58,500 tpy due to reductions in arsenic,
beryllium, dioxin, hydrochloric acid, and several other HAP from
industrial boilers and process heaters. Studies have determined a
relationship between exposure to these HAP and the onset of cancer,
however, there are some questions remaining on how cancers that may
result from exposure to these HAP can be quantified in terms of
dollars. Therefore, the EPA is unable to provide a monetized estimate
of the benefits of the HAP reduced by the final rule at this time.
However, there are significant reductions in PM and in SO2
that occur. Reductions of 560,000 tons of PM with a diameter of less
than or equal to 10 micrometers (PM10), 159,000 tons of PM
with a diameter of less than or equal to 2.5 micrometers
(PM2.5), and 112,000 tons of SO2 are expected to
occur. These reductions occur from existing sources in operation 5
years after the implementation of the regulation and are expected to
continue throughout the life of the affected sources. The major health
effect that results from these PM
[[Page 55250]]
and SO2 emissions reductions is a reduction in premature
mortality. Other health effects that occur are reductions in chronic
bronchitis, asthma attacks, and work-lost days (i.e., days when
employees are unable to work).
While we are unable to monetize the benefits associated with the
HAP emissions reductions, we are able to monetize the benefits
associated with the PM and SO2 emissions reductions. For
SO2 and PM, we estimated the benefits associated with health
effects of PM, but were unable to quantify all categories of benefits
(particularly those associated with ecosystem and environmental
effects). Unquantified benefits are noted with ``B'' in the estimates
presented below. Our primary estimate of the monetized benefits in 2005
associated with the implementation of the proposed alternative is $16.3
billion + B (1999 dollars). This estimate is about $15.3 billion + B
(1999 dollars) higher than the estimated social costs shown earlier in
this section. These benefit estimates are in advance of any facility
demonstrating eligibility for the health-based compliance alternatives.
Depending on the number of affected facilities demonstrating
eligibility for the health-based compliance alternatives, the benefit
estimate presuming the health-based compliance alternatives is $14.5
billion + B, which is $1.7 billion lower than the estimate for the
final rule. This estimate is $13.8 billion + B higher than the
estimated social costs presuming the health-based compliance
alternatives. The general approach to calculating monetized benefits is
discussed in more detail earlier in this preamble. For more detailed
information on the benefits estimated for the final rule, refer to the
RIA in the docket.
Future and Disproportionate Costs
The Unfunded Mandates Act requires that we estimate, where accurate
estimation is reasonably feasible, future compliance costs imposed by
the rule and any disproportionate budgetary effects. Our estimates of
the future compliance costs of the final rule are discussed previously
in this preamble.
We do not feel that there will be any disproportionate budgetary
effects of the final rule on any particular areas of the country, State
or local governments, types of communities (e.g., urban, rural), or
particular industry segments. This is true for the 257 facilities owned
by 54 different government bodies, and this is borne out by the results
of the ``Economic Impact Analysis of the Industrial Boilers and Process
Heaters NESHAP,'' the results of which are discussed previously in this
preamble.
Effects on the National Economy
The Unfunded Mandates Act requires that we estimate the effect of
the final rule on the national economy. To the extent feasible, we must
estimate the effect on productivity, economic growth, full employment,
creation of productive jobs, and international competitiveness of the
U.S. goods and services, if we determine that accurate estimates are
reasonably feasible and that such effect is relevant and material.
The nationwide economic impact of the final rule is presented in
the ``Economic Impact Analysis for the Industrial Boilers and Process
Heaters MACT'' in the docket. This analysis provides estimates of the
effect of the final rule on some of the categories mentioned above. The
results of the economic impact analysis are summarized previously in
this preamble. The results show that there will be little impact on
prices and output from the affected industries, and little impact on
communities that may be affected by the final rule. In addition, there
should be little impact on energy markets (in this case, coal, natural
gas, petroleum products, and electricity). Hence, the potential impacts
on the categories mentioned above should be minimal.
Consultation With Government Officials
The Unfunded Mandates Act requires that we describe the extent of
the EPA's prior consultation with affected State, local, and tribal
officials, summarize the officials' comments or concerns, and summarize
our response to those comments or concerns. In addition, section 203 of
the UMRA requires that we develop a plan for informing and advising
small governments that may be significantly or uniquely impacted by a
rule. Although the final rule does not significantly affect any State,
local, or Tribal governments, we have consulted with State and local
air pollution control officials. We also have held meetings on the
final rule with many of the stakeholders from numerous individual
companies, environmental groups, consultants and vendors, labor unions,
and other interested parties. We have added materials to the docket to
document these meetings.
In addition, we have determined that the final rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. While some small governments may have some sources
affected by the final rule, the impacts are not expected to be
significant. Therefore, the final rule is not subject to the
requirements of section 203 of the UMRA. However, EPA did complete a
report containing analyses called for in the UMRA as a response to
comments from many municipal utilities regarding the final rule and its
potential impacts. This report, ``Unfunded Mandates Reform Act Analysis
for the Industrial Boilers and Process Heaters NESHAP,'' is in the
docket.
E. Executive Order 13132: Federalism
Executive Order 13132 requires EPA to develop an accountable
process to ensure ``meaningful and timely input by State and local
officials in the development of regulatory policies that have
federalism implications.'' ``Policies that have federalism
implications'' are defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.
The final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132.
The agency is required by section 112 of the CAA, to establish the
standards in the final rule. The final rule primarily affects private
industry, and does not impose significant economic costs on State or
local governments. The final rule does not include an express provision
preempting State or local regulations. Thus, the requirements of
section 6 of the Executive Order do not apply to the final rule.
Although section 6 of Executive Order 13132 does not apply to the
final rule, we consulted with representatives of State and local
governments to enable them to provide meaningful and timely input into
the development of the final rule. This consultation took place during
the ICCR Federal Advisory Committee Act (FACA) committee meetings where
members representing State and local governments participated in
developing recommendations for EPA's combustion-related rulemakings,
including the final rule. The concerns raised by representatives of
State and local governments were considered during the development of
the final rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to
[[Page 55251]]
promote communications between EPA and State and local governments, EPA
specifically solicited comment on the final rule from State and local
officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 9, 2000) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' The final rule does not have tribal
implications, as specified in Executive Order 13175.
The final rule does not significantly or uniquely affect the
communities of Indian tribal governments. We do not know of any
industrial-commercial-institutional boilers or process heaters owned or
operated by Indian tribal governments. However, if there are any, the
effect of these rules on communities of tribal governments would not be
unique or disproportionate to the effect on other communities. Thus,
Executive Order 13175 does not apply to the final rule. The EPA
specifically solicited additional comment on the final rule from tribal
officials, but received none.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
regulation that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that we have reason to believe may
have a disproportionate effect on children.
If the regulatory action meets both criteria, the EPA must evaluate
the environmental health or safety effects of the planned regulation on
children, and explain why the planned regulation is preferable to other
potentially effective and reasonably feasible alternatives considered
by the EPA.
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Executive Order has
the potential to influence the regulation. The final rule is not
subject to Executive Order 13045 because it is based on technology
performance and not on health or safety risks.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, Office of Management and Budget, a
Statement of Energy Effects for certain actions identified as
``significant energy actions.'' Section 4(b) of Executive Order 13211
defines ``significant energy actions'' as ``any action by an agency
(normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation,
including notices of inquiry, advance notices of final rulemaking, and
notices of final rulemaking: (1)(i) That is a significant regulatory
action under Executive Order 12866 or any successor order, and (ii) is
likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) that is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
``significant energy action.'' The final rule is not a ``significant
energy action'' because it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy. The basis for the
determination is as follows.
The reduction in petroleum product output, which includes
reductions in fuel production, is estimated at only 0.001 percent, or
about 68 barrels per day based on 2000 U.S. fuel production nationwide.
That is a minimal reduction in nationwide petroleum product output. The
reduction in coal production is estimated at only 0.014 percent, or
about 3.5 million tpy (or less than 1,000 tons per day) based on 2000
U.S. coal production nationwide. The combination of the increase in
electricity usage estimated with the effect of the increased price of
affected output yields an increase in electricity output estimated at
only 0.012 percent, or about 0.72 billion kilowatt-hours per year based
on 2000 U.S. electricity production nationwide. All energy price
changes estimated show no increase in price more than 0.05 percent
nationwide, and a similar result occurs for energy distribution costs.
We also expect that there will be no discernable impact on the import
of foreign energy supplies, and no other adverse outcomes are expected
to occur with regards to energy supplies. All of the results presented
above account for the pass through of costs to consumers, as well as
the cost impact to producers. For more information on the estimated
energy effects, please refer to the economic impact analysis for the
final rule. The analysis is available in the public docket. It should
be noted that these energy impact estimates are in advance of any
facility demonstrating eligibility for the health-based compliance
alternatives.
Depending on the number of affected facilities demonstrating
eligibility for the health-based compliance alternatives, the reduction
in petroleum product output, which includes reductions in fuel
production, could fall to 65 barrels per day, or only 0.001 percent.
The reduction in coal production could fall to only 0.010 percent, or
about 2.5 million tpy based on 2000 U.S. coal production nationwide.
The combination of the increase in electricity usage estimated with the
effect of the increased price of affected output could yield an
increase in electricity output could fall to only 0.0067 percent, or
about 0.40 billion kilowatt-hours per year based on 2000 U.S.
electricity production nationwide. All energy price changes estimated
could now fall to increases of no more than 0.04 percent nationwide,
and a similar result occurs for energy distribution costs. There should
be no discernable impact on import of foreign energy supplies, and no
other adverse outcomes are expected to occur with regards to energy
supplies. All of the results presented with presumption of the health-
based compliance alternatives also account for the pass through of
costs to consumers as well as the cost impact to producers.
Therefore, we conclude that the final rule when implemented is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to the OMB, with explanations when an
agency does not use available and applicable voluntary consensus
standards.
[[Page 55252]]
The final rule involves technical standards. The EPA cites the
following standards in the final rule: EPA Methods 1, 2, 2F, 2G, 3A,
3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with
the NTTAA, EPA conducted searches to identify voluntary consensus
standards in addition to these EPA methods. No applicable voluntary
consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19.
The search and review results have been documented and are placed in
the docket for the final rule.
The three voluntary consensus standards described below were
identified as acceptable alternatives to EPA test methods for the
purposes of the final rule.
The voluntary consensus standard ASME PTC 19-10-1981-Part 10,
``Flue and Exhaust Gas Analyses,'' is cited in the final rule for its
manual method for measuring the oxygen, carbon dioxide, and carbon
monoxide content of exhaust gas. This part of ASME PTC 19-10-1981-Part
10 is an acceptable alternative to Method 3B.
The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers and Process Heaters Using
Portable Analyzers'' is an acceptable alternative to EPA Methods 3A and
10 for identifying carbon monoxide and oxygen concentrations for the
final rule when the fuel is natural gas.
The voluntary consensus standard ASTM Z65907, ``Standard Method for
Both Speciated and Elemental Mercury Determination,'' is an acceptable
alternative to EPA Method 29 (portion for mercury only) for the purpose
of the final rule. This standard can be used in the final rule to
determine the mercury concentration in stack gases for boilers with
rated heat input capacities of greater than 250 MMBtu per hour.
In addition to the voluntary consensus standards EPA uses in the
final rule, the search for emissions measurement procedures identified
15 other voluntary consensus standards. The EPA determined that 13 of
these 15 standards identified for measuring emissions of the HAP or
surrogates subject to the emission standards were impractical
alternatives to EPA test methods for the purposes of the final rule.
Therefore, EPA does not intend to adopt these standards for this
purpose. (See Docket ID No. OAR-2002-0058 for further information on
the methods.)
Two of the 15 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the final rule because they are under development by a
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2.
Section 63.7520 and Tables 4A through 4D of the final rule list the
EPA testing methods. Under Sec. 63.7(f) and Sec. 63.8(f) of subpart
A, 40 CFR part 63, of the General Provisions, a source may apply to EPA
for permission to use alternative test methods or alternative
monitoring requirements in place of any of the EPA testing methods,
performance specifications, or procedures.
J. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801, et seq., as added by
the Small Business Regulatory Enforcement Fairness Act of 1996,
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. The EPA will submit a report containing
the final rule and other required information to the United States
Senate, the United States House of Representatives, and the Comptroller
General of the United States prior to publication of the final rule in
the Federal Register. A major rule cannot take effect until 60 days
after it is published in the Federal Register. This action is a ``major
rule'' as defined by 5 U.S.C. section 804(2). The rule will be
effective on November 12, 2004.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
Dated: February 26, 2004.
Michael O. Leavitt,
Administrator.
0
For the reasons stated in the preamble, title 40, chapter I, part 63 of
the Code of Federal Regulations is amended as follows:
PART 63--[AMENDED]
0
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
0
2. Section 63.14 is amended by revising paragraph (b)(27) and paragraph
(i)(3) and adding paragraph (b)(35) and paragraphs (b)(39) through (53)
to read as follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(b) * * *
(27) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,\1\ IBR
approved for Sec. 63.9307(c)(2), Table 4 of Subpart ZZZZ, and Table 5
to Subpart DDDDD of this part.
* * * * *
(35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method),\1\ IBR approved for Table 5
to Subpart DDDDD of this part.
* * * * *
(39) ASTM Method D388-99,.\1\ Standard Classification of Coals by
Rank,\1\ IBR approved for Sec. 63.7575.
(40) ASTM D396-02a, Standard Specification for Fuel Oils,\1\ IBR
approved for Sec. 63.7575.
(41) ASTM D1835-03a, Standard Specification for Liquified Petroleum
(LP) Gases,\1\ IBR approved for Sec. 63.7575.
(42) ASTM D2013-01, Standard Practice for Preparing Coal Samples
for Analysis,\1\ IBR approved for Table 6 to Subpart DDDDD of this
part.
(43) ASTM D2234-00, .\1\ Standard Practice for Collection of a
Gross Sample of Coal,\1\ IBR approved for Table 6 to Subpart DDDDD of
this part.
(44) ASTM D3173-02, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke,\1\ IBR approved for Table 6 to
Subpart DDDDD of this part.
(45) ASTM D3683-94 (Reapproved 2000), Standard Test Method for
Trace Elements in Coal and Coke Ash Absorption,\1\ IBR approved for
Table 6 to Subpart DDDDD of this part.
(46) ASTM D3684-01, Standard Test Method for Total Mercury in Coal
by the Oxygen Bomb Combustion/Atomic Absorption Method,\1\ IBR approved
for Table 6 to Subpart DDDDD of this part.
(47) ASTM D5198-92 (Reapproved 2003), Standard Practice for Nitric
Acid Digestion of Solid Waste,\1\ IBR approved for Table 6 to Subpart
DDDDD of this part.
[[Page 55253]]
(48) ASTM D5865-03a, Standard Test Method for Gross Calorific Value
of Coal and Coke,\1\ IBR approved for Table 6 to Subpart DDDDD of this
part.
(49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory
Subsampling of Media Related to Waste Management Activities,\1\ IBR
approved for Table 6 to Subpart DDDDD of this part.
(50) ASTM E711-87 (Reapproved 1996), Standard Test Method for Gross
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter,\1\ IBR
approved for Table 6 to Subpart DDDDD of this part.
(51) ASTM E776-87 (Reapproved 1996), Standard Test Method for Forms
of Chlorine in Refuse-Derived Fuel,\1\ IBR approved for Table 6 to
Subpart DDDDD of this part.
(52) ASTM E871-82 (Reapproved 1998), Standard Method of Moisture
Analysis of Particulate Wood Fuels,\1\ IBR approved for Table 6 to
Subpart DDDDD of this part.
(53) ASTM E885-88 (Reapproved 1996), Standard Test Methods for
Analyses of Metals in Refuse-Derived Fuel by Atomic Absorption
Spectroscopy,\1\ IBR approved for Table 6 to Subpart DDDDD of this part
63.
* * * * *
(i) * * *
(3) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.
63.865(b), 63.3166(a), 63.3360(e)(1)(iii), 63.3545(a)(3),
63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3),
63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), and
Table 5 to Subpart DDDDD of this part.
* * * * *
0
3. Part 63 is amended by adding subpart DDDDD to read as follows:
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters
Sec.
What This Subpart Covers
63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this subpart?
63.7491 Are any boilers or process heaters not subject to this
subpart?
63.7495 When do I have to comply with this subpart?
Emission Limits and Work Practice Standards
63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limits, work practice standards, and operating
limits must I meet?
General Compliance Requirements
63.7505 What are my general requirements for complying with this
subpart?
63.7506 Do any boilers or process heaters have limited requirements?
63.7507 What are the health-based compliance alternatives for the
hydrogen chloride (HCl) and total selected metals (TSM) standards?
Testing, Fuel Analyses, and Initial Compliance Requirements
63.7510 What are my initial compliance requirements and by what date
must I conduct them?
63.7515 When must I conduct subsequent performance tests or fuel
analyses?
63.7520 What performance tests and procedures must I use?
63.7521 What fuel analyses and procedures must I use?
63.7522 Can I use emission averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission
limits and work practice standards?
Continuous Compliance Requirements
63.7535 How do I monitor and collect data to demonstrate continuous
compliance?
63.7540 How do I demonstrate continuous compliance with the emission
limits and work practice standards?
63.7541 How do I demonstrate continuous compliance under the
emission averaging provision?
Notifications, Reports, and Records
63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?
Other Requirements and Information
63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?
Tables to Subpart DDDDD of Part 63
Table 1 to Subpart DDDDD of Part 63--Emission Limits and Work
Practice Standards
Table 2 to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters With Particulate Matter Emission Limits
Table 3 to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters With Mercury Emission Limits and Boilers and
Process Heaters That Choose to Comply With the Alternative Total
Selected Metals Emission Limits
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters With Hydrogen Chloride Emission Limits
Table 5 to Subpart DDDDD of Part 63--Performance Testing
Requirements
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous
Compliance
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD
Appendix
Appendix A to Subpart DDDDD--Methodology and Criteria for
Demonstrating Eligibility for the Health-Based Compliance
Alternatives Specified for the Large Solid Fuel Subcategory
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters
What This Subpart Covers
Sec. 63.7480 What is the purpose of this subpart?
This subpart establishes national emission limits and work practice
standards for hazardous air pollutants (HAP) emitted from industrial,
commercial, and institutional boilers and process heaters. This subpart
also establishes requirements to demonstrate initial and continuous
compliance with the emission limits and work practice standards.
Sec. 63.7485 Am I subject to this subpart?
You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler or process heater as
defined in Sec. 63.7575 that is located at, or is part of, a major
source of HAP as defined in Sec. 63.2 or Sec. 63.761 (40 CFR part 63,
subpart HH, National Emission Standards for Hazardous Air Pollutants
from Oil and Natural Gas Production Facilities), except as specified in
Sec. 63.7491.
Sec. 63.7490 What is the affected source of this subpart?
(a) This subpart applies to new, reconstructed, or existing
affected sources as described in paragraphs (a)(1) and (2) of this
section.
(1) The affected source of this subpart is the collection of all
existing industrial, commercial, and institutional boilers and process
heaters within a subcategory located at a major source as defined in
Sec. 63.7575.
(2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler or
[[Page 55254]]
process heater located at a major source as defined in Sec. 63.7575.
(b) A boiler or process heater is new if you commence construction
of the boiler or process heater after January 13, 2003, and you meet
the applicability criteria at the time you commence construction.
(c) A boiler or process heater is reconstructed if you meet the
reconstruction criteria as defined in Sec. 63.2, you commence
reconstruction after January 13, 2003, and you meet the applicability
criteria at the time you commence reconstruction.
(d) A boiler or process heater is existing if it is not new or
reconstructed.
Sec. 63.7491 Are any boilers or process heaters not subject to this
subpart?
The types of boilers and process heaters listed in paragraphs (a)
through (o) of this section are not subject to this subpart.
(a) A municipal waste combustor covered by 40 CFR part 60, subpart
AAAA, subpart BBBB, subpart Cb or subpart Eb.
(b) A hospital/medical/infectious waste incinerator covered by 40
CFR part 60, subpart Ce or subpart Ec.
(c) An electric utility steam generating unit that is a fossil
fuel-fired combustion unit of more than 25 megawatts that serves a
generator that produces electricity for sale. A fossil fuel-fired unit
that cogenerates steam and electricity, and supplies more than one-
third of its potential electric output capacity, and more than 25
megawatts electrical output to any utility power distribution system
for sale is considered an electric utility steam generating unit.
(d) A boiler or process heater required to have a permit under
section 3005 of the Solid Waste Disposal Act or covered by 40 CFR part
63, subpart EEE (e.g., hazardous waste boilers).
(e) A commercial and industrial solid waste incineration unit
covered by 40 CFR part 60, subpart CCCC or subpart DDDD.
(f) A recovery boiler or furnace covered by 40 CFR part 63, subpart
MM.
(g) A boiler or process heater that is used specifically for
research and development. This does not include units that only provide
heat or steam to a process at a research and development facility.
(h) A hot water heater as defined in this subpart.
(i) A refining kettle covered by 40 CFR part 63, subpart X.
(j) An ethylene cracking furnace covered by 40 CFR part 63, subpart
YY.
(k) Blast furnace stoves as described in the EPA document, entitled
``National Emission Standards for Hazardous Air Pollutants (NESHAP) for
Integrated Iron and Steel Plants--Background Information for Proposed
Standards,'' (EPA-453/R-01-005).
(l) Any boiler and process heater specifically listed as an
affected source in another standard(s) under 40 CFR part 63.
(m) Any boiler and process heater specifically listed as an
affected source in another standard(s) established under section 129 of
the Clean Air Act (CAA).
(n) Temporary boilers as defined in this subpart.
(o) Blast furnace gas fuel-fired boilers and process heaters as
defined in this subpart.
Sec. 63.7495 When do I have to comply with this subpart?
(a) If you have a new or reconstructed boiler or process heater,
you must comply with this subpart by November 12, 2004 or upon startup
of your boiler or process heater, whichever is later.
(b) If you have an existing boiler or process heater, you must
comply with this subpart no later than September 13, 2007.
(c) If you have an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP,
paragraphs (c)(1) and (2) of this section apply to you.
(1) Any new or reconstructed boiler or process heater at the
existing facility must be in compliance with this subpart upon startup.
(2) Any existing boiler or process heater at the existing facility
must be in compliance with this subpart within 3 years after the
facility becomes a major source.
(d) You must meet the notification requirements in Sec. 63.7545
according to the schedule in Sec. 63.7545 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.
Emission Limits and Work Practice Standards
Sec. 63.7499 What are the subcategories of boilers and process
heaters?
The subcategories of boilers and process heaters are large solid
fuel, limited use solid fuel, small solid fuel, large liquid fuel,
limited use liquid fuel, small liquid fuel, large gaseous fuel, limited
use gaseous fuel, and small gaseous fuel. Each subcategory is defined
in Sec. 63.7575.
Sec. 63.7500 What emission limits, work practice standards, and
operating limits must I meet?
(a) You must meet the requirements in paragraphs (a)(1) and (2) of
this section.
(1) You must meet each emission limit and work practice standard in
Table 1 to this subpart that applies to your boiler or process heater,
except as provided under Sec. 63.7507.
(2) You must meet each operating limit in Tables 2 through 4 to
this subpart that applies to your boiler or process heater. If you use
a control device or combination of control devices not covered in
Tables 2 through 4 to this subpart, or you wish to establish and
monitor an alternative operating limit and alternative monitoring
parameters, you must apply to the United States Environmental
Protection Agency (EPA) Administrator for approval of alternative
monitoring under Sec. 63.8(f).
(b) As provided in Sec. 63.6(g), EPA may approve use of an
alternative to the work practice standards in this section.
General Compliance Requirements
Sec. 63.7505 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limits (including
operating limits) and the work practice standards in this subpart at
all times, except during periods of startup, shutdown, and malfunction.
(b) You must always operate and maintain your affected source,
including air pollution control and monitoring equipment, according to
the provisions in Sec. 63.6(e)(1)(i).
(c) You can demonstrate compliance with any applicable emission
limit using fuel analysis if the emission rate calculated according to
Sec. 63.7530(d) is less than the applicable emission limit. Otherwise,
you must demonstrate compliance using performance testing.
(d) If you demonstrate compliance with any applicable emission
limit through performance testing, you must develop a site-specific
monitoring plan according to the requirements in paragraphs (d)(1)
through (4) of this section. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec. 63.8(f).
(1) For each continuous monitoring system (CMS) required in this
section, you must develop and submit to the EPA Administrator for
approval a site-specific monitoring plan that addresses paragraphs
(d)(1)(i) through (iii) of this section. You must submit this site-
specific monitoring plan at least 60 days
[[Page 55255]]
before your initial performance evaluation of your CMS.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations).
(2) In your site-specific monitoring plan, you must also address
paragraphs (d)(2)(i) through (iii) of this section.
(i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 63.8(c)(1), (c)(3), and (c)(4)(ii);
(ii) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 63.8(d); and
(iii) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec. 63.10(c), (e)(1), and (e)(2)(i).
(3) You must conduct a performance evaluation of each CMS in
accordance with your site-specific monitoring plan.
(4) You must operate and maintain the CMS in continuous operation
according to the site-specific monitoring plan.
(e) If you have an applicable emission limit or work practice
standard, you must develop and implement a written startup, shutdown,
and malfunction plan (SSMP) according to the provisions in Sec.
63.6(e)(3).
Sec. 63.7506 Do any boilers or process heaters have limited
requirements?
(a) New or reconstructed boilers and process heaters in the large
liquid fuel subcategory or the limited use liquid fuel subcategory that
burn only fossil fuels and other gases and do not burn any residual oil
are subject to the emission limits and applicable work practice
standards in Table 1 to this subpart. You are not required to conduct a
performance test to demonstrate compliance with the emission limits.
You are not required to set and maintain operating limits to
demonstrate continuous compliance with the emission limits. However,
you must meet the requirements in paragraphs (a)(1) and (2) of this
section and meet the CO work practice standard in Table 1 to this
subpart.
(1) To demonstrate initial compliance, you must include a signed
statement in the Notification of Compliance Status report required in
Sec. 63.7545(e) that indicates you burn only liquid fossil fuels other
than residual oils, either alone or in combination with gaseous fuels.
(2) To demonstrate continuous compliance with the applicable
emission limits, you must also keep records that demonstrate that you
burn only liquid fossil fuels other than residual oils, either alone or
in combination with gaseous fuels. You must also include a signed
statement in each semiannual compliance report required in Sec.
63.7550 that indicates you burned only liquid fossil fuels other than
residual oils, either alone or in combination with gaseous fuels,
during the reporting period.
(b) The affected boilers and process heaters listed in paragraphs
(b)(1) through (3) of this section are subject to only the initial
notification requirements in Sec. 63.9(b) (i.e., they are not subject
to the emission limits, work practice standards, performance testing,
monitoring, SSMP, site-specific monitoring plans, recordkeeping and
reporting requirements of this subpart or any other requirements in
subpart A of this part).
(1) Existing large and limited use gaseous fuel units.
(2) Existing large and limited use liquid fuel units.
(3) New or reconstructed small liquid fuel units that burn only
gaseous fuels or distillate oil. New or reconstructed small liquid fuel
boilers and process heaters that commence burning of any other type of
liquid fuel must comply with all applicable requirements of this
subpart and subpart A of this part upon startup of burning the other
type of liquid fuel.
(c) The affected boilers and process heaters listed in paragraphs
(c)(1) through (4) of this section are not subject to the initial
notification requirements in Sec. 63.9(b) and are not subject to any
requirements in this subpart or in subpart A of this part (i.e., they
are not subject to the emission limits, work practice standards,
performance testing, monitoring, SSM plans, site-specific monitoring
plans, recordkeeping and reporting requirements of this subpart, or any
other requirements in subpart A of this part.
(1) Existing small solid fuel boilers and process heaters.
(2) Existing small liquid fuel boilers and process heaters.
(3) Existing small gaseous fuel boilers and process heaters.
(4) New or reconstructed small gaseous fuel units.
Sec. 63.7507 What are the health-based compliance alternatives for
the hydrogen chloride (HCl) and total selected metals (TSM) standards?
(a) As an alternative to the requirement for large solid fuel
boilers located at a single facility to demonstrate compliance with the
HCl emission limit in Table 1 to this subpart, you may demonstrate
eligibility for the health-based compliance alternative for HCl
emissions under the procedures prescribed in appendix A to this
subpart.
(b) In lieu of complying with the TSM emission standards in Table 1
to this subpart based on the sum of emissions for the eight selected
metals, you may demonstrate eligibility for complying with the TSM
emission standards in Table 1 based on the sum of emissions for seven
selected metals (by excluding manganese emissions from the summation of
TSM emissions) under the procedures prescribed in appendix A to this
subpart.
Testing, Fuel Analyses, and Initial Compliance Requirements
Sec. 63.7510 What are my initial compliance requirements and by what
date must I conduct them?
(a) For affected sources that elect to demonstrate compliance with
any of the emission limits of this subpart through performance testing,
your initial compliance requirements include conducting performance
tests according to Sec. 63.7520 and Table 5 to this subpart,
conducting a fuel analysis for each type of fuel burned in your boiler
or process heater according to Sec. 63.7521 and Table 6 to this
subpart, establishing operating limits according to Sec. 63.7530 and
Table 7 to this subpart, and conducting CMS performance evaluations
according to Sec. 63.7525.
(b) For affected sources that elect to demonstrate compliance with
the emission limits for HCl, mercury, or TSM through fuel analysis,
your initial compliance requirement is to conduct a fuel analysis for
each type of fuel burned in your boiler or process heater according to
Sec. 63.7521 and Table 6 to this subpart and establish operating
limits according to Sec. 63.7530 and Table 8 to this subpart.
(c) For affected sources that have an applicable work practice
standard, your initial compliance requirements depend on the
subcategory and rated capacity of your boiler or process heater. If
your boiler or process heater is in any of the limited use
subcategories or has a heat input capacity less than 100 MMBtu per
hour, your initial compliance demonstration is conducting a performance
test for carbon monoxide
[[Page 55256]]
according to Table 5 to this subpart. If your boiler or process heater
is in any of the large subcategories and has a heat input capacity of
100 MMBtu per hour or greater, your initial compliance demonstration is
conducting a performance evaluation of your continuous emission
monitoring system for carbon monoxide according to Sec. 63.7525(a).
(d) For existing affected sources, you must demonstrate initial
compliance no later than 180 days after the compliance date that is
specified for your source in Sec. 63.7495 and according to the
applicable provisions in Sec. 63.7(a)(2) as cited in Table 10 to this
subpart.
(e) If your new or reconstructed affected source commenced
construction or reconstruction between January 13, 2003 and November
12, 2004, you must demonstrate initial compliance with either the
proposed emission limits and work practice standards or the promulgated
emission limits and work practice standards no later than 180 days
after November 12, 2004 or within 180 days after startup of the source,
whichever is later, according to Sec. 63.7(a)(2)(ix).
(f) If your new or reconstructed affected source commenced
construction or reconstruction between January 13, 2003, and November
12, 2004, and you chose to comply with the proposed emission limits and
work practice standards when demonstrating initial compliance, you must
conduct a second compliance demonstration for the promulgated emission
limits and work practice standards within 3 years after November 12,
2004 or within 3 years after startup of the affected source, whichever
is later.
(g) If your new or reconstructed affected source commences
construction or reconstruction after November 12, 2004, you must
demonstrate initial compliance with the promulgated emission limits and
work practice standards no later than 180 days after startup of the
source.
Sec. 63.7515 When must I conduct subsequent performance tests or fuel
analyses?
(a) You must conduct all applicable performance tests according to
Sec. 63.7520 on an annual basis, unless you follow the requirements
listed in paragraphs (b) through (d) of this section. Annual
performance tests must be completed between 10 and 12 months after the
previous performance test, unless you follow the requirements listed in
paragraphs (b) through (d) of this section.
(b) You can conduct performance tests less often for a given
pollutant if your performance tests for the pollutant (particulate
matter, HCl, mercury, or TSM) for at least 3 consecutive years show
that you comply with the emission limit. In this case, you do not have
to conduct a performance test for that pollutant for the next 2 years.
You must conduct a performance test during the third year and no more
than 36 months after the previous performance test.
(c) If your boiler or process heater continues to meet the emission
limit for particulate matter, HCl, mercury, or TSM, you may choose to
conduct performance tests for these pollutants every third year, but
each such performance test must be conducted no more than 36 months
after the previous performance test.
(d) If a performance test shows noncompliance with an emission
limit for particulate matter, HCl, mercury, or TSM, you must conduct
annual performance tests for that pollutant until all performance tests
over a consecutive 3-year period show compliance.
(e) If you have an applicable work practice standard for carbon
monoxide and your boiler or process heater is in any of the limited use
subcategories or has a heat input capacity less than 100 MMBtu per
hour, you must conduct annual performance tests for carbon monoxide
according to Sec. 63.7520. Each annual performance test must be
conducted between 10 and 12 months after the previous performance test.
(f) You must conduct a fuel analysis according to Sec. 63.7521 for
each type of fuel burned no later than 5 years after the previous fuel
analysis for each fuel type. If you burn a new type of fuel, you must
conduct a fuel analysis before burning the new type of fuel in your
boiler or process heater. You must still meet all applicable continuous
compliance requirements in Sec. 63.7540.
(g) You must report the results of performance tests and fuel
analyses within 60 days after the completion of the performance tests
or fuel analyses. This report should also verify that the operating
limits for your affected source have not changed or provide
documentation of revised operating parameters established according to
Sec. 63.7530 and Table 7 to this subpart, as applicable. The reports
for all subsequent performance tests and fuel analyses should include
all applicable information required in Sec. 63.7550.
Sec. 63.7520 What performance tests and procedures must I use?
(a) You must conduct all performance tests according to Sec.
63.7(c), (d), (f), and (h). You must also develop a site-specific test
plan according to the requirements in Sec. 63.7(c) if you elect to
demonstrate compliance through performance testing.
(b) You must conduct each performance test according to the
requirements in Table 5 to this subpart.
(c) New or reconstructed boilers or process heaters in one of the
liquid fuel subcategories that burn only fossil fuels and other gases
and do not burn any residual oil must demonstrate compliance according
to Sec. 63.7506(a).
(d) You must conduct each performance test under the specific
conditions listed in Tables 5 and 7 to this subpart. You must conduct
performance tests at the maximum normal operating load while burning
the type of fuel or mixture of fuels that have the highest content of
chlorine, mercury, and total selected metals, and you must demonstrate
initial compliance and establish your operating limits based on these
tests. These requirements could result in the need to conduct more than
one performance test.
(e) You may not conduct performance tests during periods of
startup, shutdown, or malfunction.
(f) You must conduct three separate test runs for each performance
test required in this section, as specified in Sec. 63.7(e)(3). Each
test run must last at least 1 hour.
(g) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 of appendix A to part 60 of this chapter to convert the
measured particulate matter concentrations, the measured HCl
concentrations, the measured TSM concentrations, and the measured
mercury concentrations that result from the initial performance test to
pounds per million Btu heat input emission rates using F-factors.
Sec. 63.7521 What fuel analyses and procedures must I use?
(a) You must conduct fuel analyses according to the procedures in
paragraphs (b) through (e) of this section and Table 6 to this subpart,
as applicable.
(b) You must develop and submit a site-specific fuel analysis plan
to the EPA Administrator for review and approval according to the
following procedures and requirements in paragraphs (b)(1) and (2) of
this section.
(1) You must submit the fuel analysis plan no later than 60 days
before the date that you intend to demonstrate compliance.
(2) You must include the information contained in paragraphs
(b)(2)(i)
[[Page 55257]]
through (vi) of this section in your fuel analysis plan.
(i) The identification of all fuel types anticipated to be burned
in each boiler or process heater.
(ii) For each fuel type, the notification of whether you or a fuel
supplier will be conducting the fuel analysis.
(iii) For each fuel type, a detailed description of the sample
location and specific procedures to be used for collecting and
preparing the composite samples if your procedures are different from
paragraph (c) or (d) of this section. Samples should be collected at a
location that most accurately represents the fuel type, where possible,
at a point prior to mixing with other dissimilar fuel types.
(iv) For each fuel type, the analytical methods, with the expected
minimum detection levels, to be used for the measurement of selected
total metals, chlorine, or mercury.
(v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that will be used.
(vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
(c) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in paragraph (c)(1) or (2)
of this section.
(1) If sampling from a belt (or screw) feeder, collect fuel samples
according to paragraphs (c)(1)(i) and (ii) of this section.
(i) Stop the belt and withdraw a 6-inch wide sample from the full
cross-section of the stopped belt to obtain a minimum two pounds of
sample. Collect all the material (fines and coarse) in the full cross-
section. Transfer the sample to a clean plastic bag.
(ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal intervals during the testing
period.
(2) If sampling from a fuel pile or truck, collect fuel samples
according to paragraphs (c)(2)(i) through (iii) of this section.
(i) For each composite sample, select a minimum of five sampling
locations uniformly spaced over the surface of the pile.
(ii) At each sampling site, dig into the pile to a depth of 18
inches. Insert a clean flat square shovel into the hole and withdraw a
sample, making sure that large pieces do not fall off during sampling.
(iii) Transfer all samples to a clean plastic bag for further
processing.
(d) Prepare each composite sample according to the procedures in
paragraphs (d)(1) through (7) of this section.
(1) Throughly mix and pour the entire composite sample over a clean
plastic sheet.
(2) Break sample pieces larger than 3 inches into smaller sizes.
(3) Make a pie shape with the entire composite sample and subdivide
it into four equal parts.
(4) Separate one of the quarter samples as the first subset.
(5) If this subset is too large for grinding, repeat the procedure
in paragraph (d)(3) of this section with the quarter sample and obtain
a one-quarter subset from this sample.
(6) Grind the sample in a mill.
(7) Use the procedure in paragraph (d)(3) of this section to obtain
a one-quarter subsample for analysis. If the quarter sample is too
large, subdivide it further using the same procedure.
(e) Determine the concentration of pollutants in the fuel (mercury,
chlorine, and/or total selected metals) in units of pounds per million
Btu of each composite sample for each fuel type according to the
procedures in Table 6 to this subpart.
Sec. 63.7522 Can I use emission averaging to comply with this
subpart?
(a) As an alternative to meeting the requirements of Sec. 63.7500,
if you have more than one existing large solid fuel boiler located at
your facility, you may demonstrate compliance by emission averaging
according to the procedures in this section in a State that does not
choose to exclude emission averaging.
(b) For each existing large solid fuel boiler in the averaging
group, the emission rate achieved during the initial compliance test
for the HAP being averaged must not exceed the emission level that was
being achieved on November 12, 2004 or the control technology employed
during the initial compliance test must not be less effective for the
HAP being averaged than the control technology employed on November 12,
2004.
(c) You may average particulate matter or TSM, HCl, and mercury
emissions from existing large solid fuel boilers to demonstrate
compliance with the limits in Table 1 to this subpart if you satisfy
the requirements in paragraphs (d), (e), and (f) of this section.
(d) The weighted average emissions from the existing large solid
fuel boilers participating in the emissions averaging option must be in
compliance with the limits in Table 1 to this subpart at all times
following the compliance date specified in Sec. 63.7495.
(e) You must demonstrate initial compliance according to paragraphs
(e)(1) or (2) of this section.
(1) You must use Equation 1 of this section to demonstrate that the
particulate matter or TSM, HCl, and mercury emissions from all existing
large solid fuel boilers participating in the emissions averaging
option do not exceed the emission limits in Table 1 to this subpart.
[[Page 55258]]
[GRAPHIC] [TIFF OMITTED] TR13SE04.000
Where:
AveWeighted = Average weighted emissions for particulate matter or TSM,
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this subpart)
or fuel analysis (as calculated by the applicable equation in Sec.
63.7530(d)) for boiler, i, for particulate matter or TSM, HCl, or
mercury, in units of pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of boiler, i, in units of
million Btu per hour.
n = Number of large solid fuel boilers participating in the emissions
averaging option.
(2) If you are not capable of monitoring heat input, you can use
Equation 2 of this section as an alternative to using equation 1 of
this section to demonstrate that the particulate matter or TSM, HCl,
and mercury emissions from all existing large solid fuel boilers
participating in the emissions averaging option do not exceed the
emission limits in Table 1 to this subpart.
[GRAPHIC] [TIFF OMITTED] TR13SE04.001
Where:
AveWeighted = Average weighted emission level for PM or TSM, HCl, or
mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this subpart)
or fuel analysis (as calculated by the applicable equation in Sec.
63.7530(d)) for boiler, i, for particulate matter or TSM, HCl, or
mercury, in units of pounds per million Btu of heat input.
Sm = Maximum steam generation by boiler, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated.
(f) You must demonstrate continuous compliance on a 12-month
rolling average basis determined at the end of every month (12 times
per year) according to paragraphs (f)(1) and (2). The first 12-month
rolling-average period begins on the compliance date specified in Sec.
63.7495.
(1) For each calendar month, you must use Equation 3 of this
section to calculate the 12-month rolling average weighted emission
limit using the actual heat capacity for each existing large solid fuel
boiler participating in the emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TR13SE04.002
Where:
AveWeighted Emissions = 12-month rolling average weighted emission
level for particulate matter or TSM, HCl, or mercury, in units of
pounds per million Btu of heat input.
Er = Emission rate, calculated during the most recent compliance test,
(as calculated according to Table 5 to this subpart) or fuel analysis
(as calculated by the applicable equation in Sec. 63.7530(d)) for
boiler, i, for particulate matter or TSM, HCl, or mercury, in units of
pounds per million Btu of heat input.
Hb = The average heat input for each calendar month of boiler, i, in
units of million Btu.
n = Number of large solid fuel boilers participating in the emissions
averaging option.
(2) If you are not capable of monitoring heat input, you can use
Equation 4 of this section as an alternative to using Equation 3 of
this section to calculate the 12-month rolling average weighted
emission limit using the actual steam generation from the large solid
fuel boilers participating in the emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TR13SE04.003
Where:
AveWeighted Emissions = 12-month rolling average weighted emission
level for PM or TSM, HCl, or mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate, calculated during the most recent compliance test
(as calculated according to Table 5 to this subpart) or fuel analysis
(as calculated by the applicable equation in Sec. 63.7530(d)) for
boiler, i, for particulate matter or TSM, HCl, or mercury, in units of
pounds per million Btu of heat input.
Sa = Actual steam generation for each calender month by boiler, i, in
units of pounds.
Cf = Conversion factor, as calculated during the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated.
(g) You must develop and submit an implementation plan for emission
averaging to the applicable regulatory authority for review and
approval according to the following procedures and requirements in
paragraphs (g)(1) through (4).
[[Page 55259]]
(1) You must submit the implementation plan no later than 180 days
before the date that the facility intends to demonstrate compliance
using the emission averaging option.
(2) You must include the information contained in paragraphs
(g)(2)(i) through (vii) of this section in your implementation plan for
all emission sources included in an emissions average:
(i) The identification of all existing large solid fuel boilers in
the averaging group, including for each either the applicable HAP
emission level or the control technology installed on;
(ii) The process parameter (heat input or steam generated) that
will be monitored for each averaging group of large solid fuel boilers;
(iii) The specific control technology or pollution prevention
measure to be used for each emission source in the averaging group and
the date of its installation or application. If the pollution
prevention measure reduces or eliminates emissions from multiple
sources, the owner or operator must identify each source;
(iv) The test plan for the measurement of particulate matter (or
TSM), HCl, or mercury emissions in accordance with the requirements in
Sec. 63.7520;
(v) The operating parameters to be monitored for each control
system or device and a description of how the operating limits will be
determined;
(vi) If you request to monitor an alternative operating parameter
pursuant to Sec. 63.7525, you must also include:
(A) A description of the parameter(s) to be monitored and an
explanation of the criteria used to select the parameter(s); and
(B) A description of the methods and procedures that will be used
to demonstrate that the parameter indicates proper operation of the
control device; the frequency and content of monitoring, reporting, and
recordkeeping requirements; and a demonstration, to the satisfaction of
the applicable regulatory authority, that the proposed monitoring
frequency is sufficient to represent control device operating
conditions; and
(vii) A demonstration that compliance with each of the applicable
emission limit(s) will be achieved under representative operating
conditions.
(3) Upon receipt, the regulatory authority shall review and approve
or disapprove the plan according to the following criteria:
(i) Whether the content of the plan includes all of the information
specified in paragraph (g)(2) of this section; and
(ii) Whether the plan presents sufficient information to determine
that compliance will be achieved and maintained.
(4) The applicable regulatory authority shall not approve an
emission averaging implementation plan containing any of the following
provisions:
(i) Any averaging between emissions of differing pollutants or
between differing sources; or
(ii) The inclusion of any emission source other than an existing
large solid fuel boiler.
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If you have an applicable work practice standard for carbon
monoxide, and your boiler or process heater is in any of the large
subcategories and has a heat input capacity of 100 MMBtu per hour or
greater, you must install, operate, and maintain a continuous emission
monitoring system (CEMS) for carbon monoxide according to the
procedures in paragraphs (a)(1) through (6) of this section by the
compliance date specified in Sec. 63.7495.
(1) Each CEMS must be installed, operated, and maintained according
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and
according to the site-specific monitoring plan developed according to
Sec. 63.7505(d).
(2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec. 63.8 and according to PS 4A of
40 CFR part 60, appendix B.
(3) Each CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period.
(4) The CEMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must calculate and record a 30-day rolling average emission
rate on a daily basis. A new 30-day rolling average emission rate is
calculated as the average of all of the hourly CO emission data for the
preceding 30 operating days.
(6) For purposes of calculating data averages, you must not use
data recorded during periods of monitoring malfunctions, associated
repairs, out-of-control periods, required quality assurance or control
activities, or when your boiler or process heater is operating at less
than 50 percent of its rated capacity. You must use all the data
collected during all other periods in assessing compliance. Any period
for which the monitoring system is out of control and data are not
available for required calculations constitutes a deviation from the
monitoring requirements.
(b) If you have an applicable opacity operating limit, you must
install, operate, certify and maintain each continuous opacity
monitoring system (COMS) according to the procedures in paragraphs
(b)(1) through (7) of this section by the compliance date specified in
Sec. 63.7495.
(1) Each COMS must be installed, operated, and maintained according
to PS 1 of 40 CFR part 60, appendix B.
(2) You must conduct a performance evaluation of each COMS
according to the requirements in Sec. 63.8 and according to PS 1 of 40
CFR part 60, appendix B.
(3) As specified in Sec. 63.8(c)(4)(i), each COMS must complete a
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
(4) The COMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
COMS according to the requirements in Sec. 63.8(d). At a minimum, the
monitoring plan must include a daily calibration drift assessment, a
quarterly performance audit, and an annual zero alignment audit of each
COMS.
(6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). Identify periods the COMS is out of control including any
periods that the COMS fails to pass a daily calibration drift
assessment, a quarterly performance audit, or an annual zero alignment
audit.
(7) You must determine and record all the 6-minute averages (and 1-
hour block averages as applicable) collected for periods during which
the COMS is not out of control.
(c) If you have an operating limit that requires the use of a CMS,
you must install, operate, and maintain each continuous parameter
monitoring system (CPMS) according to the procedures in paragraphs
(c)(1) through (5) of this section by the compliance date specified in
Sec. 63.7495.
(1) The CPMS must complete a minimum of one cycle of operation for
each successive 15-minute period. You must have a minimum of four
successive cycles of operation to have a valid hour of data.
(2) Except for monitoring malfunctions, associated repairs, and
required quality assurance or control
[[Page 55260]]
activities (including, as applicable, calibration checks and required
zero and span adjustments), you must conduct all monitoring in
continuous operation at all times that the unit is operating. A
monitoring malfunction is any sudden, infrequent, not reasonably
preventable failure of the monitoring to provide valid data. Monitoring
failures that are caused in part by poor maintenance or careless
operation are not malfunctions.
(3) For purposes of calculating data averages, you must not use
data recorded during monitoring malfunctions, associated repairs, out
of control periods, or required quality assurance or control
activities. You must use all the data collected during all other
periods in assessing compliance. Any period for which the monitoring
system is out-of-control and data are not available for required
calculations constitutes a deviation from the monitoring requirements.
(4) Determine the 3-hour block average of all recorded readings,
except as provided in paragraph (c)(3) of this section.
(5) Record the results of each inspection, calibration, and
validation check.
(d) If you have an operating limit that requires the use of a flow
measurement device, you must meet the requirements in paragraphs (c)
and (d)(1) through (4) of this section.
(1) Locate the flow sensor and other necessary equipment in a
position that provides a representative flow.
(2) Use a flow sensor with a measurement sensitivity of 2 percent
of the flow rate.
(3) Reduce swirling flow or abnormal velocity distributions due to
upstream and downstream disturbances.
(4) Conduct a flow sensor calibration check at least semiannually.
(e) If you have an operating limit that requires the use of a
pressure measurement device, you must meet the requirements in
paragraphs (c) and (e)(1) through (6) of this section.
(1) Locate the pressure sensor(s) in a position that provides a
representative measurement of the pressure.
(2) Minimize or eliminate pulsating pressure, vibration, and
internal and external corrosion.
(3) Use a gauge with a minimum tolerance of 1.27 centimeters of
water or a transducer with a minimum tolerance of 1 percent of the
pressure range.
(4) Check pressure tap pluggage daily.
(5) Using a manometer, check gauge calibration quarterly and
transducer calibration monthly.
(6) Conduct calibration checks any time the sensor exceeds the
manufacturer's specified maximum operating pressure range or install a
new pressure sensor.
(f) If you have an operating limit that requires the use of a pH
measurement device, you must meet the requirements in paragraphs (c)
and (f)(1) through (3) of this section.
(1) Locate the pH sensor in a position that provides a
representative measurement of scrubber effluent pH.
(2) Ensure the sample is properly mixed and representative of the
fluid to be measured.
(3) Check the pH meter's calibration on at least two points every 8
hours of process operation.
(g) If you have an operating limit that requires the use of
equipment to monitor voltage and secondary current (or total power
input) of an electrostatic precipitator (ESP), you must use voltage and
secondary current monitoring equipment to measure voltage and secondary
current to the ESP.
(h) If you have an operating limit that requires the use of
equipment to monitor sorbent injection rate (e.g., weigh belt, weigh
hopper, or hopper flow measurement device), you must meet the
requirements in paragraphs (c) and (h)(1) through (3) of this section.
(1) Locate the device in a position(s) that provides a
representative measurement of the total sorbent injection rate.
(2) Install and calibrate the device in accordance with
manufacturer's procedures and specifications.
(3) At least annually, calibrate the device in accordance with the
manufacturer's procedures and specifications.
(i) If you elect to use a fabric filter bag leak detection system
to comply with the requirements of this subpart, you must install,
calibrate, maintain, and continuously operate a bag leak detection
system as specified in paragraphs (i)(1) through (8) of this section.
(1) You must install and operate a bag leak detection system for
each exhaust stack of the fabric filter.
(2) Each bag leak detection system must be installed, operated,
calibrated, and maintained in a manner consistent with the
manufacturer's written specifications and recommendations and in
accordance with the guidance provided in EPA-454/R-98-015, September
1997.
(3) The bag leak detection system must be certified by the
manufacturer to be capable of detecting particulate matter emissions at
concentrations of 10 milligrams per actual cubic meter or less.
(4) The bag leak detection system sensor must provide output of
relative or absolute particulate matter loadings.
(5) The bag leak detection system must be equipped with a device to
continuously record the output signal from the sensor.
(6) The bag leak detection system must be equipped with an alarm
system that will sound automatically when an increase in relative
particulate matter emissions over a preset level is detected. The alarm
must be located where it is easily heard by plant operating personnel.
(7) For positive pressure fabric filter systems that do not duct
all compartments of cells to a common stack, a bag leak detection
system must be installed in each baghouse compartment or cell.
(8) Where multiple bag leak detectors are required, the system's
instrumentation and alarm may be shared among detectors.
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limits and work practice standards?
(a) You must demonstrate initial compliance with each emission
limit and work practice standard that applies to you by either
conducting initial performance tests and establishing operating limits,
as applicable, according to Sec. 63.7520, paragraph (c) of this
section, and Tables 5 and 7 to this subpart OR conducting initial fuel
analyses to determine emission rates and establishing operating limits,
as applicable, according to Sec. 63.7521, paragraph (d) of this
section, and Tables 6 and 8 to this subpart.
(b) New or reconstructed boilers or process heaters in one of the
liquid fuel subcategories that burn only fossil fuels and other gases
and do not burn any residual oil must demonstrate compliance according
to Sec. 63.7506(a).
(c) If you demonstrate compliance through performance testing, you
must establish each site-specific operating limit in Tables 2 through 4
to this subpart that applies to you according to the requirements in
Sec. 63.7520, Table 7 to this subpart, and paragraph (c)(4) of this
section, as applicable. You must also conduct fuel analyses according
to Sec. 63.7521 and establish maximum fuel pollutant input levels
according to paragraphs (c)(1) through (3) of this section, as
applicable.
(1) You must establish the maximum chlorine fuel input
(Cinput) during the initial performance testing according to
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in
[[Page 55261]]
your boiler or process heater that has the highest content of chlorine.
(ii) During the performance testing for HCl, you must determine the
fraction of the total heat input for each fuel type burned
(Qi) based on the fuel mixture that has the highest content
of chlorine, and the average chlorine concentration of each fuel type
burned (Ci).
(iii) You must establish a maximum chlorine input level using
Equation 5 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.004
Where:
Clinput = Maximum amount of chlorine entering the boiler or
process heater through fuels burned in units of pounds per million Btu.
Ci = Arithmetic average concentration of chlorine in fuel
type, i, analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i, based
on the fuel mixture that has the highest content of chlorine. If you do
not burn multiple fuel types during the performance testing, it is not
necessary to determine the value of this term. Insert a value of ``1''
for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
(2) If you choose to comply with the alternative TSM emission limit
instead of the particulate matter emission limit, you must establish
the maximum TSM fuel input level (TSMinput) during the
initial performance testing according to the procedures in paragraphs
(c)(2)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
TSM.
(ii) During the performance testing for TSM, you must determine the
fraction of total heat input from each fuel burned (Qi)
based on the fuel mixture that has the highest content of total
selected metals, and the average TSM concentration of each fuel type
burned (Mi).
(iii) You must establish a baseline TSM input level using Equation
6 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.005
Where:
TSMinput = Maximum amount of TSM entering the boiler or
process heater through fuels burned in units of pounds per million Btu.
Mi = Arithmetic average concentration of TSM in fuel type,
i, analyzed according to Sec. 63.7521, in units of pounds per million
Btu.
Qi = Fraction of total heat input from based fuel type, i,
based on the fuel mixture that has the highest content of TSM. If you
do not burn multiple fuel types during the performance test, it is not
necessary to determine the value of this term. Insert a value of ``1''
for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of TSM.
(3) You must establish the maximum mercury fuel input level
(Mercuryinput) during the initial performance testing using
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
mercury.
(ii) During the compliance demonstration for mercury, you must
determine the fraction of total heat input for each fuel burned
(Qi) based on the fuel mixture that has the highest content
of mercury, and the average mercury concentration of each fuel type
burned (HGi).
(iii) You must establish a maximum mercury input level using
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.006
Where:
Mercuryinput = Maximum amount of mercury entering the boiler
or process heater through fuels burned in units of pounds per million
Btu.
HGi = Arithmetic average concentration of mercury in fuel
type, i, analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i, based
on the fuel mixture that has the highest mercury content. If you do not
burn multiple fuel types during the performance test, it is not
necessary to determine the value of this term. Insert a value of ``1''
for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of mercury.
(4) You must establish parameter operating limits according to
paragraphs (c)(4)(i) through (iv) of this section.
(i) For a wet scrubber, you must establish the minimum scrubber
effluent pH, liquid flowrate, and pressure drop as defined in Sec.
63.7575, as your operating limits during the three-run performance
test. If you use a wet scrubber and you conduct separate performance
tests for particulate matter, HCl, and mercury emissions, you must
establish one set of minimum scrubber effluent pH, liquid flowrate, and
pressure drop operating limits. The minimum scrubber effluent pH
operating limit must be established during the HCl performance test. If
you conduct multiple performance tests, you must set the minimum liquid
flowrate and pressure drop operating limits at the highest minimum
values established during the performance tests.
(ii) For an electrostatic precipitator, you must establish the
minimum voltage and secondary current (or total power input), as
defined in Sec. 63.7575, as your operating limits during the three-run
performance test.
(iii) For a dry scrubber, you must establish the minimum sorbent
injection rate, as defined in Sec. 63.7575, as your operating limit
during the three-run performance test.
(iv) The operating limit for boilers or process heaters with fabric
filters that choose to demonstrate continuous compliance through bag
leak detection systems is that a bag leak detection system be installed
according to the requirements in Sec. 63.7525, and that each fabric
filter must be operated such that the bag leak detection system alarm
does not sound more than 5 percent of the operating time during a 6-
month period.
(d) If you elect to demonstrate compliance with an applicable
emission limit through fuel analysis, you must conduct fuel analyses
according to Sec. 63.7521 and follow the procedures in paragraphs
(d)(1) through (5) of this section.
(1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your boiler or process heater that would
result in the maximum emission rates of the pollutants that you elect
to demonstrate compliance through fuel analysis.
(2) You must determine the 90th percentile confidence level fuel
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided z-statistic test described in Equation 8 of
this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.012
Where:
P90 = 90th percentile confidence level pollutant
concentration, in pounds per million Btu.
[[Page 55262]]
mean = Arithmetic average of the fuel pollutant concentration in the
fuel samples analyzed according to Sec. 63.7521, in units of pounds
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel
samples analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
t = t distribution critical value for 90th percentile (0.1) probability
for the appropriate degrees of freedom (number of samples minus one) as
obtained from a Distribution Critical Value Table.
(3) To demonstrate compliance with the applicable emission limit
for HCl, the HCl emission rate that you calculate for your boiler or
process heater using Equation 9 of this section must be less than the
applicable emission limit for HCl.
[GRAPHIC] [TIFF OMITTED] TR13SE04.007
Where:
HCl = HCl emission rate from the boiler or process heater in units of
pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of
chlorine in fuel type, i, in units of pounds per million Btu as
calculated according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based
on the fuel mixture that has the highest content of chlorine. If you do
not burn multiple fuel types, it is not necessary to determine the
value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.
(4) To demonstrate compliance with the applicable emission limit
for TSM, the TSM emission rate that you calculate for your boiler or
process heater using Equation 10 of this section must be less than the
applicable emission limit for TSM.
[GRAPHIC] [TIFF OMITTED] TR13SE04.008
Where:
TSM = TSM emission rate from the boiler or process heater in units of
pounds per million Btu.
Mi90 = 90th percentile confidence level concentration of TSM
in fuel, i, in units of pounds per million Btu as calculated according
to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based
on the fuel mixture that has the highest content of total selected
metals. If you do not burn multiple fuel types, it is not necessary to
determine the value of this term. Insert a value of ``1'' for
Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of TSM.
(5) To demonstrate compliance with the applicable emission limit
for mercury, the mercury emission rate that you calculate for your
boiler or process heater using Equation 11 of this section must be less
than the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TR13SE04.009
Where:
Mercury = Mercury emission rate from the boiler or process heater in
units of pounds per million Btu.
HGi90 = 90th percentile confidence level concentration of
mercury in fuel, i, in units of pounds per million Btu as calculated
according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based
on the fuel mixture that has the highest mercury content. If you do not
burn multiple fuel types, it is not necessary to determine the value of
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest mercury content.
(e) You must submit the Notification of Compliance Status
containing the results of the initial compliance demonstration
according to the requirements in Sec. 63.7545(e).
Continuous Compliance Requirements
Sec. 63.7535 How do I monitor and collect data to demonstrate
continuous compliance?
(a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec. 63.7505(d).
(b) Except for monitor malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must monitor continuously (or collect data at all required
intervals) at all times that the affected source is operating.
(c) You may not use data recorded during monitoring malfunctions,
associated repairs, or required quality assurance or control activities
in data averages and calculations used to report emission or operating
levels. You must use all the data collected during all other periods in
assessing the operation of the control device and associated control
system. Boilers and process heaters that have an applicable carbon
monoxide work practice standard and are required to install and operate
a CEMS, may not use data recorded during periods when the boiler or
process heater is operating at less than 50 percent of its rated
capacity.
Sec. 63.7540 How do I demonstrate continuous compliance with the
emission limits and work practice standards?
(a) You must demonstrate continuous compliance with each emission
limit, operating limit, and work practice standard in Tables 1 through
4 to this subpart that applies to you according to the methods
specified in Table 8 to this subpart and paragraphs (a)(1) through (10)
of this section.
(1) Following the date on which the initial performance test is
completed or is required to be completed under Sec. Sec. 63.7 and
63.7510, whichever date comes first, you must not operate above any of
the applicable maximum operating limits or below any of the applicable
minimum operating limits listed in Tables 2 through 4 to this subpart
at all times except during periods of startup, shutdown and
malfunction. Operating limits do not apply during performance tests.
Operation above the established maximum or below the established
minimum operating limits shall constitute a deviation of established
operating limits.
(2) You must keep records of the type and amount of all fuels
burned in each boiler or process heater during the reporting period to
demonstrate that all fuel types and mixtures of fuels burned would
either result in lower emissions of TSM, HCl, and mercury, than the
applicable emission limit for each pollutant (if you demonstrate
compliance through fuel analysis), or result in lower fuel input of
TSM, chlorine, and mercury than the maximum values calculated during
the last performance tests (if you demonstrate compliance through
performance testing).
(3) If you demonstrate compliance with an applicable HCl emission
limit through fuel analysis and you plan to burn a new type of fuel,
you must recalculate the HCl emission rate using Equation 9 of Sec.
63.7530 according to paragraphs (a)(3)(i) through (iii) of this
section.
[[Page 55263]]
(i) You must determine the chlorine concentration for any new fuel
type in units of pounds per million Btu, based on supplier data or your
own fuel analysis, according to the provisions in your site-specific
fuel analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of chlorine.
(iii) Recalculate the HCl emission rate from your boiler or process
heater under these new conditions using Equation 9 of Sec. 63.7530.
The recalculated HCl emission rate must be less than the applicable
emission limit.
(4) If you demonstrate compliance with an applicable HCl emission
limit through performance testing and you plan to burn a new type of
fuel type or a new mixture of fuels, you must recalculate the maximum
chlorine input using Equation 5 of Sec. 63.7530. If the results of
recalculating the maximum chlorine input using Equation 5 of Sec.
63.7530 are higher than the maximum chlorine input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the HCl emissions do not exceed the emission limit. You must also
establish new operating limits based on this performance test according
to the procedures in Sec. 63.7530(c).
(5) If you demonstrate compliance with an applicable TSM emission
limit through fuel analysis, and you plan to burn a new type of fuel,
you must recalculate the TSM emission rate using Equation 10 of Sec.
63.7530 according to the procedures specified in paragraphs (a)(5)(i)
through (iii) of this section.
(i) You must determine the TSM concentration for any new fuel type
in units of pounds per million Btu, based on supplier data or your own
fuel analysis, according to the provisions in your site-specific fuel
analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of TSM.
(iii) Recalculate the TSM emission rate from your boiler or process
heater under these new conditions using Equation 10 of Sec. 63.7530.
The recalculated TSM emission rate must be less than the applicable
emission limit.
(6) If you demonstrate compliance with an applicable TSM emission
limit through performance testing, and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum TSM
input using Equation 6 of Sec. 63.7530. If the results of
recalculating the maximum total selected metals input using Equation 6
of Sec. 63.7530 are higher than the maximum TSM input level
established during the previous performance test, then you must conduct
a new performance test within 60 days of burning the new fuel type or
fuel mixture according to the procedures in Sec. 63.7520 to
demonstrate that the TSM emissions do not exceed the emission limit.
You must also establish new operating limits based on this performance
test according to the procedures in Sec. 63.7530(c).
(7) If you demonstrate compliance with an applicable mercury
emission limit through fuel analysis, and you plan to burn a new type
of fuel, you must recalculate the mercury emission rate using Equation
11 of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(7)(i) through (iii) of this section.
(i) You must determine the mercury concentration for any new fuel
type in units of pounds per million Btu, based on supplier data or your
own fuel analysis, according to the provisions in your site-specific
fuel analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of mercury.
(iii) Recalculate the mercury emission rate from your boiler or
process heater under these new conditions using Equation 11 of Sec.
63.7530. The recalculated mercury emission rate must be less than the
applicable emission limit.
(8) If you demonstrate compliance with an applicable mercury
emission limit through performance testing, and you plan to burn a new
type of fuel or a new mixture of fuels, you must recalculate the
maximum mercury input using Equation 7 of Sec. 63.7530. If the results
of recalculating the maximum mercury input using Equation 7 of Sec.
63.7530 are higher than the maximum mercury input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the mercury emissions do not exceed the emission limit. You must
also establish new operating limits based on this performance test
according to the procedures in Sec. 63.7530(c).
(9) If your unit is controlled with a fabric filter, and you
demonstrate continuous compliance using a bag leak detection system,
you must initiate corrective action within 1 hour of a bag leak
detection system alarm and complete corrective actions according to
your SSMP, and operate and maintain the fabric filter system such that
the alarm does not sound more than 5 percent of the operating time
during a 6-month period. You must also keep records of the date, time,
and duration of each alarm, the time corrective action was initiated
and completed, and a brief description of the cause of the alarm and
the corrective action taken. You must also record the percent of the
operating time during each 6-month period that the alarm sounds. In
calculating this operating time percentage, if inspection of the fabric
filter demonstrates that no corrective action is required, no alarm
time is counted. If corrective action is required, each alarm shall be
counted as a minimum of 1 hour. If you take longer than 1 hour to
initiate corrective action, the alarm time shall be counted as the
actual amount of time taken to initiate corrective action.
(10) If you have an applicable work practice standard for carbon
monoxide, and you are required to install a CEMS according to Sec.
63.7525(a), then you must meet the requirements in paragraphs
(a)(10)(i) through (iii) of this section.
(i) You must continuously monitor carbon monoxide according to
Sec. Sec. 63.7525(a) and 63.7535.
(ii) Maintain a carbon monoxide emission level below your
applicable carbon monoxide work practice standard in Table 1 to this
subpart at all times except during periods of startup, shutdown,
malfunction, and when your boiler or process heater is operating at
less than 50 percent of rated capacity.
(iii) Keep records of carbon monoxide levels according to Sec.
63.7555(b).
(b) You must report each instance in which you did not meet each
emission limit, operating limit, and work practice standard in Tables 1
through 4 to this subpart that apply to you. You must also report each
instance during a startup, shutdown, or malfunction when you did not
meet each applicable emission limit, operating limit, and work practice
standard. These instances are deviations from the emission limits and
work practice standards in this subpart. These deviations must be
reported according to the requirements in Sec. 63.7550.
(c) During periods of startup, shutdown, and malfunction, you must
operate in accordance with the SSMP as required in Sec. 63.7505(e).
(d) Consistent with Sec. Sec. 63.6(e)and 63.7(e)(1), deviations
that occur during a period of startup, shutdown, or malfunction are not
violations if you demonstrate to the EPA Administrator's satisfaction
that you were operating in accordance with your SSMP. The EPA
Administrator will determine whether
[[Page 55264]]
deviations that occur during a period of startup, shutdown, or
malfunction are violations, according to the provisions in Sec.
63.6(e).
Sec. 63.7541 How do I demonstrate continuous compliance under the
emission averaging provision?
(a) Following the compliance date, the owner or operator must
demonstrate compliance with this subpart on a continuous basis by
meeting the requirements of paragraphs (a)(1) through (4) of this
section.
(1) For each calendar month, demonstrate compliance with the
average weighted emissions limit for the existing large solid fuel
boilers participating in the emissions averaging option as determined
in Sec. 63.7522(f) and (g);
(2) For each existing solid fuel boiler participating in the
emissions averaging option that is equipped with a dry control system,
maintain opacity at or below the applicable limit;
(3) For each existing solid fuel boiler participating in the
emissions averaging option that is equipped with a wet scrubber,
maintain the 3-hour average parameter values at or below the operating
limits established during the most recent performance test; and
(4) For each existing solid fuel boiler participating in the
emissions averaging option that has an approved alternative operating
plan, maintain the 3-hour average parameter values at or below the
operating limits established in the most recent performance test.
(b) Any instance where the owner or operator fails to comply with
the continuous monitoring requirements in paragraphs (a)(1) through (4)
of this section, except during periods of startup, shutdown, and
malfunction, is a deviation.
Notification, Reports, and Records
Sec. 63.7545 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec. Sec. 63.7(b)
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply
to you by the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you startup your affected
source before November 12, 2004, you must submit an Initial
Notification not later than 120 days after November 12, 2004. The
Initial Notification must include the information required in
paragraphs (b)(1) and (2) of this section, as applicable.
(1) If your affected source has an annual capacity factor of
greater than 10 percent, your Initial Notification must include the
information required by Sec. 63.9(b)(2).
(2) If your affected source has a federally enforceable permit that
limits the annual capacity factor to less than or equal to 10 percent
such that the unit is in one of the limited use subcategories (the
limited use solid fuel subcategory, the limited use liquid fuel
subcategory, or the limited use gaseous fuel subcategory), your Initial
Notification must include the information required by Sec. 63.9(b)(2)
and also a signed statement indicating your affected source has a
federally enforceable permit that limits the annual capacity factor to
less than or equal to 10 percent.
(c) As specified in Sec. 63.9(b)(4) and (b)(5), if you startup
your new or reconstructed affected source on or after November 12,
2004, you must submit an Initial Notification not later than 15 days
after the actual date of startup of the affected source.
(d) If you are required to conduct a performance test you must
submit a Notification of Intent to conduct a performance test at least
30 days before the performance test is scheduled to begin.
(e) If you are required to conduct an initial compliance
demonstration as specified in Sec. 63.7530(a), you must submit a
Notification of Compliance Status according to Sec. 63.9(h)(2)(ii).
For each initial compliance demonstration, you must submit the
Notification of Compliance Status, including all performance test
results and fuel analyses, before the close of business on the 60th day
following the completion of the performance test and/or other initial
compliance demonstrations according to Sec. 63.10(d)(2). The
Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(1) through (9), as applicable.
(1) A description of the affected source(s) including
identification of which subcategory the source is in, the capacity of
the source, a description of the add-on controls used on the source
description of the fuel(s) burned, and justification for the fuel(s)
burned during the performance test.
(2) Summary of the results of all performance tests, fuel analyses,
and calculations conducted to demonstrate initial compliance including
all established operating limits.
(3) Identification of whether you are complying with the
particulate matter emission limit or the alternative total selected
metals emission limit.
(4) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance testing or fuel
analysis.
(5) Identification of whether you plan to demonstrate compliance by
emissions averaging.
(6) A signed certification that you have met all applicable
emission limits and work practice standards.
(7) A summary of the carbon monoxide emissions monitoring data and
the maximum carbon monoxide emission levels recorded during the
performance test to show that you have met any applicable work practice
standard in Table 1 to this subpart.
(8) If your new or reconstructed boiler or process heater is in one
of the liquid fuel subcategories and burns only liquid fossil fuels
other than residual oil either alone or in combination with gaseous
fuels, you must submit a signed statement certifying this in your
Notification of Compliance Status report.
(9) If you had a deviation from any emission limit or work practice
standard, you must also submit a description of the deviation, the
duration of the deviation, and the corrective action taken in the
Notification of Compliance Status report.
Sec. 63.7550 What reports must I submit and when?
(a) You must submit each report in Table 9 to this subpart that
applies to you.
(b) Unless the EPA Administrator has approved a different schedule
for submission of reports under Sec. 63.10(a), you must submit each
report by the date in Table 9 to this subpart and according to the
requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.7495 and ending on June 30 or December 31, whichever date is the
first date that occurs at least 180 days after the compliance date that
is specified for your source in Sec. 63.7495.
(2) The first compliance report must be postmarked or delivered no
later than July 31 or January 31, whichever date is the first date
following the end of the first calendar half after the compliance date
that is specified for your source in Sec. 63.7495.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or
delivered
[[Page 55265]]
no later than July 31 or January 31, whichever date is the first date
following the end of the semiannual reporting period.
(5) For each affected source that is subject to permitting
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the
permitting authority has established dates for submitting semiannual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (b)(1) through (4) of
this section.
(c) The compliance report must contain the information required in
paragraphs (c)(1) through (11) of this section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name,
title, and signature, certifying the truth, accuracy, and completeness
of the content of the report.
(3) Date of report and beginning and ending dates of the reporting
period.
(4) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the semiannual reporting
period, including, but not limited to, a description of the fuel and
the total fuel usage amount with units of measure.
(5) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable.
(6) A signed statement indicating that you burned no new types of
fuel. Or, if you did burn a new type of fuel, you must submit the
calculation of chlorine input, using Equation 5 of Sec. 63.7530, that
demonstrates that your source is still within its maximum chlorine
input level established during the previous performance testing (for
sources that demonstrate compliance through performance testing) or you
must submit the calculation of HCl emission rate using Equation 9 of
Sec. 63.7530 that demonstrates that your source is still meeting the
emission limit for HCl emissions (for boilers or process heaters that
demonstrate compliance through fuel analysis). If you burned a new type
of fuel, you must submit the calculation of TSM input, using Equation 6
of Sec. 63.7530, that demonstrates that your source is still within
its maximum TSM input level established during the previous performance
testing (for sources that demonstrate compliance through performance
testing), or you must submit the calculation of TSM emission rate using
Equation 10 of Sec. 63.7530 that demonstrates that your source is
still meeting the emission limit for TSM emissions (for boilers or
process heaters that demonstrate compliance through fuel analysis). If
you burned a new type of fuel, you must submit the calculation of
mercury input, using Equation 7 of Sec. 63.7530, that demonstrates
that your source is still within its maximum mercury input level
established during the previous performance testing (for sources that
demonstrate compliance through performance testing), or you must submit
the calculation of mercury emission rate using Equation 11 of Sec.
63.7530 that demonstrates that your source is still meeting the
emission limit for mercury emissions (for boilers or process heaters
that demonstrate compliance through fuel analysis).
(7) If you wish to burn a new type of fuel and you can not
demonstrate compliance with the maximum chlorine input operating limit
using Equation 5 of Sec. 63.7530, the maximum TSM input operating
limit using Equation 6 of Sec. 63.7530, or the maximum mercury input
operating limit using Equation 7 of Sec. 63.7530, you must include in
the compliance report a statement indicating the intent to conduct a
new performance test within 60 days of starting to burn the new fuel.
(8) The hours of operation for each boiler and process heater that
is subject to an emission limit for each calendar month within the
semiannual reporting period. This requirement applies only to limited
use boilers and process heaters.
(9) If you had a startup, shutdown, or malfunction during the
reporting period and you took actions consistent with your SSMP, the
compliance report must include the information in Sec. 63.10(d)(5)(i).
(10) If there are no deviations from any emission limits or
operating limits in this subpart that apply to you, and there are no
deviations from the requirements for work practice standards in this
subpart, a statement that there were no deviations from the emission
limits, operating limits, or work practice standards during the
reporting period.
(11) If there were no periods during which the CMSs, including
CEMS, COMS, and CPMS, were out of control as specified in Sec.
63.8(c)(7), a statement that there were no periods during which the
CMSs were out of control during the reporting period.
(d) For each deviation from an emission limit or operating limit in
this subpart and for each deviation from the requirements for work
practice standards in this subpart that occurs at an affected source
where you are not using a CMSs to comply with that emission limit,
operating limit, or work practice standard, the compliance report must
contain the information in paragraphs (c)(1) through (10) of this
section and the information required in paragraphs (d)(1) through (4)
of this section. This includes periods of startup, shutdown, and
malfunction.
(1) The total operating time of each affected source during the
reporting period.
(2) A description of the deviation and which emission limit,
operating limit, or work practice standard from which you deviated.
(3) Information on the number, duration, and cause of deviations
(including unknown cause), as applicable, and the corrective action
taken.
(4) A copy of the test report if the annual performance test showed
a deviation from the emission limit for particulate matter or the
alternative TSM limit, a deviation from the HCl emission limit, or a
deviation from the mercury emission limit.
(e) For each deviation from an emission limitation and operating
limit or work practice standard in this subpart occurring at an
affected source where you are using a CMS to comply with that emission
limit, operating limit, or work practice standard, you must include the
information in paragraphs (c) (1) through (10) of this section and the
information required in paragraphs (e) (1) through (12) of this
section. This includes periods of startup, shutdown, and malfunction
and any deviations from your site-specific monitoring plan as required
in Sec. 63.7505(d).
(1) The date and time that each malfunction started and stopped and
description of the nature of the deviation (i.e., what you deviated
from).
(2) The date and time that each CMS was inoperative, except for
zero (low-level) and high-level checks.
(3) The date, time, and duration that each CMS was out of control,
including the information in Sec. 63.8(c)(8).
(4) The date and time that each deviation started and stopped, and
whether each deviation occurred during a period of startup, shutdown,
or malfunction or during another period.
(5) A summary of the total duration of the deviation during the
reporting period and the total duration as a percent of the total
source operating time during that reporting period.
(6) A breakdown of the total duration of the deviations during the
reporting period into those that are due to startup, shutdown, control
equipment problems,
[[Page 55266]]
process problems, other known causes, and other unknown causes.
(7) A summary of the total duration of CMSs downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
(8) An identification of each parameter that was monitored at the
affected source for which there was a deviation, including opacity,
carbon monoxide, and operating parameters for wet scrubbers and other
control devices.
(9) A brief description of the source for which there was a
deviation.
(10) A brief description of each CMS for which there was a
deviation.
(11) The date of the latest CMS certification or audit for the
system for which there was a deviation.
(12) A description of any changes in CMSs, processes, or controls
since the last reporting period for the source for which there was a
deviation.
(f) Each affected source that has obtained a title V operating
permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all
deviations as defined in this subpart in the semiannual monitoring
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source submits a compliance report
pursuant to Table 9 to this subpart along with, or as part of, the
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all
required information concerning deviations from any emission limit,
operating limit, or work practice requirement in this subpart,
submission of the compliance report satisfies any obligation to report
the same deviations in the semiannual monitoring report. However,
submission of a compliance report does not otherwise affect any
obligation the affected source may have to report deviations from
permit requirements to the permit authority.
(g) If you operate a new gaseous fuel unit that is subject to the
work practice standard specified in Table 1 to this subpart, and you
intend to use a fuel other than natural gas or equivalent to fire the
affected unit, you must submit a notification of alternative fuel use
within 48 hours of the declaration of a period of natural gas
curtailment or supply interruption, as defined in Sec. 63.7575. The
notification must include the information specified in paragraphs
(g)(1) through (5) of this section.
(1) Company name and address.
(2) Identification of the affected unit.
(3) Reason you are unable to use natural gas or equivalent fuel,
including the date when the natural gas curtailment was declared or the
natural gas supply interruption began.
(4) Type of alternative fuel that you intend to use.
(5) Dates when the alternative fuel use is expected to begin and
end.
Sec. 63.7555 What records must I keep?
(a) You must keep records according to paragraphs (a)(1) through
(3) of this section.
(1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status or semiannual
compliance report that you submitted, according to the requirements in
Sec. 63.10(b)(2)(xiv).
(2) The records in Sec. 63.6(e)(3)(iii) through (v) related to
startup, shutdown, and malfunction.
(3) Records of performance tests, fuel analyses, or other
compliance demonstrations, performance evaluations, and opacity
observations as required in Sec. 63.10(b)(2)(viii).
(b) For each CEMS, CPMS, and COMS, you must keep records according
to paragraphs (b)(1) through (5) of this section.
(1) Records described in Sec. 63.10(b)(2) (vi) through (xi).
(2) Monitoring data for continuous opacity monitoring system during
a performance evaluation as required in Sec. 63.6(h)(7)(i) and (ii).
(3) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(4) Request for alternatives to relative accuracy test for CEMS as
required in Sec. 63.8(f)(6)(i).
(5) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 8 to this subpart
including records of all monitoring data and calculated averages for
applicable operating limits such as opacity, pressure drop, carbon
monoxide, and pH to show continuous compliance with each emission
limit, operating limit, and work practice standard that applies to you.
(d) For each boiler or process heater subject to an emission limit,
you must also keep the records in paragraphs (d)(1) through (5) of this
section.
(1) You must keep records of monthly fuel use by each boiler or
process heater, including the type(s) of fuel and amount(s) used.
(2) You must keep records of monthly hours of operation by each
boiler or process heater. This requirement applies only to limited-use
boilers and process heaters.
(3) A copy of all calculations and supporting documentation of
maximum chlorine fuel input, using Equation 5 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the HCl emission
limit, for sources that demonstrate compliance through performance
testing. For sources that demonstrate compliance through fuel analysis,
a copy of all calculations and supporting documentation of HCl emission
rates, using Equation 9 of Sec. 63.7530, that were done to demonstrate
compliance with the HCl emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum chlorine fuel input or HCl emission rates. You can use the
results from one fuel analysis for multiple boilers and process heaters
provided they are all burning the same fuel type. However, you must
calculate chlorine fuel input, or HCl emission rate, for each boiler
and process heater.
(4) A copy of all calculations and supporting documentation of
maximum TSM fuel input, using Equation 6 of Sec. 63.7530, that were
done to demonstrate continuous compliance with the TSM emission limit
for sources that demonstrate compliance through performance testing.
For sources that demonstrate compliance through fuel analysis, a copy
of all calculations and supporting documentation of TSM emission rates,
using Equation 10 of Sec. 63.7530, that were done to demonstrate
compliance with the TSM emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum TSM fuel input or TSM emission rates. You can use the results
from one fuel analysis for multiple boilers and process heaters
provided they are all burning the same fuel type. However, you must
calculate TSM fuel input, or TSM emission rates, for each boiler and
process heater.
(5) A copy of all calculations and supporting documentation of
maximum mercury fuel input, using Equation 7 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the mercury
emission limit for sources that demonstrate compliance through
performance testing. For sources that demonstrate compliance through
fuel analysis, a copy of all calculations and supporting documentation
of mercury emission rates, using Equation 11 of Sec. 63.7530, that
were done to demonstrate compliance with the mercury emission limit.
Supporting documentation should
[[Page 55267]]
include results of any fuel analyses and basis for the estimates of
maximum mercury fuel input or mercury emission rates. You can use the
results from one fuel analysis for multiple boilers and process heaters
provided they are all burning the same fuel type. However, you must
calculate mercury fuel input, or mercury emission rates, for each
boiler and process heater.
(e) If your boiler or process heater is subject to an emission
limit or work practice standard in Table 1 to this subpart and has a
federally enforceable permit that limits the annual capacity factor to
less than or equal to 10 percent such that the unit is in one of the
limited use subcategories, you must keep the records in paragraphs
(e)(1) and (2) of this section.
(1) A copy of the federally enforceable permit that limits the
annual capacity factor of the source to less than or equal to 10
percent.
(2) Fuel use records for the days the boiler or process heater was
operating.
Sec. 63.7560 In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 63.10(b)(1). You can keep
the records off site for the remaining 3 years.
Other Requirements and Information
Sec. 63.7565 What parts of the General Provisions apply to me?
Table 10 to this subpart shows which parts of the General
Provisions in Sec. Sec. 63.1 through 63.15 apply to you.
Sec. 63.7570 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by U.S. EPA, or a
delegated authority such as your State, local, or tribal agency. If the
EPA Administrator has delegated authority to your State, local, or
tribal agency, then that agency (as well as the U.S. EPA) has the
authority to implement and enforce this subpart. You should contact
your EPA Regional Office to find out if this subpart is delegated to
your State, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities listed in paragraphs (b)(1) through (5) of
this section are retained by the EPA Administrator and are not
transferred to the State, local, or tribal agency, however, the U.S.
EPA retains oversight of this subpart and can take enforcement actions,
as appropriate.
(1) Approval of alternatives to the non-opacity emission limits and
work practice standards in Sec. 63.7500(a) and (b) under Sec.
63.6(g).
(2) Approval of alternative opacity emission limits in Sec.
63.7500(a) under Sec. 63.6(h)(9).
(3) Approval of major change to test methods in Table 5 to this
subpart under Sec. 63.7(e)(2)(ii) and (f) and as defined in Sec.
63.90.
(4) Approval of major change to monitoring under Sec. 63.8(f) and
as defined in Sec. 63.90.
(5) Approval of major change to recordkeeping and reporting under
Sec. 63.10(f) and as defined in Sec. 63.90.
Sec. 63.7575 What definitions apply to this subpart?
Terms used in this subpart are defined in the CAA, in Sec. 63.2
(the General Provisions), and in this section as follows:
Annual capacity factor means the ratio between the actual heat
input to a boiler or process heater from the fuels burned during a
calendar year, and the potential heat input to the boiler or process
heater had it been operated for 8,760 hours during a year at the
maximum steady state design heat input capacity.
Bag leak detection system means an instrument that is capable of
monitoring particulate matter loadings in the exhaust of a fabric
filter (i.e., baghouse) in order to detect bag failures. A bag leak
detection system includes, but is not limited to, an instrument that
operates on electrodynamic, triboelectric, light scattering, light
transmittance, or other principle to monitor relative particulate
matter loadings.
Biomass fuel means unadulterated wood as defined in this subpart,
wood residue, and wood products (e.g., trees, tree stumps, tree limbs,
bark, lumber, sawdust, sanderdust, chips, scraps, slabs, millings, and
shavings); animal litter; vegetative agricultural and silvicultural
materials, such as logging residues (slash), nut and grain hulls and
chaff (e.g., almond, walnut, peanut, rice, and wheat), bagasse, orchard
prunings, corn stalks, coffee bean hulls and grounds.
Blast furnace gas fuel-fired boiler or process heater means an
industrial/commercial/institutional boiler or process heater that
receives 90 percent or more of its total heat input (based on an annual
average) from blast furnace gas.
Boiler means an enclosed device using controlled flame combustion
and having the primary purpose of recovering thermal energy in the form
of steam or hot water. Waste heat boilers are excluded from this
definition.
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials in ASTM D388-991 .\1\, ``Standard Specification for
Classification of Coals by Rank \1\'' (incorporated by reference, see
Sec. 63.14(b)), coal refuse, and petroleum coke. Synthetic fuels
derived from coal for the purpose of creating useful heat including but
not limited to, solvent-refined coal, coal-oil mixtures, and coal-water
mixtures, for the purposes of this subpart. Coal derived gases are
excluded from this definition.
Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and
a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
Commercial/institutional boiler means a boiler used in commercial
establishments or institutional establishments such as medical centers,
research centers, institutions of higher education, hotels, and
laundries to provide electricity, steam, and/or hot water.
Construction/demolition material means waste building material that
result from the construction or demolition operations on houses and
commercial and industrial buildings.
Deviation. (1) Deviation means any instance in which an affected
source subject to this subpart, or an owner or operator of such a
source:
(i) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
(ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(iii) Fails to meet any emission limit, operating limit, or work
practice standard in this subpart during startup, shutdown, or
malfunction, regardless or whether or not such failure is permitted by
this subpart.
(2) A deviation is not always a violation. The determination of
whether a deviation constitutes a violation of the
[[Page 55268]]
standard is up to the discretion of the entity responsible for
enforcement of the standards.
Distillate oil means fuel oils, including recycled oils, that
comply with the specifications for fuel oil numbers 1 and 2, as defined
by the American Society for Testing and Materials in ASTM D396-02a,
``Standard Specifications for Fuel Oils 1'' (incorporated by
reference, see Sec. 63.14(b)).
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material. Sorbent injection systems
in fluidized bed boilers and process heaters are included in this
definition.
Electric utility steam generating unit means a fossil fuel-fired
combustion unit of more than 25 megawatts that serves a generator that
produces electricity for sale. A fossil fuel-fired unit that
cogenerates steam and electricity and supplies more than one-third of
its potential electric output capacity and more than 25 megawatts
electrical output to any utility power distribution system for sale is
considered an electric utility steam generating unit.
Electrostatic precipitator means an add-on air pollution control
device used to capture particulate matter by charging the particles
using an electrostatic field, collecting the particles using a grounded
collecting surface, and transporting the particles into a hopper.
Fabric filter means an add-on air pollution control device used to
capture particulate matter by filtering gas streams through filter
media, also known as a baghouse.
Federally enforceable means all limitations and conditions that are
enforceable by the EPA Administrator, including the requirements of 40
CFR parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
Firetube boiler means a boiler in which hot gases of combustion
pass through the tubes and water contacts the outside surfaces of the
tubes.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials.
Fuel type means each category of fuels that share a common name or
classification. Examples include, but are not limited to, bituminous
coal, subbituminous coal, lignite, anthracite, biomass, construction/
demolition material, salt water laden wood, creosote treated wood,
tires, residual oil. Individual fuel types received from different
suppliers are not considered new fuel types except for construction/
demolition material.
Gaseous fuel includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast
furnace gas is exempted from this definition.
Heat input means heat derived from combustion of fuel in a boiler
or process heater and does not include the heat input from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources such as gas turbines, internal combustion engines, kilns, etc.
Hot water heater means a closed vessel with a capacity of no more
than 120 U.S. gallons in which water is heated by combustion of gaseous
or liquid fuel and is withdrawn for use external to the vessel at
pressures not exceeding 160 psig, including the apparatus by which the
heat is generated and all controls and devices necessary to prevent
water temperatures from exceeding 210[deg]F (99[deg]C).
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam, hot water,
and/or electricity.
Large gaseous fuel subcategory includes any watertube boiler or
process heater that burns gaseous fuels not combined with any solid
fuels, burns liquid fuel only during periods of gas curtailment or gas
supply emergencies, has a rated capacity of greater than 10 MMBtu per
hour heat input, and has an annual capacity factor of greater than 10
percent.
Large liquid fuel subcategory includes any watertube boiler or
process heater that does not burn any solid fuel and burns any liquid
fuel either alone or in combination with gaseous fuels, has a rated
capacity of greater than 10 MMBtu per hour heat input, and has an
annual capacity factor of greater than 10 percent. Large gaseous fuel
boilers and process heaters that burn liquid fuel during periods of gas
curtailment or gas supply emergencies are not included in this
definition.
Large solid fuel subcategory includes any watertube boiler or
process heater that burns any amount of solid fuel either alone or in
combination with liquid or gaseous fuels, has a rated capacity of
greater than 10 MMBtu per hour heat input, and has an annual capacity
factor of greater than 10 percent.
Limited use gaseous fuel subcategory includes any watertube boiler
or process heater that burns gaseous fuels not combined with any liquid
or solid fuels, burns liquid fuel only during periods of gas
curtailment or gas supply emergencies, has a rated capacity of greater
than 10 MMBtu per hour heat input, and has a federally enforceable
annual average capacity factor of equal to or less than 10 percent.
Limited use liquid fuel subcategory includes any watertube boiler
or process heater that does not burn any solid fuel and burns any
liquid fuel either alone or in combination with gaseous fuels, has a
rated capacity of greater than 10 MMBtu per hour heat input, and has a
federally enforceable annual average capacity factor of equal to or
less than 10 percent. Limited use gaseous fuel boilers and process
heaters that burn liquid fuel during periods of gas curtailment or gas
supply emergencies are not included in this definition.
Limited use solid fuel subcategory includes any watertube boiler or
process heater that burns any amount of solid fuel either alone or in
combination with liquid or gaseous fuels, has a rated capacity of
greater than 10 MMBtu per hour heat input, and has a federally
enforceable annual average capacity factor of equal to or less than 10
percent.
Liquid fossil fuel means petroleum, distillate oil, residual oil
and any form of liquid fuel derived from such material.
Liquid fuel includes, but is not limited to, distillate oil,
residual oil, waste oil, and process liquids.
Minimum pressure drop means 90 percent of the lowest test-run
average pressure drop measured according to Table 7 to this subpart
during the most recent performance test demonstrating compliance with
the applicable emission limit.
Minimum scrubber effluent pH means 90 percent of the lowest test-
run average effluent pH measured at the outlet of the wet scrubber
according to Table 7 to this subpart during the most recent performance
test demonstrating compliance with the applicable hydrogen chloride
emission limit.
Minimum scrubber flow rate means 90 percent of the lowest test-run
average flow rate measured according to Table 7 to this subpart during
the most recent performance test demonstrating compliance with the
applicable emission limit.
Minimum sorbent flow rate means 90 percent of the lowest test-run
average sorbent (or activated carbon) flow rate measured according to
Table 7 to this subpart during the most recent performance test
demonstrating compliance with the applicable emission limits.
[[Page 55269]]
Minimum voltage or amperage means 90 percent of the lowest test-run
average voltage or amperage to the electrostatic precipitator measured
according to Table 7 to this subpart during the most recent performance
test demonstrating compliance with the applicable emission limits.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society for
Testing and Materials in ASTM D1835-03a, ``Standard Specification for
Liquid Petroleum Gases'' (incorporated by reference, see Sec.
63.14(b)).
Opacity means the degree to which emissions reduce the transmission
of light and obscure the view of an object in the background.
Particulate matter means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an alternative method.
Period of natural gas curtailment or supply interruption means a
period of time during which the supply of natural gas to an affected
facility is halted for reasons beyond the control of the facility. An
increase in the cost or unit price of natural gas does not constitute a
period of natural gas curtailment or supply interruption.
Process heater means an enclosed device using controlled flame,
that is not a boiler, and the unit's primary purpose is to transfer
heat indirectly to a process material (liquid, gas, or solid) or to a
heat transfer material for use in a process unit, instead of generating
steam. Process heaters are devices in which the combustion gases do not
directly come into contact with process materials. Process heaters do
not include units used for comfort heat or space heat, food preparation
for on-site consumption, or autoclaves.
Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6,
as defined by the American Society for Testing and Materials in ASTM
D396-02a, ``Standard Specifications for Fuel Oils 1''
(incorporated by reference, see Sec. 63.14(b)).
Responsible official means responsible official as defined in 40
CFR 70.2.
Small gaseous fuel subcategory includes any firetube boiler that
burns gaseous fuels not combined with any solid fuels and burns liquid
fuel only during periods of gas curtailment or gas supply emergencies,
and any boiler or process heater that burns gaseous fuels not combined
with any solid fuels, burns liquid fuel only during periods of gas
curtailment or gas supply emergencies, and has a rated capacity of less
than or equal to 10 MMBtu per hour heat input.
Small liquid fuel subcategory includes any firetube boiler that
does not burn any solid fuel and burns any liquid fuel either alone or
in combination with gaseous fuels, and any boiler or process heater
that does not burn any solid fuel and burns any liquid fuel either
alone or in combination with gaseous fuels, and has a rated capacity of
less than or equal to 10 MMBtu per hour heat input. Small gaseous fuel
boilers and process heaters that burn liquid fuel during periods of gas
curtailment or gas supply emergencies are not included in this
definition.
Small solid fuel subcategory includes any firetube boiler that
burns any amount of solid fuel either alone or in combination with
liquid or gaseous fuels, and any other boiler or process heater that
burns any amount of solid fuel either alone or in combination with
liquid or gaseous fuels and has a rated capacity of less than or equal
to 10 MMBtu per hour heat input.
Solid fuel includes, but is not limited to, coal, wood, biomass,
tires, plastics, and other nonfossil solid materials.
Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another. A temporary boiler that remains at a location for
more than 180 consecutive days is no longer considered to be a
temporary boiler. Any temporary boiler that replaces a temporary boiler
at a location and is intended to perform the same or similar function
will be included in calculating the consecutive time period.
Total selected metals means the combination of the following
metallic HAP: arsenic, beryllium, cadmium, chromium, lead, manganese,
nickel and selenium.
Unadulterated wood means wood or wood products that have not been
painted, pigment-stained, or pressure treated with compounds such as
chromate copper arsenate, pentachlorophenol, and creosote. Plywood,
particle board, oriented strand board, and other types of wood products
bound by glues and resins are included in this definition.
Waste heat boiler means a device that recovers normally unused
energy and converts it to usable heat. Waste heat boilers incorporating
duct or supplemental burners that are designed to supply 50 percent or
more of the total rated heat input capacity of the waste heat boiler
are not considered waste heat boilers, but are considered boilers.
Waste heat boilers are also referred to as heat recovery steam
generators.
Watertube boiler means a boiler in which water passes through the
tubes and hot gases of combustion pass over the outside surfaces of the
tubes.
Wet scrubber means any add-on air pollution control device that
mixes an aqueous stream or slurry with the exhaust gases from a boiler
or process heater to control emissions of particulate matter and/or to
absorb and neutralize acid gases, such as hydrogen chloride.
Work practice standard means any design, equipment, work practice,
or operational standard, or combination thereof, that is promulgated
pursuant to section 112(h) of the CAA.
Tables to Subpart DDDDD of Part 63
Table 1 to Subpart DDDDD of Part 63.--Emission Limits and Work Practice
Standards
As stated in Sec. 63.7500, you must comply with the following
applicable emission limits and work practice standards:
------------------------------------------------------------------------
You must meet the
If your boiler or process following emission
heater is in this For the following limits and work
subcategory . . . pollutants . . . practice standards .
. .
------------------------------------------------------------------------
1. New or reconstructed a. Particulate 0.025 lb per MMBtu
large solid fuel. Matter (or Total of heat input; or
Selected Metals). (0.0003 lb per
MMBtu of heat
input).
b. Hydrogen Chloride 0.02 lb per MMBtu of
heat input.
c. Mercury.......... 0.000003 lb per
MMBtu of heat
input.
d. Carbon Monoxide.. 400 ppm by volume on
a dry basis
corrected to 7
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-
run average for
units less than 100
MMBtu/hr).
[[Page 55270]]
2. New or reconstructed a. Particulate 0.025 lb per MMBtu
limited use solid fuel. Matter (or Total of heat input; or
Selected Metals). (0.0003 lb per
MMBtu of heat
input).
b. Hydrogen Chloride 0.02 lb per MMBtu of
heat input.
c. Mercury.......... 0.000003 lb per
MMBtu of heat
input.
d. Carbon Monoxide.. 400 ppm by volume on
a dry basis
corrected to 7
percent oxygen (3-
run average).
3. New or reconstructed a. Particulate 0.025 lb per MMBtu
small solid fuel. Matter (or Total of heat input; or
Selected Metals). (0.0003 lb per
MMBtu of heat
input).
b. Hydrogen Chloride 0.02 lb per MMBtu of
heat input.
c. Mercury.......... 0.000003 lb per
MMBtu of heat
input.
4. New reconstructed large a. Particulate 0.03 lb per MMBtu of
liquid fuel. Matter. heat input.
b. Hydrogen Chloride 0.0005 lb per MMBtu
of heat input.
c. Carbon Monoxide.. 400 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-
run average for
units less than 100
MMBtu/hr).
5. New or reconstructed a. Particulate 0.03 lb per MMBtu of
limited use liquid fuel. Matter. heat input.
b. Hydrogen Chloride 0.0009 lb per MMBtu
of heat input.
c. Carbon Monoxide.. 400 ppm by volume on
a dry basis liquid
corrected to 3
percent oxygen (3-
run average).
6. New or reconstructed a. Particulate 0.03 lb per MMBtu of
small liquid fuel. Matter. heat input.
b. Hydrogen Chloride 0.0009 lb per MMBtu
of heat input.
7. New reconstructed large Carbon Monoxide..... 400 ppm by volume on
gaseous fuel. a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-
run average for
units less than 100
MMBtu/hr).
8. New or reconstructed Carbon Monoxide..... 400 ppm by volume on
limited use gaseous fuel. a dry basis
corrected to 3
percent oxygen (3-
run average).
9. Existing large solid fuel a. Particulate 0.07 lb per MMBtu of
Matter (or Total heat input; or
Selected Metals). (0.001 lb per MMBtu
of heat input).
b. Hydrogen Chloride 0.09 lb per MMBtu of
heat input.
c. Mercury.......... 0.000009 lb per
MMBtu of heat
input.
10. Existing limited use Particulate Matter 0.21 lb per MMBtu of
solid fuel. (or Total Selected heat input; or
Metals). (0.004 lb per MMBtu
of heat input).
------------------------------------------------------------------------
Table 2 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
Process Heaters With Particulate Matter Emission Limits
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
------------------------------------------------------------------------
If you demonstrate compliance with
applicable particulate matter You must meet these operating
emission limits using . . . limits . . .
------------------------------------------------------------------------
1. Wet scrubber control............ a. Maintain the minimum pressure
drop and liquid flow-rate at or
above the operating levels
established during the performance
test according to Sec.
63.7530(c) and Table 7 to this
subpart that demonstrated
compliance with the applicable
emission limit for particulate
matter.
2. Fabric filter control........... a. Install and operate a bag leak
detection system according to Sec.
63.7525 and operate the fabric
filter such that the bag leak
detection system alarm does not
sound more than 5 percent of the
operating time during each 6-month
period; or
b. This option is for boilers and
process heaters that operate dry
control systems. Existing boilers
and process heaters must maintain
opacity to less than or equal to
20 percent (6-minute average)
except for one 6-minute period per
hour of not more than 27 percent.
New boilers and process heaters
must maintain opacity to less than
or equal to 10 percent opacity (1-
hour block average).
3. Electrostatic precipitator a. This option is for boilers and
control. process heaters that operate dry
control systems. Existing boilers
and process heaters must maintain
opacity to less than or equal to
20 percent (6-minute average)
except for one 6-minute period per
hour of not more than 27 percent.
New boilers and process heaters
must maintain opacity to less than
or equal to 10 percent opacity (1-
hour block average); or
[[Page 55271]]
b. This option is only for boilers
and process heaters that operate
additional wet control systems.
Maintain the minimum voltage and
secondary current or total power
input of the electrostatic
precipitator at or above the
operating limits established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limit for
particulate matter.
4. Any other control type.......... This option is for boilers and
process heaters that operate dry
control systems. Existing boilers
and process heaters must maintain
opacity to less than or equal to
20 percent (6-minute average)
except for one 6-minute period per
hour of not more than 27 percent.
New boilers and process heaters
must maintain opacity to less than
or equal to 10 percent opacity (1-
hour block average).
------------------------------------------------------------------------
Table 3 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
Process Heaters With Mercury Emission Limits and Boilers and Process
Heaters That Choose To Comply With the Alternative Total Selected Metals
Emission Limits
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
------------------------------------------------------------------------
If you demonstrate compliance with
applicable mercury and/or total You must meet these operating
selected metals emission limits limits . . .
using . . .
------------------------------------------------------------------------
1. Wet scrubber control............ Maintain the minimum pressure drop
and liquid flow-rate at or above
the operating levels established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limits for
mercury and/or total selected
metals.
2. Fabric filter control........... a. Install and operate a bag leak
detection system according to Sec.
63.7525 and operate the fabric
filter such that the bag leak
detection system alarm does not
sound more than 5 percent of the
operating time during a 6-month
period; or
b. This option is for boilers and
process heaters that operate dry
control systems. Existing sources
must maintain opacity to less than
or equal to 20 percent (6-minute
average) except for one 6-minute
period per hour of not more than
27 percent. New sources must
maintain opacity to less than or
equal to 10 percent opacity (1-
hour block average).
3. Electrostatic precipitator a. This option is for boilers and
control. process heaters that operate dry
control systems. Existing sources
must maintain opacity to less than
or equal to 20 percent (6-minute
average) except for one 6-minute
period per hour of not more than
27 percent. New sources must
maintain opacity to less than or
equal to 10 percent opacity (1-
hour block average); or
b. This option is only for boilers
and process heaters that operate
additional wet control systems.
Maintain the minimum voltage and
secondary current or total power
input of the electrostatic
precipitator at or above the
operating limits established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limits for
mercury and/or total selected
metals.
4. Dry scrubber or carbon injection Maintain the minimum sorbent or
control. carbon injection rate at or above
the operating levels established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limit for
mercury.
5. Any other control type.......... This option is only for boilers and
process heaters that operate dry
control systems. Existing sources
must maintain opacity to less than
or equal to 20 percent (6-minute
average) except for one 6-minute
period per hour of not more than
27 percent. New sources must
maintain opacity to less than or
equal to 10 percent opacity (1-
hour block average).
6. Fuel analysis................... Maintain the fuel type or fuel
mixture such that the mercury and/
or total selected metals emission
rates calculated according to Sec.
63.7530(d)(4) and/or (5) is less
than the applicable emission
limits for mercury and/or total
selected metals.
------------------------------------------------------------------------
[[Page 55272]]
Table 4 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
Process Heaters With Hydrogen Chloride Emission Limits
As stated in Sec. 63.7500, you must comply with the following
applicable operating limits:
------------------------------------------------------------------------
If you demonstrate compliance with
applicable hydrogen chloride You must meet these operating
emission limits using . . . limits . . .
------------------------------------------------------------------------
1. Wet scrubber control............ Maintain the minimum scrubber
effluent pH, pressure drop, and
liquid flow-rate at or above the
operating levels established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limit for
hydrogen chloride.
2. Dry scrubber control............ Maintain the minimum sorbent
injection rate at or above the
operating levels established
during the performance test
according to Sec. 63.7530(c) and
Table 7 to this subpart that
demonstrated compliance with the
applicable emission limit for
hydrogen chloride.
3. Fuel analysis................... Maintain the fuel type or fuel
mixture such that the hydrogen
chloride emission rate calculated
according to Sec. 63.7530(d)(3)
is less than the applicable
emission limit for hydrogen
chloride.
------------------------------------------------------------------------
Table 5 to Subpart DDDDD of Part 63.--Performance Testing Requirements
As stated in Sec. 63.7520, you must comply with the following
requirements for performance test for existing, new or reconstructed
affected sources:
------------------------------------------------------------------------
To conduct a performance
test for the following You must . . . Using . . .
pollutant . . .
------------------------------------------------------------------------
1. Particulate Matter....... a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASME PTC 19,
Part 10 (1981)
(IBR, see Sec.
63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 5 or 17
particulate matter (positive pressure
emission fabric filters must
concentration. use Method 5D) in
appendix A to part
60 of this chapter.
f. Convert emissions Method 19 F-factor
concentration to lb methodology in
per MMBtu emission appendix A to part
rates. 60 of this chapter.
2. Total selected metals.... a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASME PTC 19,
Part 10 (1981)
(IBR, see Sec.
63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the total Method 29 in
selected metals appendix A to part
emission 60 of this chapter.
concentration.
f. Convert emissions Method 19 F-factor
concentration to lb methodology in
per MMBtu emission appendix A to part
rates. 60 of this chapter.
3. Hydrogen chloride........ a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASME PTC 19,
Part 10 (1981)
(IBR, see Sec.
63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 26 or 26A in
hydrogen chloride appendix A to part
emission 60 of this chapter.
concentration.
f. Convert emissions Method 19 F-factor
concentration to lb methodology in
per MMBtu emission appendix A to part
rates. 60 of this chapter.
4. Mercury.................. a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASME PTC 19,
Part 10 (1981)
(IBR, see Sec.
62.14(i)).
[[Page 55273]]
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 29 in
mercury emission appendix A to part
concentration. 60 of this chapter
or Method 101A in
appendix B to part
61 of this chapter
or ASTM Method
D6784-02 (IBR, see
Sec. 63.14(b)).
f. Convert emissions Method 19 F-factor
concentration to lb methodology in
per MMBtu emission appendix A to part
rates. 60 of this chapter.
5. Carbon Monoxide.......... a. Select the Method 1 in appendix
sampling ports A to part 60 of
location and the this chapter.
number of traverse
points.
b. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASTM D6522-00
(IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part 10
(1981) (IBR, see
Sec. 63.14(i)).
c. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
d. Measure the Method 10, 10A, or
carbon monoxide 10B in appendix A
emission to part 60 of this
concentration. chapter, or ASTM
D6522-00 (IBR, see
Sec. 63.14(b))
when the fuel is
natural gas.
------------------------------------------------------------------------
Table 6 to Subpart DDDDD of Part 63.--Fuel Analysis Requirements
As stated in Sec. 63.7521, you must comply with the following
requirements for fuel analysis testing for existing, new or
reconstructed affected sources:
------------------------------------------------------------------------
To conduct a fuel analysis
for the following pollutant You must . . . Using . . .
. . .
------------------------------------------------------------------------
1. Mercury.................. a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D2234-00 \1\ (for
coal)(IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003)(for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or
samples. SW-846-3020A (for
liquid samples) or
ASTM D2013-01 (for
coal) (IBR, see
Sec. 63.14(b)) or
ASTM D5198-92
(2003) (for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
d. Determine heat ASTM D5865-03a (for
content of the fuel coal)(IBR, see Sec.
type. 63.14(b)) or ASTM
E711-87 (1996) (for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
e. Determine ASTM D3173-02 (IBR,
moisture content of see Sec.
the fuel type. 63.14(b)) or ASTM
E871-82 (1998)(IBR,
see Sec.
63.14(b)) or
equivalent.
f. Measure mercury ASTM D3684-01 (for
concentration in coal)(IBR, see Sec.
fuel sample. 63.14(b)) or SW-
846-7471A (for
solid samples) or
SW-846 7470A (for
liquid samples).
g. Convert
concentrations into
units of pounds of
pollutant per MMBtu
of heat content.
2. Total selected metals.... a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D2234-00 \1\ (for
coal)(IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003)
(for biomass)(IBR,
see Sec.
63.14(b)) or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or
samples. SW-846-3020A (for
liquid samples) or
ASTM D2013-01 (for
coal)(IBR, see Sec.
63.14(b)) or ASTM
D5198-92 (2003)(for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
d. Determine heat ASTM D5865-03a (for
content of the fuel coal)(IBR, see Sec.
type. 63.14(b)) or ASTM
E 711-87 (for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
e. Determine ASTM D3173-02 (IBR,
moisture content of see Sec.
the fuel type. 63.14(b)) or ASTM
E871 (IBR, see Sec.
63.14(b)) or
equivalent.
[[Page 55274]]
f. Measure total SW-846-6010B or ASTM
selected metals D3683-94 (2000)
concentration in (for coal) (IBR,
fuel sample. see Sec.
63.14(b)) or ASTM
E885-88 (1996) (for
biomass)(IBR, see
Sec. 63.14(b)).
g. Convert
concentrations into
units of pounds of
pollutant per MMBtu
of heat content.
3. Hydrogen chloride........ a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D2234 \1\ (for
coal)(IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003)
(for biomass)(IBR,
see Sec.
63.14(b)) or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or
samples. SW-846-3020A (for
liquid samples) or
ASTM D2013-01 (for
coal)(IBR, see Sec.
63.14(b)) or ASTM
D5198-92 (2003)
(for biomass)(IBR,
see Sec.
63.14(b)) or
equivalent.
d. Determine heat ASTM D5865-03a (for
content of the fuel coal)(IBR, see Sec.
type. 63.14(b)) or ASTM
E711-87 (1996) (for
biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
e. Determine ASTM D3173-02 (IBR,
moisture content of see Sec.
the fuel type. 63.14(b)) or ASTM
E871-82 (1998)(IBR,
see Sec.
63.14(b)) or
equivalent.
f. Measure chlorine SW-846-9250 or ASTM
concentration in E776-87 (1996) (for
fuel sample. biomass)(IBR, see
Sec. 63.14(b)) or
equivalent.
g. Convert
concentrations into
units of pounds of
pollutant per MMBtu
of heat content.
------------------------------------------------------------------------
Table 7 to Subpart DDDDD of Part 63.--Establishing Operating Limits
As stated in Sec. 63.7520, you must comply with the following requirements for establishing operating limits:
--------------------------------------------------------------------------------------------------------------------------------------------------------
If you have an applicable emission And your operating limits According to the following
limit for . . . are based on . . . You must . . . Using . . . requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Particulate matter, mercury, or a. Wet scrubber operating i. Establish a site- (1) Data from the pressure (a) You must collect
total selected metals. parameters. specific minimum pressure drop and liquid flow rate pressure drop and liquid
drop and minimum flow rate monitors and the flow-rate data every 15
operating limit according particulate matter, minutes during the entire
to Sec. 63.7530(c). mercury, or total selected period of the performance
metals performance test. tests;
(b) Determine the average
pressure drop and liquid
flow-rate for each
individual test run in the
three-run performance test
by computing the average
of all the 15-minute
readings taken during each
test run.
b. Electrostatic i. Establish a site- (1) Data from the pressure (a) You must collect
precipitator operating specific minimum voltage drop and liquid flow rate voltage and secondary
parameters (option only and secondary current or monitors and the current or total power
for units with additional total power input particulate matter, input data every 15
wet scrubber control). according to Sec. mercury, or total selected minutes during the entire
63.7530(c). metals performance test. period of the performance
tests;
(b) Determine the average
voltage and secondary
current or total power
input for each individual
test run in the three-run
performance test by
computing the average of
all the 15-minute readings
taken during each test
run.
[[Page 55275]]
2. Hydrogen Chloride................ a. Wet scrubber operating i. Establish a site- (1) Data from the pH, (a) You must collect pH,
parameters. specific minimum pressure pressure drop, and liquid pressure drop, and liquid
drop and minimum flow rate flow-rate monitors and the flow-rate data every 15
operating limit according hydrogen chloride minutes during the entire
to Sec. 63.7530(c). performance test. period of the performance
tests;
(b) Determine the average
pH, pressure drop, and
liquid flow-rate for each
individual test run in the
three-run performance test
by computing the average
of all the 15-minute
readings taken during each
test run.
b. Dry scrubber operating i. Establish a site- (1) Data from the sorbent (a) You must collect
parameters. specific minimum sorbent injection rate monitors sorbent injection rate
injection rate operating and hydrogen chloride data every 15 minutes
limit according to Sec. performance test. during the entire period
63.7530(c). of the performance tests;
(b) Determine the average
sorbent injection rate for
each individual test run
in the three-run
performance test by
computing the average of
all the 15-minute readings
taken during each test
run.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 8 to Subpart DDDDD of Part 63.--Demonstrating Continuous
Compliance
As stated in Sec. 63.7540, you must show continuous compliance with
the emission limitations for affected sources according to the
following:
------------------------------------------------------------------------
If you must meet the following
operating limits or work practice You must demonstrate continuous
standards . . . compliance by . . .
------------------------------------------------------------------------
1. Opacity......................... a. Collecting the opacity
monitoring system data according
to Sec. Sec. 63.7525(b) and
63.7535; and
b. Reducing the opacity monitoring
data to 6-minute averages; and
c. Maintaining opacity to less than
or equal to 20 percent (6-minute
average) except for one 6-minute
period per hour of not more than
27 percent for existing sources;
or maintaining opacity to less
than or equal to 10 percent (1-
hour block average) for new
sources.
2. Fabric Filter Bag Leak Detection Installing and operating a bag leak
Operation. detection system according to Sec.
63.7525 and operating the fabric
filter such that the requirements
in Sec. 63.7540(a)(9) are met.
3. Wet Scrubber Pressure Drop and a. Collecting the pressure drop and
Liquid Flow-rate. liquid flow rate monitoring system
data according to Sec. Sec.
63.7525 and 63.7535; and
b. Reducing the data to 3-hour
block averages; and
c. Maintaining the 3-hour average
pressure drop and liquid flow-rate
at or above the operating limits
established during the performance
test according to Sec.
63.7530(c).
4. Wet Scrubber pH................. a. Collecting the pH monitoring
system data according to Sec.
Sec. 63.7525 and 63.7535; and
b. Reducing the data to 3-hour
block averages; and
c. Maintaining the 3-hour average
pH at or above the operating limit
established during the performance
test according to Sec.
63.7530(c).
5. Dry Scrubber Sorbent or Carbon a. Collecting the sorbent or carbon
Injection Rate. injection rate monitoring system
data for the dry scrubber
according to Sec. Sec. 63.7525
and 63.7535; and
b. Reducing the data to 3-hour
block averages; and
c. Maintaining the 3-hour average
sorbent or carbon injection rate
at or above the operating limit
established during the performance
test according to Sec. Sec.
63.7530(c).
6. Electrostatic Precipitator a. Collecting the secondary current
Secondary Current and Voltage or and voltage or total power input
Total Power Input. monitoring system data for the
electrostatic precipitator
according to Sec. Sec. 63.7525
and 63.7535; and
b. Reducing the data to 3-hour
block averages; and
[[Page 55276]]
c. Maintaining the 3-hour average
secondary current and voltage or
total power input at or above the
operating limits established
during the performance test
according to Sec. Sec.
63.7530(c).
7. Fuel Pollutant Content.......... a. Only burning the fuel types and
fuel mixtures used to demonstrate
compliance with the applicable
emission limit according to Sec.
63.7530(c) or (d) as applicable;
and
b. Keeping monthly records of fuel
use according to Sec.
63.7540(a).
------------------------------------------------------------------------
Table 9 to Subpart DDDDD of Part 63.--Reporting Requirements
As stated in Sec. 63.7550, you must comply with the following
requirements for reports:
------------------------------------------------------------------------
The report must You must submit the
You must submit a(n) contain . . . report . . .
------------------------------------------------------------------------
1. Compliance report........ a. Information Semiannually
required in Sec. according to the
63.7550(c)(1) requirements in
through (11); and Sec. 63.7550(b).
b. If there are no
deviations from any
emission limitation
(emission limit and
operating limit)
that applies to you
and there are no
deviations from the
requirements for
work practice
standards in Table
8 to this subpart
that apply to you,
a statement that
there were no
deviations from the
emission
limitations and
work practice
standards during
the reporting
period. If there
were no periods
during which the
CMSs, including
continuous
emissions
monitoring system,
continuous opacity
monitoring system,
and operating
parameter
monitoring systems,
were out-of-control
as specified in
Sec. 63.8(c)(7),
a statement that
there were no
periods during
which the CMSs were
out-of-control
during the
reporting period;
and
c. If you have a
deviation from any
emission limitation
(emission limit and
operating limit) or
work practice
standard during the
reporting period,
the report must
contain the
information in Sec.
63.7550(d). If
there were periods
during which the
CMSs, including
continuous
emissions
monitoring system,
continuous opacity
monitoring system,
and operating
parameter
monitoring systems,
were out-of-
control, as
specified in Sec.
63.8(c)(7), the
report must contain
the information in
Sec. 63.7550(e);
and
d. If you had a
startup, shutdown,
or malfunction
during the
reporting period
and you took
actions consistent
with your startup,
shutdown, and
malfunction plan,
the compliance
report must include
the information in
Sec.
63.10(d)(5)(i)
2. An immediate startup, a. Actions taken for i. By fax or
shutdown, and malfunction the event; and telephone within 2
report if you had a working days after
startup, shutdown, or starting actions
malfunction during the inconsistent with
reporting period that is the plan; and
not consistent with your
startup, shutdown, and
malfunction plan, and the
source exceeds any
applicable emission
limitation in the relevant
emission standard.
b. The information ii. By letter within
in Sec. 7 working days
63.10(d)(5)(ii) after the end of
the event unless
you have made
alternative
arrangements with
the permitting
authority.
------------------------------------------------------------------------
[[Page 55277]]
Table 10 to Subpart DDDDD of Part 63.--Applicability of General Provisions to Subpart DDDDD
As stated in Sec. 63.7565, you must comply with the applicable General Provisions according to the following:
----------------------------------------------------------------------------------------------------------------
Citation Subject Brief description Applicable
----------------------------------------------------------------------------------------------------------------
Sec. 63.1........................ Applicability............. Initial Applicability Yes.
Determination;
Applicability After
Standard Established;
Permit Requirements;
Extensions, Notifications.
Sec. 63.2........................ Definitions............... Definitions for part 63 Yes.
standards.
Sec. 63.3........................ Units and Abbreviations... Units and abbreviations Yes.
for part 63 standards.
Sec. 63.4........................ Prohibited Activities..... Prohibited Activities; Yes.
Compliance date;
Circumvention,
Severability.
Sec. 63.5........................ Construction/ Applicability; Yes.
Reconstruction. applications; approvals.
Sec. 63.6(a)..................... Applicability............. GP apply unless compliance Yes.
extension; and GP apply
to area sources that
become major.
Sec. 63.6(b)(1)-(4).............. Compliance Dates for New Standards apply at Yes.
and Reconstructed sources. effective date; 3 years
after effective date;
upon startup; 10 years
after construction or
reconstruction commences
for 112(f).
Sec. 63.6(b)(5).................. Notification.............. Must notify if commenced Yes.
construction or
reconstruction after
proposal.
Sec. 63.6(b)(6).................. [Reserved].
Sec. 63.6(b)(7).................. Compliance Dates for New Area sources that become Yes.
and Reconstructed Area major must comply with
Sources That Become Major. major source standards
immediately upon becoming
major, regardless of
whether required to
comply when they were an
area source.
Sec. 63.6(c)(1)-(2).............. Compliance Dates for Comply according to date Yes.
Existing Sources. in subpart, which must be
no later than 3 years
after effective date; and
for 112(f) standards,
comply within 90 days of
effective date unless
compliance extension.
Sec. 63.6(c)(3)-(4).............. [Reserved].
Sec. 63.6(c)(5).................. Compliance Dates for Area sources that become Yes.
Existing Area Sources major must comply with
That Become Major. major source standards by
date indicated in subpart
or by equivalent time
period (for example, 3
years).
Sec. 63.6(d)..................... [Reserved].
Sec. 63.6(e)(1)-(2).............. Operation & Maintenance... Operate to minimize Yes.
emissions at all times;
and Correct malfunctions
as soon as practicable;
and Operation and
maintenance requirements
independently
enforceable; information
Administrator will use to
determine if operation
and maintenance
requirements were met.
Sec. 63.6(e)(3).................. Startup, Shutdown, and Requirement for SSM and Yes.
Malfunction Plan (SSMP). startup, shutdown,
malfunction plan; and
content of SSMP.
Sec. 63.6(f)(1).................. Compliance Except During Comply with emission Yes.
SSM. standards at all times
except during SSM.
Sec. 63.6(f)(2)-(3).............. Methods for Determining Compliance based on Yes.
Compliance. performance test,
operation and maintenance
plans, records,
inspection.
Sec. 63.6(g)(1)-(3).............. Alternative Standard...... Procedures for getting an Yes.
alternative standard.
Sec. 63.6(h)(1).................. Compliance with Opacity/VE Comply with opacity/VE Yes.
Standards. emission limitations at
all times except during
SSM.
Sec. 63.6(h)(2)(i)............... Determining Compliance If standard does not state No.
with Opacity/Visible test method, use Method 9
Emission (VE) Standards. for opacity and Method 22
for VE.
Sec. 63.6(h)(2)(ii).............. [Reserved].
Sec. 63.6(h)(2)(iii)............. Using Previous Tests to Criteria for when previous Yes.
Demonstrate Compliance opacity/VE testing can be
with Opacity/VE Standards used to show compliance
with this subpart.
Sec. 63.6(h)(3).................. [Reserved].
Sec. 63.6(h)(4).................. Notification of Opacity/VE Notify Administrator of No.
Observation Date. anticipated date of
observation.
Sec. 63.6(h)(5)(i),(iii)-(v)..... Conducting Opacity/VE Dates and Schedule for No.
Observations. conducting opacity/VE
observations.
[[Page 55278]]
Sec. 63.6(h)(5)(ii).............. Opacity Test Duration and Must have at least 3 hours No.
Averaging Times. of observation with
thirty, 6-minute averages.
Sec. 63.6(h)(6).................. Records of Conditions Keep records available and No.
During Opacity/VE allow Administrator to
observations. inspect.
Sec. 63.6(h)(7)(i)............... Report continuous opacity Submit continuous opacity Yes.
monitoring system monitoring system data
Monitoring Data from with other performance
Performance Test. test data.
Sec. 63.6(h)(7)(ii).............. Using continuous opacity Can submit continuous No.
monitoring system instead opacity monitoring system
of Method 9. data instead of Method 9
results even if subpart
requires Method 9, but
must notify Administrator
before performance test.
Sec. 63.6(h)(7)(iii)............. Averaging time for To determine compliance, Yes.
continuous opacity must reduce continuous
monitoring system during opacity monitoring system
performance test. data to 6-minute averages.
Sec. 63.6(h)(7)(iv).............. Continuous opacity Demonstrate that Yes.
monitoring system continuous opacity
requirements. monitoring system
performance evaluations
are conducted according
to Sec. Sec. 63.8(e),
continuous opacity
monitoring systems are
properly maintained and
operated according to
Sec. 63.8(c) and data
quality as Sec. 63.8(d).
Sec. 63.6(h)(7)(v)............... Determining Compliance Continuous opacity Yes.
with Opacity/VE Standards. monitoring system is
probative but not
conclusive evidence of
compliance with opacity
standard, even if Method
9 observation shows
otherwise. Requirements
for continuous opacity
monitoring system to be
probative evidence-proper
maintenance, meeting PS
1, and data have not been
altered.
Sec. 63.6(h)(8).................. Determining Compliance Administrator will use all Yes.
with Opacity/VE Standards. continuous opacity
monitoring system, Method
9, and Method 22 results,
as well as information
about operation and
maintenance to determine
compliance.
Sec. 63.6(h)(9).................. Adjusted Opacity Standard. Procedures for Yes.
Administrator to adjust
an opacity standard.
Sec. 63.6(i)(1)-(14)............. Compliance Extension...... Procedures and criteria Yes.
for Administrator to
grant compliance
extension.
Sec. 63.6(j)..................... Presidential Compliance President may exempt Yes.
Exemption. source category from
requirement to comply
with rule.
Sec. 63.7(a)(1).................. Performance Test Dates.... Dates for Conducting Yes.
Initial Performance
Testing and Other
Compliance Demonstrations.
Sec. 63.7(a)(2).................. Performance Test Dates.... New source with initial Yes.
startup date before
effective date has 180
days after effective date
to demonstrate compliance
Sec. 63.7(a)(2)(ii-viii)......... [Reserved].
Sec. 63.7(a)(2)(ix).............. Performance Test Dates.... 1. New source that Yes.
commenced construction
between proposal and
promulgation dates, when
promulgated standard is
more stringent than
proposed standard, has
180 days after effective
date or 180 days after
startup of source,
whichever is later, to
demonstrate compliance;
and.
2. If source initially No.
demonstrates compliance
with less stringent
proposed standard, it has
3 years and 180 days
after the effective date
of the standard or 180
days after startup of
source, whichever is
later, to demonstrate
compliance with
promulgated standard.
Sec. 63.7(a)(3).................. Section 114 Authority..... Administrator may require Yes.
a performance test under
CAA Section 114 at any
time.
[[Page 55279]]
Sec. 63.7(b)(1).................. Notification of Must notify Administrator No.
Performance Test. 60 days before the test.
Sec. 63.7(b)(2).................. Notification of If rescheduling a Yes.
Rescheduling. performance test is
necessary, must notify
Administrator 5 days
before scheduled date of
rescheduled date.
Sec. 63.7(c)..................... Quality Assurance/Test Requirement to submit site- Yes.
Plan. specific test plan 60
days before the test or
on date Administrator
agrees with: test plan
approval procedures; and
performance audit
requirements; and
internal and external QA
procedures for testing.
Sec. 63.7(d)..................... Testing Facilities........ Requirements for testing Yes.
facilities.
Sec. 63.7(e)(1).................. Conditions for Conducting 1. Performance tests must No.
Performance Tests. be conducted under
representative
conditions; and
2. Cannot conduct Yes.
performance tests during
SSM; and
3. Not a deviation to Yes.
exceed standard during
SSM; and
4. Upon request of Yes.
Administrator, make
available records
necessary to determine
conditions of performance
tests.
Sec. 63.7(e)(2).................. Conditions for Conducting Must conduct according to Yes.
Performance Tests. rule and EPA test methods
unless Administrator
approves alternative.
Sec. 63.7(e)(3).................. Test Run Duration......... Must have three separate Yes.
test runs; and Compliance
is based on arithmetic
mean of three runs; and
conditions when data from
an additional test run
can be used.
Sec. 63.7(e)(4).................. Interaction with other Nothing in Sec. Yes.
sections of the Act. 63.7(e)(1) through (4)
can abrogate the
Administrator's authority
to require testing under
Section 114 of the Act.
Sec. 63.7(f)..................... Alternative Test Method... Procedures by which Yes.
Administrator can grant
approval to use an
alternative test method.
Sec. 63.7(g)..................... Performance Test Data Must include raw data in Yes.
Analysis. performance test report;
and must submit
performance test data 60
days after end of test
with the Notification of
Compliance Status; and
keep data for 5 years.
Sec. 63.7(h)..................... Waiver of Tests........... Procedures for Yes.
Administrator to waive
performance test.
Sec. 63.8(a)(1).................. Applicability of Subject to all monitoring Yes.
Monitoring Requirements. requirements in standard.
Sec. 63.8(a)(2).................. Performance Specifications Performance Specifications Yes.
in appendix B of part 60
apply.
Sec. 63.8(a)(3).................. [Reserved].
Sec. 63.8(a)(4).................. Monitoring with Flares.... Unless your rule says No.
otherwise, the
requirements for flares
in Sec. 63.11 apply.
Sec. 63.8(b)(1)(i)-(ii)........... Monitoring................ Must conduct monitoring Yes.
according to standard
unless Administrator
approves alternative.
Sec. 63.8(b)(1)(iii)............. Monitoring................ Flares not subject to this No.
section unless otherwise
specified in relevant
standard.
Sec. 63.8(b)(2)-(3).............. Multiple Effluents and Specific requirements for Yes.
Multiple Monitoring installing monitoring
Systems. systems; and must install
on each effluent before
it is combined and before
it is released to the
atmosphere unless
Administrator approves
otherwise; and if more
than one monitoring
system on an emission
point, must report all
monitoring system
results, unless one
monitoring system is a
backup.
Sec. 63.8(c)(1).................. Monitoring System Maintain monitoring system Yes.
Operation and Maintenance. in a manner consistent
with good air pollution
control practices.
[[Page 55280]]
Sec. 63.8(c)(1)(i)............... Routine and Predictable Maintain and operate CMS Yes.
SSM. according to Sec.
63.6(e)(1).
Sec. 63.8(c)(1)(ii).............. SSM not in SSMP........... Must keep necessary parts Yes.
available for routine
repairs of CMSs.
Sec. 63.8(c)(1)(iii)............. Compliance with Operation Must develop and implement Yes.
and Maintenance an SSMP for CMSs.
Requirements.
Sec. 63.8(c)(2)-(3).............. Monitoring System Must install to get Yes.
Installation. representative emission
and parameter
measurements; and must
verify operational status
before or at performance
test.
Sec. 63.8(c)(4).................. Continuous Monitoring CMSs must be operating No.
System (CMS) Requirements. except during breakdown,
out-of-control, repair,
maintenance, and high-
level calibration drifts.
Sec. 63.8(c)(4)(i)............... Continuous Monitoring Continuous opacity Yes.
System (CMS) Requirements. monitoring system must
have a minimum of one
cycle of sampling and
analysis for each
successive 10-second
period and one cycle of
data recording for each
successive 6-minute
period.
Sec. 63.8(c)(4)(ii).............. Continuous Monitoring Continuous emissions No.
System (CMS) Requirements. monitoring system must
have a minimum of one
cycle of operation for
each successive 15-minute
period.
Sec. 63.8(c)(5).................. Continuous Opacity Must do daily zero and Yes.
Monitoring system (COMS) high level calibrations.
Requirements.
Sec. 63.8(c)(6).................. Continuous Monitoring Must do daily zero and No.
System (CMS) Requirements. high level calibrations.
Sec. 63.8(c)(7)-(8).............. Continuous Monitoring Out-of-control periods, Yes.
Systems Requirements. including reporting.
Sec. 63.8(d)..................... Continuous Monitoring Requirements for Yes.
Systems Quality Control. continuous monitoring
systems quality control,
including calibration,
etc.; and must keep
quality control plan on
record for the life of
the affected source. Keep
old versions for 5 years
after revisions.
Sec. 63.8(e)..................... Continuous monitoring Notification, performance Yes.
systems Performance evaluation test plan,
Evaluation. reports.
Sec. 63.8(f)(1)-(5).............. Alternative Monitoring Procedures for Yes.
Method. Administrator to approve
alternative monitoring.
Sec. 63.8(f)(6).................. Alternative to Relative Procedures for No.
Accuracy Test. Administrator to approve
alternative relative
accuracy tests for
continuous emissions
monitoring system.
Sec. 63.8(g)(1)-(4).............. Data Reduction............ Continuous opacity Yes.
monitoring system 6-
minute averages
calculated over at least
36 evenly spaced data
points; and continuous
emissions monitoring
system 1-hour averages
computed over at least 4
equally spaced data
points.
Sec. 63.8(g)(5).................. Data Reduction............ Data that cannot be used No.
in computing averages for
continuous emissions
monitoring system and
continuous opacity
monitoring system.
Sec. 63.9(a)..................... Notification Requirements. Applicability and State Yes.
Delegation.
Sec. 63.9(b)(1)-(5).............. Initial Notifications..... Submit notification 120 Yes.
days after effective
date; and Notification of
intent to construct/
reconstruct; and
Notification of
commencement of construct/
reconstruct; Notification
of startup; and Contents
of each.
Sec. 63.9(c)..................... Request for Compliance Can request if cannot Yes.
Extension. comply by date or if
installed BACT/LAER.
Sec. 63.9(d)..................... Notification of Special For sources that commence Yes.
Compliance Requirements construction between
for New Source. proposal and promulgation
and want to comply 3
years after effective
date.
Sec. 63.9(e)..................... Notification of Notify Administrator 60 No.
Performance Test. days prior.
[[Page 55281]]
Sec. 63.9(f)..................... Notification of VE/Opacity Notify Administrator 30 No.
Test. days prior.
Sec. 63.9(g)..................... Additional Notifications Notification of Yes.
When Using Continuous performance evaluation;
Monitoring Systems. and notification using
continuous opacity
monitoring system data;
and notification that
exceeded criterion for
relative accuracy.
Sec. 63.9(h)(1)-(6).............. Notification of Compliance Contents; and due 60 days Yes.
Status. after end of performance
test or other compliance
demonstration, and when
to submit to Federal vs.
State authority.
Sec. 63.9(i)..................... Adjustment of Submittal Procedures for Yes.
Deadlines. Administrator to approve
change in when
notifications must be
submitted.
Sec. 63.9(j)..................... Change in Previous Must submit within 15 days Yes.
Information. after the change.
Sec. 63.10(a).................... Recordkeeping/Reporting... Applies to all, unless Yes.
compliance extension; and
when to submit to Federal
vs. State authority; and
procedures for owners of
more than 1 source.
Sec. 63.10(b)(1)................. Recordkeeping/Reporting... General Requirements; and Yes.
keep all records readily
available and keep for 5
years.
Sec. 63.10(b)(2)(i)-(v).......... Records related to Occurrence of each of Yes.
Startup, Shutdown, and operation (process,
Malfunction. equipment); and
occurrence of each
malfunction of air
pollution equipment; and
maintenance of air
pollution control
equipment; and actions
during startup, shutdown,
and malfunction.
Sec. 63.10(b)(2)(vi) and (x-xi).. Continuous monitoring Malfunctions, inoperative, Yes.
systems Records. out-of-control; and
calibration checks; and
adjustments, maintenance.
Sec. 63.10(b)(2)(vii)-(ix)....... Records................... Measurements to Yes.
demonstrate compliance
with emission
limitations; and
performance test,
performance evaluation,
and visible emission
observation results; and
measurements to determine
conditions of performance
tests and performance
evaluations.
Sec. 63.10(b)(2)(xii)............ Records................... Records when under waiver. Yes.
Sec. 63.10(b)(2)(xiii)........... Records................... Records when using No.
alternative to relative
accuracy test.
Sec. 63.10(b)(2)(xiv)............ Records................... All documentation Yes.
supporting Initial
Notification and
Notification of
Compliance Status.
Sec. 63.10(b)(3)................. Records................... Applicability Yes.
Determinations.
Sec. 63.10(c)(1),(5)-(8),(10)- Records................... Additional Records for Yes.
(15). continuous monitoring
systems.
Sec. 63.10(c)(7)-(8)............. Records................... Records of excess No.
emissions and parameter
monitoring exceedances
for continuous monitoring
systems.
Sec. 63.10(d)(1)................. General Reporting Requirement to report..... Yes.
Requirements.
Sec. 63.10(d)(2)................. Report of Performance Test When to submit to Federal Yes.
Results. or State authority.
Sec. 63.10(d)(3)................. Reporting Opacity or VE What to report and when... Yes.
Observations.
Sec. 63.10(d)(4)................. Progress Reports.......... Must submit progress Yes.
reports on schedule if
under compliance
extension.
Sec. 63.10(d)(5)................. Startup, Shutdown, and Contents and submission... Yes.
Malfunction Reports.
Sec. 63.10(e)(1)(2).............. Additional continuous Must report results for Yes.
monitoring systems each CEM on a unit; and
Reports. written copy of
performance evaluation;
and 3 copies of
continuous opacity
monitoring system
performance evaluation.
Sec. 63.10(e)(3)................. Reports................... Excess Emission Reports... No.
Sec. 63.10(e)(3)(i-iii).......... Reports................... Schedule for reporting No.
excess emissions and
parameter monitor
exceedance (now defined
as deviations).
[[Page 55282]]
Sec. 63.10(e)(3)(iv-v)........... Excess Emissions Reports.. Requirement to revert to No.
quarterly submission if
there is an excess
emissions and parameter
monitor exceedance (now
defined as deviations);
and provision to request
semiannual reporting
after compliance for one
year; and submit report
by 30th day following end
of quarter or calendar
half; and if there has
not been an exceedance or
excess emission (now
defined as deviations),
report contents is a
statement that there have
been no deviations.
Sec. 63.10(e)(3)(iv-v)........... Excess Emissions Reports.. Must submit report No.
containing all of the
information in Sec.
63.10(c)(5-13), Sec.
63.8(c)(7-8).
Sec. 63.10(e)(3)(vi-viii)........ Excess Emissions Report Requirements for reporting No.
and Summary Report. excess emissions for
continuous monitoring
systems (now called
deviations); Requires all
of the information in
Sec. 63.10(c)(5-13),
Sec. 63.8(c)(7-8).
Sec. 63.10(e)(4)................. Reporting continuous Must submit continuous Yes.
opacity monitoring system opacity monitoring system
data. data with performance
test data.
Sec. 63.10(f).................... Waiver for Recordkeeping/ Procedures for Yes.
Reporting. Administrator to waive.
Sec. 63.11....................... Flares.................... Requirements for flares... No.
Sec. 63.12....................... Delegation................ State authority to enforce Yes.
standards.
Sec. 63.13....................... Addresses................. Addresses where reports, Yes.
notifications, and
requests are sent.
Sec. 63.14....................... Incorporation by Reference Test methods incorporated Yes.
by reference.
Sec. 63.15....................... Availability of Public and confidential Yes.
Information. Information.
----------------------------------------------------------------------------------------------------------------
Appendix A to Subpart DDDDD--Methodology and Criteria for Demonstrating
Eligibility for the Health-Based Compliance Alternatives Specified for
the Large Solid Fuel Subcategory
1. Purpose/Introduction
This appendix provides the methodology and criteria for
demonstrating that your affected source is eligible for the
compliance alternative for the HCl emission limit and/or the total
selected metals (TSM) emission limit. This appendix specifies
emissions testing methods that you must use to determine HCl,
chlorine, and manganese emissions from the affected units and what
parts of the affected source facility must be included in the
eligibility demonstration. You must demonstrate that your affected
source is eligible for the health-based compliance alternatives
using either a look-up table analysis (based on the look-up tables
included in this appendix) or a site-specific compliance
demonstration performed according to the criteria specified in this
appendix. This appendix also specifies how and when you file any
eligibility demonstrations for your affected source and how to show
that your affected source remains eligible for the health-based
compliance alternatives in the future.
2. Who Is Eligible To Demonstrate That They Qualify for the Health-
Based Compliance Alternatives?
Each new, reconstructed, or existing affected source may
demonstrate that they are eligible for the health-based compliance
alternatives. Section 63.7490 of subpart DDDDD defines the affected
source and explains which affected sources are new, existing, or
reconstructed.
3. What Parts of My Facility Have To Be Included in the Health-Based
Eligibility Demonstration?
If you are attempting to determine your eligibility for the
compliance alternative for HCl, you must include every emission
point subject to subpart DDDDD that emits either HCl or
Cl2 in the eligibility demonstration.
If you are attempting to determine your eligibility for the
compliance alternative for TSM, you must include every emission
point subject to subpart DDDDD that emits manganese in the
eligibility demonstration.
4. How Do I Determine HAP Emissions From My Affected Source?
(a) You must conduct HAP emissions tests or fuel analysis for
every emission point covered under subpart DDDDD within the affected
source facility according to the requirements in paragraphs (b)
through (f) of this section and the methods specified in Table 1 of
this appendix.
(1) If you are attempting to determine your eligibility for the
compliance alternative for HCl, you must test the subpart DDDDD
units at your facility for both HCl and Cl2. When
conducting fuel analysis, you must assume any chlorine detected will
be emitted as Cl2.
(2) If you are attempting to determine your eligibility for the
compliance alternative for TSM, you must test the subpart DDDDD
units at your facility for manganese.
(b) Periods when emissions tests must be conducted.
(1) You must not conduct emissions tests during periods of
startup, shutdown, or malfunction, as specified in Sec. 63.7(e)(1).
(2) You must test under worst-case operating conditions as
defined in this appendix. You must describe your worst-case
operating conditions in your performance test report for the process
and control systems (if applicable) and explain why the conditions
are worst-case.
(c) Number of test runs. You must conduct three separate test
runs for each test required in this section, as specified in Sec.
63.7(e)(3). Each test run must last at least 1 hour.
(d) Sampling locations. Sampling sites must be located at the
outlet of the control device and prior to any releases to the
atmosphere.
(e) Collection of monitoring data for HAP control devices.
During the emissions test, you must collect operating parameter
monitoring system data at least every 15 minutes during the entire
emissions test and establish the site-specific operating
requirements in Tables 3 or 4, as appropriate, of subpart DDDDD
using data from the monitoring system and the procedures specified
in Sec. 63.7530 of subpart DDDDD.
[[Page 55283]]
(f) Nondetect data. You may treat emissions of an individual HAP
as zero if all of the test runs result in a nondetect measurement
and the condition in paragraph (f)(1) of this section is met for the
manganese test method. Otherwise, nondetect data for individual HAP
must be treated as one-half of the method detection limit.
(1) For manganese measured using Method 29 in appendix A to 40
CFR part 60, you analyze samples using atomic absorption
spectroscopy (AAS).
(g) You must determine the maximum hourly emission rate for each
appropriate emission point according to Equation 1 of this appendix.
[GRAPHIC] [TIFF OMITTED] TR13SE04.010
Where:
Max Hourly Emissions = Maximum hourly emissions for hydrogen
chloride, chlorine, or manganese, in units of pounds per hour.
Er = Emission rate (the 3-run average as determined according to
Table 1 of this appendix or the pollutant concentration in the fuel
samples analyzed according to Sec. 63.7521) for hydrogen chloride,
chlorine, or manganese, in units of pounds per million Btu of heat
input.
Hm = Maximum rated heat input capacity of appropriate emission
point, in units of million Btu per hour.
5. What Are the Criteria for Determining If My Facility Is Eligible for
the Health-Based Compliance Alternatives?
(a) Determine the HAP emissions from each appropriate emission
point within the affected source facility using the procedures
specified in section 4 of this appendix.
(b) Demonstrate that your facility is eligible for either of the
health-based compliance alternatives using either the methods
described in section 6 of this appendix (look-up table analysis) or
section 7 of this appendix (site-specific compliance demonstration).
(c) Your facility is eligible for the health-based compliance
alternative for HCl if one of the following two statements is true:
(1) The calculated HCl-equivalent emission rate is below the
appropriate value in the look-up table;
(2) Your site-specific compliance demonstration indicates that
your maximum HI for HCl and C12 at a location where
people live is less than or equal to 1.0;
(d) Your facility is eligible for the health-based compliance
alternative for TSM if one of the following two statements is true:
(1) The manganese emission rate for all your subpart DDDDD
sources is below the appropriate value in the look-up table;
(2) Your site-specific compliance demonstration indicates that
your maximum HQ for manganese at a location where people live is
less than or equal to 1.0.
6. How Do I Conduct a Look-Up Table Analysis?
You may use look-up tables to demonstrate that your facility is
eligible for either the compliance alternative for the HCl emission
limit or the compliance alternative for TSM emission limit.
(a) HCl health-based compliance alternative. (1) To calculate
the total toxicity-weighted HCl-equivalent emission rate for your
facility, first calculate the total affected source emission rate of
HCl by summing the maximum hourly HCl emission rates from all your
subpart DDDDD sources. Then, similarly, calculate the total affected
source emission rate for Cl2. Finally, calculate the
toxicity-weighted emission rate (expressed in HCl equivalents)
according to Equation 2 of this appendix.
[GRAPHIC] [TIFF OMITTED] TR13SE04.011
Where:
ERtw is the HCl-equivalent emission rate, lb/hr.
ERi is the emission rate of HAP i in lbs/hr
RfCi is the reference concentration of HAP i
RfCHCl is the reference concentration of HCl (RfCs for
HCl and Cl2 can be found at http://www.epa.gov/ttn/atw/toxsource/summary.html).
(2) The calculated HCl-equivalent emission rate will then be
compared to the appropriate allowable emission rate in Table 2 of
this appendix. To determine the correct value from the table, an
average value for the appropriate subpart DDDDD emission points
should be used for stack height and the minimum distance between any
appropriate subpart DDDDD stack at the facility and the property
boundary should be used for property boundary distance. Appropriate
emission points and stacks are those that emit HCl and/or
Cl2. If one or both of these values does not match the
exact values in the lookup tables, then use the next lowest table
value. (Note: If your average stack height is less than 5 meters,
you must use the 5 meter row.) Your facility is eligible to comply
with the health-based alternative HCl emission limit if your
toxicity-weighted HCl equivalent emission rate, determined using the
methods specified in this appendix, does not exceed the appropriate
value in Table 2 of this appendix.
(b) TSM Compliance Alternative. To calculate the total manganese
emission rate for your affected source, sum the maximum hourly
manganese emission rates for all your subpart DDDDD sources. The
calculated manganese emission rate will then be compared to the
allowable emission rate in the Table 3 of this appendix. To
determine the correct value from the table, an average value for the
appropriate subpart DDDDD emission points should be used for stack
height and the minimum distance between any appropriate subpart
DDDDD stack at the facility and the property boundary should be used
for property boundary distance. Appropriate emission points and
stacks are those that emit manganese. If one or both of these values
does not match the exact values in the lookup tables, then use the
next lowest table value. (Note: If your average stack height is less
than 5 meters, you must use the 5 meter row.) Your facility may
exclude manganese when demonstrating compliance with the TSM
emission limit if your manganese emission rate, determined using the
methods specified in this appendix, does not exceed the appropriate
value specified in Table 3 of this appendix.
7. How Do I Conduct a Site-Specific Compliance Demonstration?
If you fail to demonstrate that your facility is able to comply
with one or both of the alternative health-based emission standards
using the look-up table approach, you may choose to perform a site-
specific compliance demonstration for your facility. You may use any
scientifically-accepted peer-reviewed risk assessment methodology
for your site-specific compliance demonstration. An example of one
approach for performing a site-specific compliance demonstration for
air toxics can be found in the EPA's ``Air Toxics Risk Assessment
Reference Library, Volume 2, Site-Specific Risk Assessment Technical
Resource Document'', which may be obtained through the EPA's Air
Toxics Web site at http://www.epa.gov/ttn/fera/risk_atoxic.html.
(a) Your facility is eligible for the HCl alternative compliance
option if your site-specific compliance demonstration shows that the
maximum HI for HCl and Cl2 from your subpart DDDDD
sources is less than or equal to 1.0.
(b) Your facility is eligible for the TSM alternative compliance
option if your site-specific compliance demonstration shows that the
maximum HQ for manganese from your subpart DDDDD sources is less
than or equal to 1.0.
(c) At a minimum, your site-specific compliance demonstration
must:
(1) Estimate long-term inhalation exposures through the
estimation of annual
[[Page 55284]]
or multi-year average ambient concentrations;
(2) Estimate the inhalation exposure for the individual most
exposed to the facility's emissions;
(3) Use site-specific, quality-assured data wherever possible;
(4) Use health-protective default assumptions wherever site-
specific data are not available, and;
(5) Contain adequate documentation of the data and methods used
for the assessment so that it is transparent and can be reproduced
by an experienced risk assessor and emissions measurement expert.
(d) Your site-specific compliance demonstration need not:
(1) Assume any attenuation of exposure concentrations due to the
penetration of outdoor pollutants into indoor exposure areas;
(2) Assume any reaction or deposition of the emitted pollutants
during transport from the emission point to the point of exposure.
8. What Must My Health-Based Eligibility Demonstration Contain?
(a) Your health-based eligibility demonstration must contain, at
a minimum, the information specified in paragraphs (a)(1) through
(6) of this section.
(1) Identification of each appropriate emission point at the
affected source facility, including the maximum rated capacity of
each appropriate emission point.
(2) Stack parameters for each appropriate emission point
including, but not limited to, the parameters listed in paragraphs
(a)(2)(i) through (iv) below:
(i) Emission release type.
(ii) Stack height, stack area, stack gas temperature, and stack
gas exit velocity.
(iii) Plot plan showing all emission points, nearby residences,
and fenceline.
(iv) Identification of any control devices used to reduce
emissions from each appropriate emission point.
(3) Emission test reports for each pollutant and appropriate
emission point which has been tested using the test methods
specified in Table 1 of this appendix, including a description of
the process parameters identified as being worst case. Fuel analyses
for each fuel and emission point which has been conducted including
collection and analytical methods used.
(4) Identification of the RfC values used in your look-up table
analysis or site-specific compliance demonstration.
(5) Calculations used to determine the HCl-equivalent or
manganese emission rates according to sections 6(a) or (b) of this
appendix.
(6) Identification of the controlling process factors
(including, but not limited to, fuel type, heat input rate, type of
control devices, process parameters reflecting the emissions rates
used for your eligibility demonstration) that will become Federally
enforceable permit conditions used to show that your facility
remains eligible for the health-based compliance alternatives.
(b) If you use the look-up table analysis in section 6 of this
appendix to demonstrate that your facility is eligible for either
health-based compliance alternative, your eligibility demonstration
must contain, at a minimum, the information in paragraphs (a) and
(b)(1) through (3) of this section.
(1) Calculations used to determine the average stack height of
the subpart DDDDD emission points that emit either manganese or HCl
and Cl2.
(2) Identification of the subpart DDDDD emission point, that
emits either manganese or HCl and Cl2, with the minimum
distance to the property boundary of the facility.
(3) Comparison of the values in the look-up tables (Tables 2 and
3 of this appendix) to your maximum HCl-equivalent or manganese
emission rates.
(c) If you use a site-specific compliance demonstration as
described in section 7 of this appendix to demonstrate that your
facility is eligible, your eligibility demonstration must contain,
at a minimum, the information in paragraphs (a) and (c)(1) through
(7) of this section:
(1) Identification of the risk assessment methodology used.
(2) Documentation of the fate and transport model used.
(3) Documentation of the fate and transport model inputs,
including the information described in paragraphs (a)(1) through (5)
of this section converted to the dimensions required for the model
and all of the following that apply: meteorological data; building,
land use, and terrain data; receptor locations and population data;
and other facility-specific parameters input into the model.
(4) Documentation of the fate and transport model outputs.
(5) Documentation of any exposure assessment and risk
characterization calculations.
(6) Comparison of the HQ HI to the limit of 1.0.
9. When Do I Have to Complete and Submit My Health-Based Eligibility
Demonstration?
(a) If you have an existing affected source, you must complete
and submit your eligibility demonstration to your permitting
authority, along with a signed certification that the demonstration
is an accurate depiction of your facility, no later than the date
one year prior to the compliance date of subpart DDDDD. A separate
copy of the eligibility demonstration must be submitted to: U.S.
EPA, Risk and Exposure Assessment Group, Emission Standards Division
(C404-01), Attn: Group Leader, Research Triangle Park, North
Carolina 27711, electronic mail address [email protected].
(b) If you have a new or reconstructed affected source that
starts up before the effective date of subpart DDDDD, or an affected
source that is an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP before
the effective date of subpart DDDDD, then you must comply with the
requirements of subpart DDDDD until your eligibility demonstration
is completed and submitted to your permitting authority.
(c) If you have a new or reconstructed affected source that
starts up after the effective date of subpart DDDDD, or an affected
source that is an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP after
the effective date for subpart DDDDD, then you must follow the
schedule in paragraphs (c)(1) and (2) of this section.
(1) You must complete and submit a preliminary eligibility
demonstration based on the information (e.g., equipment types,
estimated emission rates, etc.) used to obtain your title V permit.
You must base your preliminary eligibility demonstration on the
maximum emissions allowed under your title V permit. If the
preliminary eligibility demonstration indicates that your affected
source facility is eligible for either compliance alternative, then
you may start up your new affected source and your new affected
source will be considered in compliance with the alternative HCl
standard and subject to the compliance requirements in this appendix
or, in the case of manganese, your compliance demonstration with the
TSM emission limit is based on 7 metals (excluding manganese).
(2) You must conduct the emission tests or fuel analysis
specified in section 4 of this appendix upon initial startup and use
the results of these emissions tests to complete and submit your
eligibility demonstration within 180 days following your initial
startup date. To be eligible, you must meet the criteria in section
11 of this appendix within 18 months following initial startup of
your affected source.
10. When Do I Become Eligible for the Health-Based Compliance
Alternatives?
To be eligible for either health-based compliance alternative,
the parameters that defined your affected source as eligible for the
health-based compliance alternatives (including, but not limited to,
fuel type, fuel mix (annual average), type of control devices,
process parameters reflecting the emissions rates used for your
eligibility demonstration) must be submitted for incorporation as
Federally enforceable limits into your title V permit. If you do not
meet these criteria, then your affected source is subject to the
applicable emission limits, operating limits, and work practice
standards in Subpart DDDDD.
11. How Do I Ensure That My Facility Remains Eligible for the Health-
Based Compliance Alternatives?
(a) You must update your eligibility demonstration and resubmit
it each time you have a process change, such that any of the
parameters that defined your affected source changes in a way that
could result in increased HAP emissions (including, but not limited
to, fuel type, fuel mix (annual average), change in type of control
device, changes in process parameters documented as worst-case
conditions during the emissions testing used for your approved
eligibility demonstration).
(b) If you are updating your eligibility demonstration to
account for an action in paragraph (a) of this section, then you
must perform emission testing or fuel analysis according to section
4 of this appendix for the subpart DDDDD emission points that may
have increased HAP emissions beyond the levels reflected in your
previously approved eligibility demonstration due to the process
[[Page 55285]]
change. You must submit your revised eligibility demonstration to
the permitting authority prior to revising your permit to
incorporate the process change. If your updated eligibility
demonstration indicates that your affected source is no longer
eligible for the health-based compliance alternatives, then you must
comply with the applicable emission limits, operating limits, and
compliance requirements in Subpart DDDDD prior to making the process
change and revising your permit.
12. What Records Must I Keep?
You must keep records of the information used in developing the
eligibility demonstration for your affected source, including all of
the information specified in section 8 of this appendix.
13. Definitions
The definitions in Sec. 63.7575 of subpart DDDDD apply to this
appendix. Additional definitions applicable for this appendix are as
follows:
Hazard Index (HI) means the sum of more than one hazard quotient
for multiple substances and/or multiple exposure pathways.
Hazard Quotient (HQ) means the ratio of the predicted media
concentration of a pollutant to the media concentration at which no
adverse effects are expected. For inhalation exposures, the HQ is
calculated as the air concentration divided by the RfC.
Look-up table analysis means a risk screening analysis based on
comparing the HAP or HAP-equivalent emission rate from the affected
source to the appropriate maximum allowable HAP or HAP-equivalent
emission rates specified in Tables 2 and 3 of this appendix.
Reference Concentration (RfC) means an estimate (with
uncertainty spanning perhaps an order of magnitude) of a continuous
inhalation exposure to the human population (including sensitive
subgroups) that is likely to be without an appreciable risk of
deleterious effects during a lifetime. It can be derived from
various types of human or animal data, with uncertainty factors
generally applied to reflect limitations of the data used.
Worst-case operating conditions means operation of an affected
unit during emissions testing under the conditions that result in
the highest HAP emissions or that result in the emissions stream
composition (including HAP and non-HAP) that is most challenging for
the control device if a control device is used. For example, worst-
case conditions could include operation of an affected unit firing
solid fuel likely to produce the most HAP.
Table 1 to Appendix B of Subpart DDDDD--Emission Test Methods
------------------------------------------------------------------------
For . . . You must . . . Using . . .
------------------------------------------------------------------------
(1) Each subpart DDDDD emission Select sampling Method 1 of 40 CFR
point for which you choose to ports' location part 60, appendix
use a compliance alternative. and the number of A.
traverse points.
(2) Each subpart DDDDD emission Determine velocity Method 2, 2F, or
point for which you choose to and volumetric 2G in appendix A
use a compliance alternative. flow rate;. to 40 CFR part
60.
(3) Each subpart DDDDD emission Conduct gas Method 3A or 3B in
point for which you choose to molecular weight appendix A to 40
use a compliance alternative. analysis. CFR part 60.
(4) Each subpart DDDDD emission Measure moisture Method 4 in
point for which you choose to content of the appendix A to 40
use a compliance alternative. stack gas. CFR part 60.
(5) Each subpart DDDDD emission Measure the Method 26 or 26A
point for which you choose to hydrogen chloride in appendix A to
use the HCl compliance and chlorine 40 CFR part 60.
alternative. emission
concentrations.
(6) Each subpart DDDDD emission Measure the Method 29 in
point for which you choose to manganese appendix A to 40
use the TSM compliance emission CFR part 60.
alternative. concentration.
(7) Each subpart DDDDD emission Convert emissions Method 19 F-factor
point for which you choose to concentration to methodology in
use a compliance alternative. lb per MMBtu appendix A to
emission rates. part 60 of this
chapter.
------------------------------------------------------------------------
[[Page 55286]]
Table 2 to Appendix A of Subpart DDDDD--Allowable Toxicity-Weighted Emission Rate Expressed in HCl Equivalents (lbs/hr)
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Distance to property boundary (m)
Stack ht. (m) -----------------------------------------------------------------------------------------------------------------------
0 50 100 150 200 250 500 1000 1500 2000 3000 5000
--------------------------------------------------------------------------------------------------------------------------------------------------------
5............................... 114.9 114.9 114.9 114.9 114.9 114.9 144.3 287.3 373.0 373.0 373.0 373.0
10.............................. 188.5 188.5 188.5 188.5 188.5 188.5 195.3 328.0 432.5 432.5 432.5 432.5
20.............................. 386.1 386.1 386.1 386.1 386.1 386.1 386.1 425.4 580.0 602.7 602.7 602.7
30.............................. 396.1 396.1 396.1 396.1 396.1 396.1 396.1 436.3 596.2 690.6 807.8 816.5
40.............................. 408.1 408.1 408.1 408.1 408.1 408.1 408.1 448.2 613.3 715.5 832.2 966.0
50.............................. 421.4 421.4 421.4 421.4 421.4 421.4 421.4 460.6 631.0 746.3 858.2 1002.8
60.............................. 435.5 435.5 435.5 435.5 435.5 435.5 435.5 473.4 649.0 778.6 885.0 1043.4
70.............................. 450.2 450.2 450.2 450.2 450.2 450.2 450.2 486.6 667.4 813.8 912.4 1087.4
80.............................. 465.5 465.5 465.5 465.5 465.5 465.5 465.5 500.0 685.9 849.8 940.9 1134.8
100............................. 497.5 497.5 497.5 497.5 497.5 497.5 497.5 527.4 723.6 917.1 1001.2 1241.3
200............................. 677.3 677.3 677.3 677.3 677.3 677.3 677.3 682.3 919.8 1167.1 1390.4 1924.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 3 to Appendix A of Subpart DDDDD--Allowable Manganese Emission Rate (lbs/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Distance to property boundary (m)
Stack ht. (m) -----------------------------------------------------------------------------------------------------------------------
0 50 100 150 200 250 500 1000 1500 2000 3000 5000
--------------------------------------------------------------------------------------------------------------------------------------------------------
5............................... 0.29 0.29 0.29 0.29 0.29 0.29 0.36 0.72 0.93 0.93 0.93 0.94
10.............................. 0.47 0.47 0.47 0.47 0.47 0.47 0.49 0.82 1.08 1.08 1.08 1.08
20.............................. 0.97 0.97 0.97 0.97 0.97 0.97 0.97 1.06 1.45 1.51 1.51 1.51
30.............................. 0.99 0.99 0.99 0.99 0.99 0.99 0.99 1.09 1.49 1.72 2.02 2.04
40.............................. 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.12 1.53 1.79 2.08 2.42
50.............................. 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.15 1.58 1.87 2.15 2.51
60.............................. 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.18 1.62 1.95 2.21 2.61
70.............................. 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.22 1.67 2.03 2.28 2.72
80.............................. 1.16 1.16 1.16 1.16 1.16 1.16 1.16 1.25 1.71 2.12 2.35 2.84
100............................. 1.24 1.24 1.24 1.24 1.24 1.24 1.24 1.32 1.81 2.29 2.50 3.10
200............................. 1.69 1.69 1.69 1.69 1.69 1.69 1.69 1.71 2.30 2.92 3.48 4.81
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[FR Doc. 04-11221 Filed 9-10-04; 8:45 am]
BILLING CODE 6560-50-U