National Emission Standards for Hazardous Air Pollutants for
Industrial, Commercial, and Institutional Boilers and Process Heaters
[Federal Register: September 13, 2004 (Volume 69, Number 176)]
[Rules and Regulations]
[Page 55217-55286]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr13se04-11]
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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
eddinger.jim@epa.gov.
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)
[[Page 55219]]
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.regulations.gov/ 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.
[[Page 55220]]
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.
[[Page 55221]]
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.
[[Page 55222]]
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
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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 rem ![[logo] US EPA](http://www.epa.gov/epafiles/images/logo_epaseal.gif){kind=logo}