[Federal Register Volume 69, Number 176 (Monday, September 13, 2004)]
[Rules and Regulations]
[Pages 55218-55286]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-11221]



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Part II





Environmental Protection Agency





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40 CFR Part 63



National Emission Standards for Hazardous Air Pollutants for 
Industrial, Commercial, and Institutional Boilers and Process Heaters; 
Final Rule

  Federal Register / Vol. 69, No. 176 / Monday, September 13, 2004 / 
Rules and Regulations  

[[Page 55218]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[OAR-2002-0058; FRL-7633-9]
RIN 2060-AG69


National Emission Standards for Hazardous Air Pollutants for 
Industrial, Commercial, and Institutional Boilers and Process Heaters

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The EPA is promulgating national emission standards for 
hazardous air pollutants (NESHAP) for industrial, commercial, and 
institutional boilers and process heaters. The EPA has identified 
industrial, commercial, and institutional boilers and process heaters 
as major sources of hazardous air pollutants (HAP) emissions. The final 
rule will implement section 112(d) of the Clean Air Act (CAA) by 
requiring all major sources to meet HAP emissions standards reflecting 
the application of the maximum achievable control technology (MACT). 
The final rule is expected to reduce HAP emissions by 50,600 to 58,000 
tons per year (tpy).
    The HAP emitted by facilities in the boiler and process heater 
source category include arsenic, cadmium, chromium, hydrogen chloride 
(HCl), hydrogen fluoride, lead, manganese, mercury, nickel, and various 
organic HAP. Exposure to these substances has been demonstrated to 
cause adverse health effects such as irritation to the lung, skin, and 
mucus membranes, effects on the central nervous system, kidney damage, 
and cancer. These adverse health effects associated with the exposure 
to these specific HAP are further described in this preamble. In 
general, these findings only have been shown with concentrations higher 
than those typically in the ambient air.
    The final rule contains numerous compliance provisions including 
health-based compliance alternatives for the hydrogen chloride and 
total selected metals emission limits.

DATES: The final rule is effective November 12, 2004. The incorporation 
by reference of certain publications listed in the final rule is 
approved by the Director of the Federal Register as of November 12, 
2004.

ADDRESSES: The official public docket is the collection of materials 
that is available for public viewing at the Office of Air and Radiation 
Docket and Information Center (Air Docket) in the EPA Docket Center, 
Room B-102, 1301 Constitution Avenue, NW., Washington, DC.

FOR FURTHER INFORMATION CONTACT: For information concerning 
applicability and rule determinations, contact your State or local 
representative or appropriate EPA Regional Office representative. For 
information concerning rule development, contact Jim Eddinger, 
Combustion Group, Emission Standards Division (C439-01), U.S. EPA, 
Research Triangle Park, North Carolina 27711, telephone number (919) 
541-5426, fax number (919) 541-5450, electronic mail address 
[email protected].

SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities 
potentially regulated by this action include:

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                                                                               Examples of potentially regulated
                 Category                     NAICS code         SIC code                   entities
----------------------------------------------------------------------------------------------------------------
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.epa.gov/edocket/ to view public comments, 
access the index listing of the contents of the official public docket, 
and to access those documents in the public docket that are available 
electronically. Once in the system, select ``search,'' then key in the 
appropriate docket identification number.
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of the final rule is also available on the WWW 
through the Technology Transfer Network (TTN). Following signature, a 
copy of the final rule will be posted on the TTN policy and guidance 
page for newly proposed or promulgated rules at the following address: 
http://www.epa.gov/ttn/oarpg. The TTN provides information and 
technology exchange in various areas of air pollution control. If more 
information regarding the TTN is needed, call the TTN HELP line at 
(919) 541-5384.
    Judicial Review. Under section 307(b)(1) of the CAA, judicial 
review of the NESHAP is available by filing a petition for review in 
the U.S. Court of Appeals for the District of Columbia Circuit by 
November 12, 2004. Only those objections to the final rule that were 
raised with reasonable specificity during the period for public comment 
may be raised during judicial review. Under section 307(b)(2) of the 
CAA, the requirements that are the subject of the final rule may not be 
challenged later in civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Background Information Document. The EPA proposed the NESHAP for 
industrial, commercial, and institutional boilers and process heaters 
on January 13, 2003 (68 FR 1660) and received 218 comment letters on 
the proposal. A memorandum ``National Emission Standards for Hazardous 
Air Pollutants for Industrial, Commercial, and Institutional Boilers 
and Process Heaters, Summary of Public Comments and Responses,'' 
containing EPA's responses to each public comment is available in 
Docket No. OAR-2002-0058.
    Outline. The information presented in this preamble is organized as 
follows:

I. Background Information
    A. What is the statutory authority for the final rule?
    B. What criteria are used in the development of NESHAP?
    C. How was the final rule developed?
    D. What is the relationship between the final rule and other 
combustion rules?
    E. What are the health effects of pollutants emitted from 
industrial, commercial, and institutional boilers and process 
heaters?
II. Summary of the Final Rule
    A. What source categories and subcategories are affected by the 
final rule?
    B. What is the affected source?
    C. What pollutants are emitted and controlled?
    D. Does the final rule apply to me?
    E. What are the emission limitations and work practice 
standards?
    F. What are the testing and initial compliance requirements?
    G. What are the continuous compliance requirements?
    H. What are the notification, recordkeeping and reporting 
requirements?
    I. What are the health-based compliance alternatives, and how do 
I demonstrate eligibility?
III. What are the significant changes since proposal?
    A. Definition of Affected Source
    B. Sources Not Covered by the NESHAP
    C. Emission Limits
    D. Definitions Added or Revised
    E. Requirements for Sources in Subcategories Without Emission 
Limits or Work Practice Requirements
    F. Carbon Monoxide Work Practice Emission Levels and 
Requirements
    G. Fuel Analysis Option
    H. Emissions Averaging
    I. Opacity Limit
    J. Operating Limit Determination
    K. Revision of Compliance Dates
IV. What are the responses to significant comments?
    A. Applicability
    B. Format
    C. Compliance Schedule
    D. Subcategorization
    E. MACT Floor
    F. Beyond the MACT Floor
    G. Work Practice Requirements
    H. Compliance
    I. Emissions Averaging
    J. Risk-based Approach
V. Impacts of the Final Rule
    A. What are the air impacts?
    B. What are the water and solid waste impacts?
    C. What are the energy impacts?
    D. What are the control costs?
    E. What are the economic impacts?
    F. What are the social costs and benefits of the final rule?
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act of 1995
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations that 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Congressional Review Act

I. Background Information

A. What Is the Statutory Authority for the Final Rule?

    Section 112 of the CAA requires us to list categories and 
subcategories of major sources and area sources of HAP and to establish 
NESHAP for the listed source categories and subcategories. Industrial 
boilers, commercial and institutional boilers, and process heaters were 
listed on July 16, 1992 (57 FR 31576). Major sources of HAP are those 
that have the potential to emit greater than 10 tpy of any one HAP or 
25 tpy of any combination of HAP.

B. What Criteria Are Used in the Development of NESHAP?

    Section 112(c)(2) of the CAA requires that we establish NESHAP for 
control of HAP from both existing and new major sources, based upon the 
criteria set out in CAA section 112(d). The CAA requires the NESHAP to 
reflect the maximum degree of reduction in emissions of HAP that is 
achievable, taking into consideration the cost of achieving the 
emission reduction, any non-air quality health and environmental 
impacts, and energy requirements. This level of control is commonly 
referred to as the MACT.
    The minimum control level allowed for NESHAP (the minimum level of 
stringency for MACT) is the ``MACT floor,'' as defined under section 
112(d)(3) of the CAA. The MACT floor for existing sources is the 
emission limitation achieved by the average of the best-performing 12 
percent of existing sources for categories and subcategories with 30 or 
more sources, or the average of the best-performing five sources for 
categories or subcategories with fewer than 30 sources. For new 
sources, the MACT floor cannot be less stringent than the emission 
control achieved in practice by the best-controlled similar source.

C. How Was the Final Rule Developed?

    We proposed standards for industrial, commercial, and institutional 
boilers and process heaters on January 13, 2003 (68 FR 1660). Public 
comments were solicited at the time of proposal. The public comment 
period lasted from January 13, 2003, to March 14, 2003.

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    We received a total of 218 public comment letters on the proposed 
rule. Comments were submitted by industry trade associations, owners/
operators of boilers and process heaters, State regulatory agencies and 
their representatives, and environmental groups. Today's final rule 
reflects our consideration of all of the comments and additional 
information received. Major public comments on the proposed rules, 
along with our responses to those comments, are summarized in this 
preamble.

D. What Is the Relationship Between the Final Rule and Other Combustion 
Rules?

    The final rule regulates source categories covering industrial 
boilers, institutional and commercial boilers, and process heaters. 
These source categories potentially include combustion units that are 
already regulated by other MACT standards. Therefore, we are excluding 
from the final rule any combustion units that are already or will be 
subject to regulation under another MACT standard under 40 CFR part 63.
    Combustion units that are regulated by other standards and are 
therefore excluded from the final rule include solid waste incineration 
units covered by section 129 of the CAA; boilers or process heaters 
required to have a permit under section 3005 of the Solid Waste 
Disposal Act or covered by the hazardous waste combustor NESHAP in 40 
CFR part 63, subpart EEE \1\; and recovery boilers or furnaces covered 
by 40 CFR part 63, subpart MM.
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    \1\ Please note that boilers that burn small quantities of 
hazardous waste under the exemptions provided by 40 CFR 266.108 are 
subject to today's final rule.
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    With regards to solid waste incineration units covered by section 
129 of the CAA, EPA solicited on February 17, 2004 (69 FR 7390) public 
comments on the definition of ``commercial and industrial solid waste 
incineration unit'' for the purpose of determining which combustion 
sources to regulate under section 129 and which to regulate under 
section 112 (e.g., boilers and process heaters). As stated above, 
combustion units covered under section 129 are not subject to the final 
rule.
    Electric utility steam generating units are not subject to the 
final rule. An electric utility steam generating unit is a fossil fuel-
fired combustion unit of more than 25 megawatts that serves a generator 
that produces electricity for sale. A fossil fuel-fired unit that 
cogenerates steam and electricity and supplies more than one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit. Non-fossil fuel-
fired utility boilers and electric utility steam generating units less 
than 25 megawatts are covered by the final rule.
    In 1986, EPA codified the NSPS for industrial boilers (40 CFR part 
60, subparts Db and Dc) and revised portions of them in 1999. The NSPS 
regulates emissions of particulate matter (PM), sulfur dioxide, and 
nitrogen oxides from boilers constructed after June 19, 1984. Sources 
subject to the NSPS are also subject to the final rule because the 
final rule regulates sources of hazardous air pollutants while the NSPS 
does not. However, in developing the final rule for industrial, 
commercial, and institutional boilers and process heaters, EPA 
minimized the monitoring requirements, testing requirements, and 
recordkeeping requirements to avoid duplicating requirements.
    Because of the broad applicability of the final rule due to the 
definition of a process heater, certain process heaters could appear to 
fit the applicability of another existing MACT rule. We have, 
therefore, included in the list of combustion units not subject to the 
final rule refining kettles subject to the secondary lead MACT rule (40 
CFR part 63, subpart X); ethylene cracking furnaces covered by 40 CFR 
part 63, subpart YY; and blast furnace stoves described in the EPA 
document entitled ``National Emission Standards for Hazardous Air 
Pollutants for Integrated Iron and Steel Plants--Background Information 
for Proposed Standards'' (EPA-453/R-01-005).

E. What Are the Health Effects of Pollutants Emitted From Industrial, 
Commercial, and Institutional Boilers and Process Heaters?

    The final rule protects air quality and promotes the public health 
by reducing emissions of some of the HAP listed in section 112(b)(1) of 
the CAA. As noted above, emissions data collected during development of 
the proposed rule show that HCl emissions represent the predominant HAP 
emitted by industrial boilers. Industrial boilers emit lesser amounts 
of hydrogen fluoride, chlorine, metals (arsenic, cadmium, chromium, 
mercury, manganese, nickel, and lead), and organic HAP emissions. 
Although numerous organic HAP may be emitted from industrial boilers 
and process heaters, only a few account for essentially all the mass of 
organic HAP emissions. These organic HAP are: Formaldehyde, benzene, 
and acetaldehyde.
    Exposure to high levels of these HAP is associated with a variety 
of adverse health effects. These adverse health effects include chronic 
health disorders (e.g., irritation of the lung, skin, and mucus 
membranes, effects on the central nervous system, and damage to the 
kidneys), and acute health disorders (e.g., lung irritation and 
congestion, alimentary effects such as nausea and vomiting, and effects 
on the kidney and central nervous system). We have classified three of 
the HAP as human carcinogens and five as probable human carcinogens. 
Our screening assessment for respiratory HAP and for central nervous 
system (CNS) HAP, using health protective assumptions, indicates that 
manganese and chlorine are the only boiler-related HAP that are 
reasonably expected to approach health based criteria concentrations at 
receptor locations at or beyond facility boundaries. Emissions of all 
other HAP modeled on an individual basis appears to be insignificant 
relative to the concentration that would produce the health effects 
that they represent. The maximal hazard index (HI) for summation of the 
HAP modeled in the screening assessment for respiratory effects, 
including chlorine, was less than 3. The maximal HI for summation of 
the HAP modeled in the screening assessment for CNS effects, including 
manganese, was less than 3. Therefore, effects noted below for HAP at 
high concentrations are not expected to occur prior or after regulation 
as a result of emissions from these facilities, and are provided to 
illustrate the nature of the contaminant's effects at high dose. A 
screening assessment was also conducted for acute effects, and no 
exceedances were seen. Therefore, potential acute effects are not 
discussed below. However, to the extent the adverse effects do occur, 
the final rule will reduce emissions and subsequent exposures.
Acetaldehyde
    Acetaldehyde is ubiquitous in the environment and may be formed in 
the body from the breakdown of ethanol (ethyl alcohol). In humans, 
symptoms of chronic (long-term) exposure to acetaldehyde resemble those 
of alcoholism. Long-term inhalation exposure studies in animals 
reported effects on the nasal epithelium and mucous membranes, and 
increased kidney weight. The EPA has classified acetaldehyde as a 
probable human carcinogen (Group B2) based on animal studies that have 
shown nasal tumors in rats and laryngeal tumors in hamsters.

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Arsenic
    Chronic (long-term) inhalation exposure to inorganic arsenic in 
humans is associated with irritation of the skin and mucous membranes. 
Human data suggest a relationship between inhalation exposure for women 
working at or living near metal smelters and an increased risk of 
reproductive effects. Inorganic arsenic exposure in humans by the 
inhalation route has been shown to be strongly associated with lung 
cancer, while ingestion of inorganic arsenic in humans has been linked 
to a form of skin cancer and also to bladder, liver, and lung cancer. 
The EPA has classified inorganic arsenic as a Group A, human 
carcinogen.
Benzene
    Chronic (long-term) inhalation exposure has caused various 
disorders in the blood, including reduced numbers of red blood cells. 
Increased incidence of leukemia (cancer of the tissues that form white 
blood cells) has been observed in humans occupationally exposed to 
benzene. The EPA has classified benzene as a Group A, known human 
carcinogen.
Beryllium
    Chronic (long-term) inhalation exposure of humans to high levels of 
beryllium has been reported to cause chronic beryllium disease 
(berylliosis), in which granulomatous (noncancerous) lesions develop in 
the lung. Inhalation exposure to high levels of beryllium has been 
demonstrated to cause lung cancer in rats and monkeys. Human studies 
are limited, but suggest a causal relationship between beryllium 
exposure and an increased risk of lung cancer. We have classified 
beryllium as a Group B1, probable human carcinogen, when inhaled; data 
are inadequate to determine whether beryllium is carcinogenic when 
ingested.
Cadmium
    Chronic (long-term) inhalation or oral exposure to cadmium leads to 
a build-up of cadmium in the kidneys that can cause kidney disease. 
Cadmium has been shown to be a developmental toxicant at high doses in 
animals, resulting in fetal malformations and other effects, but no 
conclusive evidence exists in humans. Animal studies have demonstrated 
an increase in lung cancer from long-term inhalation exposure to 
cadmium. The EPA has classified cadmium as a Group B1, probable 
carcinogen.
Chlorine
    Chlorine is a commonly used household cleaner and disinfectant. 
Chlorine is an irritant to the eyes, the upper respiratory tract, and 
lungs. Chronic (long-term) exposure to chlorine gas in workers has 
resulted in respiratory effects, including eye and throat irritation 
and airflow obstruction. No information is available on the 
carcinogenic effects of chlorine in humans from inhalation exposure. A 
National Toxicology Program (NTP) study showed no evidence of 
carcinogenic activity in male rats or male and female mice, and 
equivocal evidence in female rats, from ingestion of chlorinated water. 
The EPA has not classified chlorine for potential carcinogenicity.
Chromium
    Chromium may be emitted by industrial boilers in two forms, 
trivalent chromium (chromium III) or hexavalent chromium (chromium VI). 
The respiratory tract is the major target organ for chromium VI 
toxicity for inhalation exposures. Bronchitis, decreased pulmonary 
function, pneumonia, and other respiratory effects have been noted from 
chronic high dose exposure in occupational settings to chromium VI. 
Limited human studies suggest that chromium VI inhalation exposure may 
be associated with complications during pregnancy and childbirth, while 
animal studies have not reported reproductive effects from inhalation 
exposure to chromium VI. Human and animal studies have clearly 
established that inhaled chromium VI is a carcinogen, resulting in an 
increased risk of lung cancer. The EPA has classified chromium VI as a 
Group A, human carcinogen.
    Chromium III is less toxic than chromium VI. The respiratory tract 
is also the major target organ for chromium III toxicity, similar to 
chromium VI. Chromium III is an essential element in humans, with a 
daily intake of 50 to 200 micrograms per day recommended for an adult. 
The body can detoxify some amount of chromium VI to chromium III. The 
EPA has not classified chromium III with respect to carcinogenicity.
Formaldehyde
    Exposure to formaldehyde irritates the eyes, nose, and throat. 
Reproductive effects, such as menstrual disorders and pregnancy 
problems, have been reported in female workers exposed to high levels 
of formaldehyde. Limited human studies have reported an association 
between formaldehyde exposure and lung and nasopharyngeal cancer. 
Animal inhalation studies have reported an increased incidence of nasal 
squamous cell cancer. The EPA considers formaldehyde a probable human 
carcinogen (Group B2).
Hydrogen chloride
    Hydrogen chloride, also called hydrochloric acid, is corrosive to 
the eyes, skin, and mucous membranes at high concentration. Chronic 
(long-term) occupational exposure to high levels of hydrochloric acid 
has been reported to cause gastritis, bronchitis, and dermatitis in 
workers. Prolonged exposure to lower concentrations may also cause 
dental discoloration and erosion. No information is available on the 
reproductive or developmental effects of hydrochloric acid in humans. 
In rats exposed to high levels of hydrochloric acid by inhalation, 
altered estrus cycles have been reported in females and increased fetal 
mortality and decreased fetal weight have been reported in offspring. 
The EPA has not classified hydrochloric acid for carcinogenicity.
Hydrogen fluoride
    Chronic (long-term) exposure to fluoride at low levels has a 
beneficial effect of dental cavity prevention and may also be useful 
for the treatment of osteoporosis. Exposure to higher levels of 
fluoride may cause dental fluorosis. One study reported menstrual 
irregularities in women occupationally exposed to fluoride. The EPA has 
not classified hydrogen fluoride for carcinogenicity.
Lead
    Lead can cause a variety of effects at low dose levels. Chronic 
(long-term) exposure to high levels of lead in humans results in 
effects on the blood, central nervous system (CNS), blood pressure, and 
kidneys. Children are particularly sensitive to the chronic effects of 
lead, with slowed cognitive development, reduced growth and other 
effects reported. Reproductive effects, such as decreased sperm count 
in men and spontaneous abortions in women, have been associated with 
lead exposure. The developing fetus is at particular risk from maternal 
lead exposure, with low birth weight and slowed postnatal 
neurobehavioral development noted. Human studies are inconclusive 
regarding lead exposure and cancer, while animal studies have reported 
an increase in kidney cancer from high-dose lead exposure by the oral 
route. The EPA has classified lead as a Group B2, probable human 
carcinogen.

[[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

[[Page 55234]]

of the fuel. Good combustion practice (GCP), in terms of boilers and 
process heaters, could be defined as the system design and work 
practices expected to minimize organic HAP emissions. While few sources 
in EPA's database specifically reported using good combustion 
practices, the data that we have suggests that boilers and process 
heaters within each subcategory might use any of a wide variety of 
different work practices, depending on the characteristics of the 
individual unit. The lack of information, and lack of a uniform 
approach to assuring combustion efficiency, is not surprising given the 
extreme diversity of boilers and process heaters, and given the fact 
that no applicable Federal standards, and most applicable State 
standards, do not include work practice requirements for boilers and 
process heaters. Even those States that do have such requirements do 
not require the same work practices. For example, CO emissions are 
generally a good indicator of incomplete combustion, and, therefore, 
low CO emissions might reflect good combustion practices. (As discussed 
in the proposal, CO is considered a surrogate for organic HAP 
emissions.) Therefore, we considered whether existing CO emission 
limits might be used to establish good combustion practice standards 
for boilers and process heaters. We reviewed State regulations 
applicable to boilers and process heaters, and then for each 
subcategory we matched the applicability of State CO emission limits 
with information on the locations and characteristics of the boilers 
and process heaters in the population database. Ultimately, we found 
that very few units (less than 6 percent) in any subcategory were 
subject to CO emission limits. We concluded that this information did 
not allow EPA to identify a level of performance that was 
representative of good combustion across the various units in any 
subcategory. Therefore, we did not establish a CO emission limit, as a 
surrogate for organic HAP emissions, as a part of the MACT floor for 
existing units. However, we have considered the appropriateness of such 
requirements in the context of evaluation possible beyond-the-floor 
options.
    In general, boilers and process heaters are designed for good 
combustion. Facilities have an economic incentive to ensure that fuel 
is not wasted, and the combustion device operates properly and is 
appropriately maintained. In fact, existing boilers and process heaters 
are used typically as high efficiency control devices to control 
(reduce) emission streams containing organic HAP compounds from various 
process operations. Therefore, EPA's inability to establish a 
combustion practice requirement as part of the MACT floor for existing 
sources in this category should not reduce the incentive for owners and 
operators to run their boilers and process heaters at top efficiency.
    As a result of the evaluation of the feasibility of establishing 
emission limits based on control techniques such as fuel switching and 
good combustion practices, we concluded that add-on control technology 
should be the primary factor for purposes of identifying the best 
controlled units within each subcategory of boilers and process 
heaters. We identified the types of air pollution control techniques 
currently used. We ranked those controls according to their 
effectiveness in removing the different HAP categories of pollutants; 
including metallic HAP and PM, inorganic HAP such as acid gases, 
mercury, and organic HAP. We then listed all the boilers and process 
heaters in the population database in order of decreasing control 
device effectiveness within each subcategory for each pollutant type. 
Then we identified the top 12 percent of units within each category 
based on this ranking, and determined what kind of emission control 
technology, or combination of technologies, the units in the top 12 
percent employed. Finally, we looked at the emissions test data from 
boilers and process heaters that used the same control technology, or 
technologies, as the units in the top 12 percent to estimate the 
average emissions limitation achieved by these units.
    This approach reasonably ensures that the emission limit selected 
as the MACT floor adequately represents the average level of control 
actually achieved by units in the top 12 percent. The analysis of the 
measured emissions from units representative of the top 12 percent is 
reasonably designed to provide a meaningful estimate of the average 
performance, or central tendency, of the best controlled 12 percent of 
units in a given subcategory. For existing subcategories where less 
than 12 percent of units in the subcategory use any type of control 
technology, we looked to see if we could estimate the central tendency 
of the best controlled units by looking at the unit occupying the 
median point in the top 12 percent (the unit at the 94th percentile). 
If the median unit of the top 12 percent is using some control 
technology, we might use the measured emission performance of that 
individual unit as the basis for estimating an appropriate average 
level of control of the top 12 percent. For subcategories where less 
than 6 percent of the units in a HAP grouping used controls or limited 
emissions, the median unit for that HAP grouping reflects no emissions 
reductions. Therefore, in these circumstances, EPA has appropriately 
established the MACT floor emission levels for these sources as no 
emission reduction.
    Comment: Many commenters opposed EPA using emissions data from 
units in the large subcategory to develop emission limits for units in 
the small or limited use subcategories. Some commenters stated that it 
was not appropriate to assume that emissions rates achievable by large 
units are achievable by small units, even the best controlled units. 
Other commenters argued that the use of large unit data in MACT 
determinations for other subcategories would defeat the purpose of the 
subcategorization and violate the requirements of CAA section 112 
because the use of this data does not represent sources in the relevant 
category or subcategory.
    Response: The EPA disagrees with the commenters and maintains that 
it has conducted the MACT floor analysis appropriately. Section 112(d) 
of the CAA requires us to establish emission limits for new sources 
based on the performance of the best-controlled similar source. The CAA 
does not specify that the similar source must be within the same source 
category or subcategory. To the contrary, our interpretation of section 
112(d) is that we are obligated to consider similar sources from other 
source categories or subcategories in determining the best-controlled 
similar source for establishing MACT for new sources.
    For new limited use and small units, we concluded that the best-
controlled similar sources are found in the large subcategory. First, 
EPA determined the control technology used by the best controlled 
sources in the subcategory. For example, only units in the population 
database less than 10 MMBtu/hr (and not in the limited use subcategory) 
were used to determine the MACT floor control technology for units in 
the small subcategories. Second, EPA used information in the emissions 
test database to establish the emission level associated with the MACT 
floor control technology. The emissions test database did not contain 
test data for limited use or small boilers and process heaters. Section 
112(d) of the CAA requires EPA to use information from similar sources 
to set the MACT floor. Such sources may not be in the same subcategory. 
Although the units in the small and

[[Page 55235]]

limited use subcategories are different enough to warrant their own 
subcategory (i.e., different purposes and operation), emissions of the 
specific types of HAP for which limits are being proposed are expected 
to be related more to the type of fuel burned and the type of control 
used, than to unit operation. Consequently, EPA determined that 
emissions information from large fuel-fired units could be used to 
establish MACT floor levels for the small and limited use subcategories 
because the fuels and controls are similar. The proposal preamble 
requested additional information from commenters to refine/revise the 
approach if necessary. No commenters provided emissions information for 
limited use or small subcategory boilers or process heaters.
    Comment: Several commenters requested that EPA account for 
variability in fuel composition as MACT floors are established and to 
provide adequate allowances for inherent fuel supply variability. Some 
commenters argued that there is no flexibility in the rule to account 
for this variability and noted that coal composition can vary by 
location and also within an individual seam.
    Response: As described in the memorandum ``Revised MACT Floor 
Analysis for the Industrial, Commercial, and Institutional Boilers and 
Process Heater National Emission Standards for Hazardous Air Pollutants 
Based on Public Comments'' in the docket, the calculation of numerical 
emission limits was a two-step analysis. The first step involved 
calculating a numerical average of the appropriate subset of emission 
test data. The second step involved generating and applying an 
appropriate variability factor to account for unavoidable variations in 
emissions due to uncontrollable variations in fuel characteristics and 
ordinary operational variability. Accounting for variability is 
appropriate in order to generate a more accurate estimation of the 
actual, long term, performance of a source (e.g., the source occupying 
the median point in the top 12 percent). An emission test provides a 
momentary snapshot, not an estimation of continuous performance. In 
order to translate the former into the latter, we must account for that 
ordinary and unavoidable variability that the source is likely to 
experience over time. This gives us a more reasonable estimate of the 
actual level of emissions control that the unit is achieving. The EPA 
contends that by considering the variability of emissions information, 
we have indirectly incorporated variability in fuel, operating 
conditions, and sampling and analytical conditions because these 
parameters vary from emission tests conducted from one unit to another, 
and even within each test set of three measurements at a single unit. 
The most elementary measure of variation is range. Range is defined as 
the difference between the largest and smallest values. This is the 
variability methodology used in the proposed rule. That is, for each 
unit with multiple emissions tests conducted over time, the variability 
was calculated by dividing the highest three-run test result by the 
lowest three-run test result. The overall variability was calculated by 
averaging all the individual unit variability factors. This overall 
variability factor was multiplied by the overall average emission level 
to derive a MACT floor limit representative of the average emission 
limitation achieved by the top 12 percent of units. This approach 
adequately accounts for inherent fuel supply variability. Based on 
comments, EPA did conduct a more robust statistical analysis (t-test) 
of the mercury emissions data used in the MACT floor analysis to 
identify the 97.5th percent confidence limit. This analysis provided 
similar results to the variability analysis conducted in the proposed 
rule. Consequently, EPA decided not to change its variability 
methodology. A detailed discussion of the statistical analysis 
conducted is provided in the memorandum ``Statistical Analysis of 
Mercury Test Data Variability in Response to Public Comments on 
Determination of the MACT Floor for Mercury Emissions'' in the docket.
    Comment: Several commenters supported EPA's finding that the MACT 
floor level of control for existing gaseous and liquid fuel units is no 
control. Other commenters noted that EPA has a clear statutory 
obligation to set emission standards for each listed HAP (the commenter 
cited legal briefs). One commenter specifically challenged EPA's 
determination of the MACT floor for organic pollutants. The commenter 
explained that EPA should rank the units for which emissions data is 
available according to the best performing units, not based on the add-
on control level of 6 percent of the total population. The commenter 
noted that the U.S. Court of Appeals for the DC Circuit had squarely 
held, in the National Lime case, that EPA was not allowed to make a 
``no control'' determination for a pollutant emitted by a listed 
category of sources.
    Response: The EPA agrees that all factors which might control HAP 
emissions must be considered in making a floor determination for each 
subcategory. However, EPA disagrees that it must express the floor as a 
quantitative emission level in those instances where the sources on 
which the floor determination is based has not adopted or implemented 
any measure that would reduce emissions. For several subcategories and 
certain HAP, EPA has not identified any adjustments or other 
operational modifications that would materially reduce emissions by 
these units, and EPA had determined that no add-on controls are 
presently in use. In these circumstances, EPA has established 
appropriately the MACT floors for these sources as no emission 
reduction.
    Comment: One commenter pointed out that the variability factor used 
to make the calculated MACT floor less stringent is not allowed by 
section 112 of the CAA. The commenter mentioned that the variability 
factors are not consistent, as one factor considers the fuel 
variability and the other factor considers the test data variability.
    Response: Section 112(d)(2) of the CAA requires that emissions 
standards promulgated shall require the maximum degree of reductions in 
emissions that the EPA Administrator, taking into consideration the 
costs of achieving such emission reduction, determines is achievable 
for new and existing sources in the subcategory to which such emission 
standards applies. Accounting for variability is appropriate in order 
to generate a more accurate estimation of the actual, long term, 
performance of a source (e.g., the source occupying the median point in 
the top 12 percent). An emission test provides a momentary snapshot, 
not an estimation of continuous performance. In order to translate the 
former into the latter, we must account for that ordinary and 
unavoidable variability that the source is like to experience over 
time. This give us a more reasonable estimate of the actual level of 
emissions control that the unit is achieving. As such, due to 
variations in fuel burned, and ordinary operational variability any 
emission limit set from a point source measurement alone may not be 
indicative of normal emissions or operations of the unit. Attempting to 
base a standard (either a floor standard, or a beyond-the-floor 
standard) solely on point measurements would lead to unachievable 
standards for all sources. Limits set by EPA must be achieved at all 
times, and it is important that the MACT floor limit adequately account 
for the normal and unavoidable variability in the process and in the 
operation of the control device.
    Variability was assessed two ways. For existing subcategories, 
variability in emissions information was used to develop variability 
factors for all

[[Page 55236]]

subcategories where emissions information was available. Variability in 
fuel content was used only in situations regarding determining the 
achievable MACT floor level for new sources from the emission test 
result on the best controlled similar source. This approach is 
appropriate since the main uncertainty associated with the emission 
test result from the best controlled similar source is fuel 
variability. Corresponding fuel analysis results were not available for 
the emissions test results from the best controlled similar source. 
Whereas, the average emission level of the best 12 percent of the units 
has, besides fuel variability, the uncertainty associated with 
operational and design variability of the various control devices 
installed on units that represent the best 12 percent of the units. For 
example, available fuel analysis information shows that mercury content 
of coal varies by a factor of 12.54. Dividing the highest mercury 
emission test result by the lowest mercury test results from coal-fired 
units included in units that represent the best 12 percent results in a 
variability factor of 20. Therefore, we concluded that fuel 
availability was inherently considered in the MACT floor analysis 
approach used for existing subcategories.
    Comment: Many commenters requested that EPA revise the MACT floor 
methodology for mercury emission limits. The commenters contended that 
the variability factor was calculated inappropriately. Other commenters 
stated that EPA should account for variability in fuel composition in 
the MACT floor analysis. Other commenters expressed concern that the 
floor level of control was based on fabric filters, which has not been 
proven at all sources to reduce mercury.
    Response: As discussed in the proposal preamble, the MACT floor 
analysis for mercury was based on a two step process. First the 
percentage of units with control technologies that could achieve 
mercury emissions reductions was determined using the boiler population 
databases. If the control technology analysis indicated that at least 
12 percent of sources in the subcategory used a control device that 
could achieve mercury emissions reductions, then the control technology 
present at the median (6th percentile) was identified as the MACT floor 
control technology. The MACT floor level of control for mercury was 
identified as a fabric filter. The control effectiveness of fabric 
filters was based on emissions information for utility boilers that 
indicated that mercury emissions reductions were being achieved with 
this technology. In this case, we could use control efficiency 
information from another similar source category to supplement the 
information available in this source category because of the similarity 
in fuel burned, combustor type, and control methodology and operation. 
We maintain that fabric filters are still the appropriate level of 
control for the MACT floor.
    Second, the emission limit associated with the MACT floor control 
technology was calculated using emissions information for units in the 
subcategory, whenever possible. For most of the subcategories 
developed, emissions information was adequate. Only for the emission 
limit for new source liquids and the variability factor for new source 
solids was fuel pollutant content incorporated into the MACT floor 
analyses. The mercury fuel content of coal from the utility industry 
was used in developing the variability factors for new solid fired 
units. This was done because mercury emissions are dependent on the 
quantity of mercury in the fuel burned. Coal available to utilities and 
industrial boilers and process heaters is expected to be similar, and 
coal is the solid fuel that is routinely used in such units that has 
generally the greatest degree of HAP variability. We maintain that the 
utility database used at proposal to develop the variability factor for 
new sources was adequate in establishing the MACT floor emission limit.
    The EPA recognizes that the mercury emissions database for 
industrial boilers is limited. However, EPA is directed by the CAA to 
develop standards for sources using whatever data is available. Prior 
to proposal and during the Industrial Combustion Coordinated Rulemaking 
(ICCR) process, EPA conducted a thorough search for HAP emission test 
reports. This search was supported by industry, trade groups, and 
States. For criteria pollutants, such as PM, substantial emission 
information was available and gathered. For mercury and other HAP, this 
was not the case. Industrial boilers have not generally been required 
to test for HAP emissions. In the proposed rule, EPA requested 
commenters to provide additional emissions information. However, only 
one source provided any additional mercury emissions data. This 
information (test results from three additional coal-fired industrial 
boilers) was used to revise the mercury emission limit for existing 
sources. We also reviewed the mercury emission database used to develop 
the MACT floor emission limit for existing sources. After review, we 
determined that a revision to the variability factor was appropriate. 
The additional data and the revised variability factor was used to re-
calculate the mercury emission limit to be 0.000009 lb/MMBtu (from 
0.000007 lb/MMBtu at proposal). A detailed discussion of the revised 
MACT floor analysis conducted is provided in the memorandum ``Revised 
MACT Floor Analysis for the Industrial, Commercial, and Institutional 
Boilers and Process Heaters National Emission Standards for Hazardous 
Air Pollutants Based on Public Comments'' in the docket.
    Variability of the emissions data were incorporated into the final 
emission limits. The EPA contends that by considering the variability 
of emissions information, we have indirectly incorporated variability 
in fuel, operating conditions, and sampling and analytical conditions 
because these parameters vary from emission tests conducted from one 
unit to another, and even within one unit. The EPA does not consider it 
appropriate or feasible to incorporate variability from a multitude of 
parameters because such information is not available and cannot be 
correlated to the emissions information in the emissions test database. 
For the final rule, EPA did conduct a statistical analysis of the data 
to identify the 97.5th percent confidence interval. This analysis 
provided similar results to the variability analysis conducted in the 
proposed rule. Consequently, EPA decided not to change its variability 
methodology. A detailed discussion of the statistical analysis 
conducted is provided in the memorandum ``Statistical Analysis of 
Mercury Test Data Variability in Response to Public Comments on 
Determination of the MACT Floor for Mercury Emissions'' in the docket.
    Comment: Several commenters contended that the California standards 
which the CO requirements are based on do not require CO CEMS, but 
require initial compliance testing and periodic subsequent performance 
testing.
    Response: The commenters are correct that the California CO 
regulations do not require CO CEMS. The regulations do provide sources 
with the option of conducting annual testing or installing CO CEMS to 
demonstrate compliance with the CO emission limit. Because the 
regulations that were the basis of the MACT floor do not provide 
specifics on which boilers should conduct annual testing and which 
should use CO CEMS, we reviewed the cost information provided by the 
commenters to make this determination. In considering the additional 
cost information and reviewing the cost information used in the 
proposed rule, the EPA decided that

[[Page 55237]]

changes to the CO compliance requirements were warranted. The final 
rule requires that new units with heat input capacities less than 100 
MMBtu/hr conduct initial and annual performance tests for CO emissions. 
New units with heat input capacities greater or equal to 100 MMBtu/hr 
are still required to install, operate, and maintain a CO CEMS.
    Regardless of whether the California regulations do or do not 
require CO CEMS, we would have reviewed the need for continuous 
monitoring and operating limits in order to ensure the most accurate 
indication of proper operation of the control system. The purpose of 
all of the minimum operating parameter limits in the standard is to 
ensure continuous compliance by ensuring that the air pollution control 
equipment is operating as they were during the latest performance test 
demonstrating compliance with the emission limits. The operating 
parameters are established as ``minimum'' to provide enforceable 
boundaries in their operation. Operating outside the bounds of the 
minimum parameters may lead to increased air emissions.
    The EPA would also like to clarify that operation above the CO 
limit constitutes a deviation of the work practice standard. However, 
the determination of what deviations constitute violations of the 
standard is up to the discretion of the entity responsible for 
enforcement of the standards.

F. Beyond the MACT Floor

    Comment: Many commenters contended that carbon injection should 
have been required as a beyond-the-floor option. Other commenters 
supported EPA's decision to not require any controls beyond-the-floor.
    Response: For the final rule, EPA maintains that options beyond the 
MACT floor are not appropriate for the standard. The EPA is required by 
the CAA to set the standard at a minimum on the best controlled 12 
percent of sources (for existing units) or best controlled similar 
source (for new units). The CAA also requires EPA to consider costs and 
non-air quality impacts and energy requirements when considering more 
stringent requirements than the MACT floor. As documented in the 
memorandum ``Methodology for Estimating Costs and Emissions Impacts for 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants'' in the 
docket, EPA did consider the cost and emission impacts of a variety of 
regulatory options more stringent than the MACT floor for each 
subcategory. The EPA recognizes that for some subcategories, more 
stringent controls than the MACT floor can be applied and achieve 
additional emissions reductions. However, EPA also determined that the 
cost impacts of such controls were very high. Considering both the 
costs and emissions reductions, EPA determined that it would be 
infeasible to require any options more stringent than the floor level.
    For the final rule, EPA maintains that carbon injection should not 
be required as an above the floor technology. As discussed in the 
proposal preamble, we identified one existing industrial boiler that 
was using carbon injection. The emissions data that we obtained from 
the boiler indicated that this carbon injection unit was not achieving 
mercury emissions reductions. This result led us to conclude that it 
was not the new source floor level of control. However, there may have 
been other reasons for the ineffectiveness of this system (e.g., low 
inlet mercury levels, insufficient carbon injection rate, ESP instead 
of fabric filter for PM control). Therefore, we considered carbon 
injection as a beyond-the-floor option, but decided that while this 
control technique has been used in other source categories, there is no 
demonstrated evidence that it would work for industrial boilers and 
process heaters because the type of mercury emitted and properties of 
the emission streams are sufficiently different for boilers and process 
heaters and other source categories.

G. Work Practice Requirements

    Comment: Many commenters requested EPA consider exceedences of the 
CO limit to be a trigger for corrective action rather than a violation.
    Response: In the final rule, we have clarified that an exceedence 
of the CO limit constitutes a deviation of the work practice standard. 
An observed exceedence of a monitoring parameter is not an automatic 
violation. You are required to report any deviation from an applicable 
emission limitation (including operating limit). We will review the 
information in your report along with other available information to 
determine if the deviation constitutes a violation. The determination 
of what emission or operating limit deviation constitutes violations of 
the standard is up to the discretion of the entity responsible for 
enforcement of the standard.

H. Compliance

    Comment: Many commenters requested that EPA simplify and write the 
fuel monitoring requirements to not require retesting of fuel for 
changes in fuel supplier.
    Response: We agree that the fuel monitoring requirements in the 
proposal needed to be clarified and explained further. Therefore, we 
have clarified the fuel analysis options in the final rule. If you 
elect to demonstrate compliance with the HCl, mercury, or total 
selected metals limit by using fuel which has a statistically lower 
pollutant content than the emission limit, then your operating limit is 
the emission limit of the applicable pollutant. Under this option, you 
are not required to conduct performance tests (i.e. stack tests).
    If you demonstrate compliance with the HCl, mercury, or total 
selected metals limit by using fuel with a statistically higher 
pollutant content than the applicable emission limit, but performance 
tests demonstrate that you can meet the emission limits, then your 
operating limits are the operating limits of the control device (if 
used) and the fuel pollutant content of the fuel type/mixture burned.
    The final rule specifies the testing methodology and procedures and 
the initial and continuous compliance requirements to be used when 
complying with the fuel analysis options. Fuel analysis tests for total 
chloride, gross calorific value, mercury, metal analysis, sample 
collection, and sample preparation are included in the final rule.
    If you elect to comply based on fuel analysis, you are required to 
statistically analyze, using the z-test, the data to determine the 90th 
percentile confidence level. It is the 90th percentile confidence level 
that is required to be used to determine compliance with the applicable 
emission limit. The statistical approach is required to assist in 
ensuring continuous compliance by statistically accounting for the 
inherent variability in the fuel type.
    You are required to recalculate the fuel pollutant content only if 
you burn a new fuel type or fuel mixture. You are required to conduct 
another performance test if you demonstrate compliance through 
performance testing, you burn a new fuel type or mixture, and the 
results of recalculating the fuel pollutant content are higher than the 
level established during the initial performance test.
    Comment: Many commenters requested EPA consider exceedences of

[[Page 55238]]

parametric limits to be a trigger for corrective action rather than a 
violation.
    Response: In the final rule, we have clarified that an exceedence 
of the parametric limits constitute a deviation of the operating 
limits. An observed exceedence of a monitoring parameter is not an 
automatic violation. You are required to report any deviation from an 
applicable emission limitation (including operating limit). We will 
review the information in your report along with other available 
information to determine if the deviation constitutes a violation. The 
determination of what emission or operating limit deviation constitutes 
violations of the standard is up to the discretion of the entity 
responsible for enforcement of the standard.
    Comment: Many commenters requested EPA revise the opacity 
requirements. Commenters objected to the provision in the proposed 
NESHAP that would establish an opacity ``operating limit'' based on the 
initial performance test. Some commenters contended that EPA has 
provided no data or references demonstrating a relationship between 
opacity and particulate, total metals, or mercury emissions. Other 
commenters argued that the proposed opacity limit approach for dry 
control devices is unworkable due to the inherent inability of 
continuous opacity monitors (COMS) to accurately measure opacity at 
levels less than 10 percent. Some commenters argued that the 
performance and opacity achieved during the initial test may not be 
representative of the unit's performance. Other commenters explained 
that equipment condition, fuel and operating variations, and other 
uncontrollable parameters may result in varying emissions and emissions 
control equipment efficiencies over time. Commenters suggested 
requiring the NSPS limits for opacity rather than setting opacity based 
on the initial compliance test.
    Response: We have reviewed the information provided by the 
commenters, and agree that the opacity operating limit requirements in 
the proposed rule are not appropriate for this source category. Because 
of the variability in fuels burned, the combination of fuels burned, 
and the typical operation of boilers and process heaters, we have 
decided that an opacity limit set based on the initial performance test 
may not be representative of the units typical performance.
    We have revised the opacity operating limit provision by requiring 
existing units to maintain opacity to less than or equal to 20 percent 
(based on 6-minute averages) except for one 6-minute period per hour of 
not more than 27 percent. This is the opacity limit contained in the 
current NSPS for industrial boilers, which has a similar PM emission 
limit as the final rule. Therefore, it was determined that it was 
appropriate to include a similar opacity level as the control device 
operating limit for existing units. New sources can maintain their 
opacity operating limit to less than or equal to 10 percent (based on 
1-hour block averages). This level appears to be the lowest opacity 
level currently applicable to industrial boilers in State regulations.
    Comment: Several commenters objected to the requirement to conduct 
performance testing at worst case conditions. The commenters found this 
requirement to be unrealistic because stack testing must be scheduled 
well in advance and worst-case conditions depend on fuel, load, and 
many other variables, making it impossible to assure that the testing 
will occur during worst-case conditions. Two commenters contended there 
can be no guarantee that mineral properties for a fuel source at the 
time of the baseline test can be guaranteed beyond the content 
identified during purchase contract negotiations with a fuel supplier. 
Two commenters suggested that EPA define what worst case conditions are 
because sources do not have the experience to determine worst-case 
representative process conditions.
    Response: We agree that more direction and clarification is needed 
regarding testing at worst case conditions. We have modified fuel 
sampling requirements and performance testing fuel use requirements to 
simplify compliance. During performance testing, sources are required 
to burn the type of fuel or mixture of fuel types that have the highest 
concentration of regulated HAP. This, in combination with revised fuel 
sampling requirements (e.g., based on fuel type and not on supplier, 
etc.), will simplify the determination of the fuel blend during the 
performance test. Sources are also required to conduct performance 
tests under representative full load operating conditions.
    Comment: Several commenters objected to the requirement for annual 
performance tests because they felt that it is overly burdensome given 
the ongoing compliance demonstrations required by the NESHAP. Several 
commenters suggested that initial performance testing should be 
required with subsequent performance testing occurring every 3 to 5 
years. Some commenters stated that 5-year test intervals are consistent 
with title V permits and have been allowed in other MACT standards 
(e.g. Hazardous Waste Combustors).
    Response: We have worked to minimize the testing and monitoring 
requirements of the final rule while retaining the ability to ensure 
compliance with the emission limits and work practice requirements. We 
are providing an option for sources to conduct performance testing once 
every 3 years if they conduct successful performance testing for 3 
consecutive years. We are also allowing sources to demonstrate 
compliance with the HCl, mercury, and total selected metals emission 
limits through fuel testing if they do not need emission control 
devices to achieve the standard.

I. Emissions Averaging

    In the proposal preamble, we solicited comments on an emissions 
averaging or bubbling compliance alternative, as part of the EPA's 
general policy of encouraging the use of flexible compliance approaches 
where they can be properly monitored and enforced, and whether EPA 
should include emissions averaging in the final rule. Emissions 
averaging can provide sources the flexibility to comply in the least 
costly manner while still maintaining regulation that is workable and 
enforceable. We requested comment on an averaging approach for 
determining compliance with the non-mercury metallic HAP, HCl, mercury, 
and/or PM standards for existing sources. We indicated that averaging 
would allow owners and operators to submit non-mercury metals, mercury, 
HCl, and/or PM emissions limits to the EPA Administrator for approval 
for each existing boiler in the averaging group such that if these 
emission limits are met, the total emissions from all existing boilers 
in the averaging group are less than or equal to emission limits (for 
non-mercury metals, mercury, HCl, or PM) applicable to units in the 
particular subcategory. We indicated also that averaging would not be 
applicable to new sources and could only be used between boilers and 
process heaters in the same subcategory. Also, owners or operators of 
existing sources subject to the Industrial Boiler New Source 
Performance Standards NSPS (40 CFR part 60, subparts Db and Dc) would 
be required to continue to meet the PM emission standard of that NSPS 
regardless of whether or not they are averaging.
    Emissions averaging has been incorporated into the final rule as an 
alternative means of complying with the final rule. Emissions averaging 
allows an individual affected unit emitting

[[Page 55239]]

above the allowable emission limit required by the final rule to comply 
with that emission limit by averaging its emissions with other affected 
units at the same facility emitting below the allowable emission limit 
required by the final rule.
    Comment: Many commenters supported including averaging in the final 
rule. Commenters cited numerous reasons, including cost effectiveness, 
energy efficiency, greater flexibility in compliance, and greater 
environmental benefit. Commenters also cited 40 CFR part 63, subpart 
MM, Pulping Chemical Recovery Combustion MACT as a precedent for 
including emissions averaging in MACT standards. Two commenters 
disagreed with allowing emissions averaging, stating that it would 
complicate compliance determinations, does not fit within the CAA 
mandate, and is inconsistent with the purpose of CAA section 112. Many 
of those commenters who supported emissions averaging recommended 
additional flexibility, such as including new units, and bubbling 
across subcategories.
    Response: The final rule includes an emissions averaging compliance 
alternative because emissions averaging represents an equivalent, more 
flexible, and less costly alternative to controlling certain emission 
points to MACT levels. We have concluded that a limited form of 
averaging could be implemented and not lessen the stringency of the 
standard. We agree with the commenters that some type of emissions 
averaging would provide flexibility in compliance, cost and energy 
savings to owners and operators. We also recognize that we must ensure 
that any emissions averaging option can be implemented and enforced, 
will be clear to sources, and most importantly, will achieve no less 
emissions reductions than unit by unit implementation of the MACT 
requirements.
    The final rule is not the first NESHAP to include provisions 
permitting emission averaging. In general, EPA has concluded that it is 
permissible to establish within a NESHAP a unified compliance regimen 
that permits averaging across affected units subject to the standard 
under certain conditions. Averaging across affected units is permitted 
only if it can be demonstrated that the total quantity of any 
particular HAP that may be emitted by that portion of a contiguous 
major source that is subject to the NESHAP will not be greater under 
the averaging mechanism than it would be if each individual affected 
unit complied separately with the applicable standard. Under this 
rigorous test, the practical outcome of averaging is equivalent in 
every respect to compliance by the discrete units, and the statutory 
policy embodied in the MACT floor provisions is, therefore, fully 
effectuated.
    The EPA has generally imposed certain limits on the scope and 
nature of emissions averaging programs. These limits include: (1) No 
averaging between different types of pollutants, (2) no averaging 
between sources that are not part of the same major source, (3) no 
averaging between sources within the same major source that are not 
subject to the same NESHAP, and (4) no averaging between existing 
sources and new sources.
    The final rule fully satisfies each of these criteria. Accordingly, 
EPA has concluded that the averaging of emissions across affected units 
permitted by the final rule is consistent with the CAA. In addition, 
EPA notes that the provision in the final rule that requires each 
facility that intends to utilize emission averaging to submit an 
emission averaging plan provides additional assurance that the 
necessary criteria will be followed. In this emission averaging plan, 
the facility must include the identification of (1) all units in the 
averaging group, (2) the control technology installed, (3) the process 
parameter that will be monitored, (4) the specific control technology 
or pollution prevention measure to be used, (5) the test plan for the 
measurement of particulate matter (or selected total metals), hydrogen 
chloride, or mercury emissions, and (6) the operating parameters to be 
monitored for each control device. Upon receipt, the regulatory 
authority will not approve an emission averaging plan containing 
averaging between emissions of different types of pollutants or between 
sources in different subcategories.
    The final rule excludes new affected sources from the emissions 
averaging provision. New sources have historically been held to a 
stricter standard than existing sources because it is most cost 
effective to integrate state-of-the-art controls into equipment design 
and to install the technology during construction of new sources. One 
reason we allow emissions averaging is to give existing sources 
flexibility to achieve compliance at diverse points with varying 
degrees of add-on control already in place in the most cost-effective 
and technically reasonable fashion. This concern does not apply to new 
sources which can be designed and constructed with compliance in mind.
    Only existing large solid fuel units, as defined in the final rule, 
can be included in the emissions averaging compliance alternative. Of 
the nine subcategories established for existing sources, existing large 
solid fuel units is the only subcategory for which multiple HAP 
emissions limits apply. For the existing small solid fuel subcategory 
and the six existing gaseous and liquid fuel subcategories, no HAP 
emissions limits are included in the final rule and, thus, it would not 
be appropriate to allow these units to average emissions. As for the 
existing limited use solid fuel subcategory, since these units, as 
defined in the final rule, operated on a limited basis (capacity factor 
of less than 10 percent) and are subject only to a less stringent PM 
emissions limit (as a surrogate for non-mercury metals), it would be 
inappropriate to allow these units to average emissions.
    With concern about the equivalency of emissions reductions from 
averaging and non-averaging in mind, the EPA Administrator is also 
imposing under the emission averaging provision caps on the current 
emissions from each of the sources in the averaging group. The 
emissions for each unit in the averaging group would be capped at the 
emission level being achieved on the effective date of the final rule. 
These caps would ensure that emissions do not increase above the 
emission levels that sources currently are designed, operated, and 
maintained to achieve. In the absence of performance tests, in 
documenting these caps, these sources will documented the type, design, 
and operating specification of control devices installed on the 
effective date of the final rule to ensure that existing controls are 
not removed or lessen. By including this provision in the final rule, 
the EPA Administrator has taken yet another step to assist in ensuring 
that emission averaging results in environmental benefits equivalent or 
better over what would have happened without emission averaging.
    The inclusion of emissions averaging into rules and the decision on 
how to design an emission averaging approach for a particular source 
category must be evaluated for each source category.

J. Risk-based Approach

    Comment: Multiple commenters supported EPA's incorporation of risk-
based concepts into the MACT Program. One commenter stated that 
providing risk-based applicability criteria for sources whose HAP 
emissions do not pose a significant risk is appropriate. Several 
commenters stated that there is clear legal authority in the CAA to 
construct NESHAP based on risk, and such an approach is very 
appropriate in the case of the Industrial Boiler MACT. The commenter 
also noted that the regulatory framework exists within their

[[Page 55240]]

State to implement such an approach. Several commenters added that 
risk-based alternatives will function as indirect emission limits that 
must be maintained by the facilities to assure that the criteria are 
met, and, thus, such alternatives for low-risk facilities are 
supportable by EPA's authority under section 112(d)(4) and 112(c)(9) of 
the CAA and EPA's inherent de minimis authority. Another commenter 
asserted that there are ways to structure the rule to focus on 
facilities that pose significant risks and avoid imposition of high 
costs on facilities that pose little risk. An appropriate approach 
would be to allow individual facilities to conduct a risk assessment to 
show that they pose insignificant risks to the public. However, one 
commenter stated that it is not appropriate for State and local 
programs to determine which facilities should be exempted from MACT. 
Several commenters supported a risk-based compliance alternative for 
HCl.
    Response: The EPA has determined that it can establish applicable 
health-based emission standards for HCl and manganese for affected 
sources in this category pursuant to its authority under section 
112(d)(4) of the CAA. As a result, EPA has included such standards in 
the final rule as alternative compliance requirements. Under this 
approach, affected sources can choose to comply with either the MACT-
based emission limits or the health-based emission limits. Sources 
which choose to comply with the health-based emission limit(s) will 
remain subject to those limits, but will need to comply with testing, 
monitoring and reporting requirements commensurate with the compliance 
option they have chosen. Such health-based standards are consistent 
with both the commenters' support for an approach that minimizes the 
impact on low-risk facilities and EPA's statutory mandate under section 
112.
    Section 112(d)(4) of the CAA authorizes EPA to consider established 
health thresholds, with an ample margin of safety, when promulgating 
emission standards under section 112. Hydrogen chloride and Mn are two 
pollutants for which health thresholds have been established. Issues 
concerning our legal authority to establish health-based emission 
standards under section 112(d)(4) are discussed in detail below.
    We are not using CAA section 112(c)(9) for the final rule, and 
there is no delisting of categories or subcategories, as would be 
consistent with section 112(c)(9).
    The criteria defining how affected sources demonstrate that they 
meet the threshold emissions levels for the health-based compliance 
alternative(s) is included in appendix A to the final rule. The 
criteria in appendix A to the final rule were developed for and apply 
only to the Boiler and process heater source category and are not 
applicable to other source categories. The final rule provides two ways 
that an affected source may demonstrate compliance with the health-
based emission limits. The first option is through the use of lookup 
tables which allow facilities to determine, using a limited number of 
site-specific input parameters, whether emissions from boilers and 
process heaters might cause a hazard index (HI) limit for non-
carcinogens to be exceeded. The second option is a modeling approach 
which allows those facilities that do not match the site-specific input 
parameters on which the lookup tables are based to demonstrate 
compliance with the health-based emission limits by modeling using 
site-specific information.
    The affected source will have to demonstrate that it meets the 
criteria established by today's final rule and then assume Federally 
enforceable limitations, as described in appendix A of the final rule, 
that ensure their specified HAP emissions do not subsequently increase 
to exceed levels reflected in their demonstrations.
    Comment: Multiple commenters are opposed to the risk-based 
exemptions. Some noted that the proposal to include risk-based 
exemptions is critically flawed and opposes adoption of the risk-based 
exemptions.
    One commenter stated that the inclusion of case-by-case risk-based 
exemptions into the first phase of the MACT program will negate the 
legislative mandate and jeopardize the effectiveness of the national 
air toxics program to adequately protect public health and the 
environment and to establish a level playing field. The commenter was 
very concerned that EPA referenced a fundamentally flawed 
interpretation of CAA section 112(d)(4) written by an industry (AF&PA) 
subject to regulation. Of particular concern was AF&PA's unprecedented 
proposal to include ``de minimis exemptions'' and ``cost'' in the MACT 
standard process.
    One commenter stated that the use of risk-based concepts to evade 
MACT applicability is contrary to the intent of the CAA and is based on 
a flawed interpretation of section 112(d)(4) of the CAA. The commenter 
added that the CAA requires a technology-based floor level of control 
and does not provide exclusions for risk or secondary impacts from 
applying the MACT floor.
    One commenter stated that in separate rulemakings and lawsuits, EPA 
has adopted legal positions and policies that refute and contradict the 
very risk-based and cost-based approaches contained in the proposals. 
In these other arenas, the commenter contended that EPA has properly 
rejected risk assessment to alter the establishment of MACT standards. 
The EPA also has properly rejected cost in determining MACT floors and 
in denying a basis for avoiding the MACT floor.
    Several commenters stated that the preamble discussion of the risk-
based approaches is not sufficient to allow for complete public comment 
and, therefore, it would not be appropriate for EPA to go directly to a 
final rule (without reproposal) with any of the approaches outlined in 
the proposal.
    Response: We are not identifying and deleting a subcategory of 
sources in this source category pursuant to the authority of CAA 
section 112(c)(9). Legal issues associated with the health-based 
provisions are addressed below and in the comment/response memorandum.
    As discussed above, we are, however, including in the final rule 
alternative health-based emission standards for HCl and TSM based on 
our authority under CAA section 112(d)(4). Section 112(d)(4) authorizes 
EPA to consider health thresholds, with an ample margin of safety, in 
establishing emission standards. The analysis necessary to do this can 
generally be characterized as a risk analysis. Thus, we disagree with 
the commenter that we must wait for implementation of CAA section 
112(f) before utilizing risk analysis.
    Comment: Many commenters stated that the proposal to include risk-
based exemptions is contrary to the 1990 CAA Amendments (CAAA) which 
calls for MACT standards based on technology rather than risk as a 
first step. They added that congress incorporated the residual risk 
program under CAA section 112(f) to follow the MACT standards (not to 
replace them). The commenters added that the need for the technology-
based approach has been recently reinforced by the results of the 
National Air Toxics Assessment (NATA), which indicates that exposure to 
air toxics is very high throughout the country in urban and remote 
areas. Several commenters added that risk-based approaches will be used 
separately to augment and improve technology-based standards that do 
not adequately provide protection to the public. One commenter added 
that they have been unable to substantiate the basis for EPA's support 
of the regulatory relief sought by industry through risk-based 
exemptions and that, in fact, the use of risk assessment at this stage 
of the

[[Page 55241]]

MACT program is directly opposed to title III of the CAA.
    Response: We disagree that inclusion of health-based compliance 
alternatives, in the form of emission standards based on the authority 
of section 112(d)(4) of the CAA, in the final rule is contrary to the 
1990 CAAA. The final rule is a technology-based standard developed 
using the procedures dictated by section 112 of the CAA. The only 
difference between the final rule and other MACT is that we used our 
discretion under section 112(d)(4) to base appropriate parts of the 
final rule on established health thresholds, with an ample margin of 
safety. The final rule is particularly well-suited for a health-based 
compliance alternative, established pursuant to the criteria set forth 
in section 112(d)(4). In addition to the fact that there are 
established health thresholds for HCl and manganese, EPA has determined 
that many of the facilities in this source category do not emit these 
pollutants in amounts that pose a significant risk to the surrounding 
population. Those sources that can demonstrate that the emissions of 
acid gases and manganese meet the threshold emission levels will be in 
compliance with the MACT. The criteria are based on health-protective 
estimates of risk and the threshold emission levels will provide ample 
protection of human health and the environment.
    Inclusion of health-based compliance alternatives in the final rule 
does not alter the MACT program. Rather, it merely represents EPA 
availing itself, in appropriate circumstances, of the authority 
Congress granted it in section 112(d)(4) of the CAA. We recognize that 
such provisions are only appropriate for certain HAP, and our decision-
making process required source category-specific input from 
stakeholders.
    Although the NATA modeling study may show measurable concentrations 
of toxic air pollution across the country, these data do not suggest 
that EPA should not establish health-based emission standards pursuant 
to its authority under CAA section 112(d)(4) when it determines that it 
is appropriate to do so. The alternative health-based emission 
standards included in the final rule will ensure that affected sources 
which choose to comply with those standards do not emit HCl and/or 
manganese at levels that are harmful to public health.
    Comment: Many commenters stated that the proposal to allow risk-
based exemptions would divert back to the time-consuming NESHAP 
development process that existed prior to the CAAA of 1990. The 
commenters asserted that under this process, which began with a risk 
assessment step, only eight NESHAP were promulgated during a 20-year 
period. The commenters continued that if the proposed approaches are 
inserted into upcoming standards, the commenters fear the MACT program 
(which is already far behind schedule) would be further delayed. One 
commenter supported EPA efforts to determine alternative MACT setting 
methodologies but strongly recommended that these be pursued separately 
from the final rule. The commenter contended that this will provide for 
timely issuance of final RICE and Boiler/Process Heater MACT rules 
relative to the settlement deadline. Two commenters stated that delays 
could be exacerbated by litigation following legal challenges to the 
rules, and such delays would trigger the MACT hammer, which would 
unnecessarily burden the State and local agencies and the industries. 
The commenters concluded that further delay is unacceptable. The 
commenters did not want to be in a position of implementing the CAA 
section 112(j) program and urged EPA to not delay the issuance of any 
MACT standard. The commenters noted that according to a recently 
proposed EPA rule regarding section 112(j), the regulated community and 
State and local agencies would have to proceed with part 2 permit 
applications, followed by case-by-case MACT, if EPA misses the newly 
agreed-upon MACT deadlines by as little as 2 months. This would be time 
consuming, costly, and burdensome for both regulators and the regulated 
community.
    Response: We disagree that allowing health-based compliance 
alternatives in the final rule will alter the MACT program or affect 
the schedule for promulgation of the remaining MACT standards. We do 
not anticipate any further delays in completing the remaining MACT 
standards. The setting of alternative health-based emission standards 
in the final rule affects only the final rule.
    The approach taken in the final rule is particularly well-suited to 
acid gases and manganese, which are the only pollutants included in the 
health-based compliance alternatives. For many facilities, these 
pollutants are currently emitted in amounts that do not expose anyone 
in surrounding population to concentrations above the established 
health thresholds. As a result, emissions of HCl and/or manganese at 
these facilities do not pose a significant risk to the surrounding 
population. Only those Boiler facilities that demonstrate that their 
emissions are below the health-based emission standard(s), are eligible 
for the compliance alternatives.
    Including health-based compliance alternatives for boiler sources 
does not mean that EPA will automatically provide such alternatives for 
other industries. Rather, as has been the case throughout the MACT rule 
development process, EPA will undertake in each individual rule to 
determine whether it is appropriate to exercise its discretion to use 
its authority under CAA section 112(d)(4) in developing applicable 
emission standards. The Boilers NESHAP is being promulgated by the 
February 2004 court-ordered deadline.
    Comment: Many commenters stated that the risk-based proposal 
removes the level-playing field that would result from the proper 
implementation of technology-based MACT standards. The commenters added 
that establishing a baseline level of control is essential to prevent 
industry from moving to areas of the country that have the least 
stringent air toxics programs, which was one of the primary goals of 
developing a uniform national air toxics program under section 112 of 
the 1990 CAA amendments. The risk-based approaches would jeopardize 
future reductions of HAP in a uniform and consistent manner across the 
nation.
    Response: Providing health-based compliance alternatives for 
sources that can meet them in the final rule will assure the 
application of a uniform set of requirements across the nation. The 
final rule and its criteria for demonstrating eligibility for the 
health-based compliance alternatives apply uniformly to boilers across 
the nation in the large solid fuel-fired subcategories. The final rule 
establishes a two baseline levels of emission reduction for HCl and 
manganese, one based on a traditional MACT analysis and the other based 
on EPA's evaluation of the health threat posed by emissions of these 
two pollutants. All Boiler facilities must meet one of these baseline 
levels, and all facilities with boilers in the applicable subcategories 
have the same opportunity to demonstrate that they can meet the 
alternative health-based emission standards. The criteria for 
qualifying to comply with the alternative health-based emission 
standards are not dependent on local air toxics programs. Therefore, 
concerns regarding facilities moving to areas of the country with less-
stringent air toxics programs should be alleviated.
    Comment: Multiple commenters stated that section 112(d)(4) of the 
CAA provides EPA with authority to exclude sources that emit threshold 
pollutants from regulation. The commenters indicated that section 
112(d)(4) allows for discretion in developing MACT standards for HAP 
with health

[[Page 55242]]

thresholds. The commenters added that the use of section 112(d)(4) 
authority also is supported by CAA's legislative history, which 
emphasizes that Congress included section 112(d)(4) in the CAA to 
prevent unnecessary regulation of source categories.
    One commenter pointed out that Congress does not differentiate 
between technology-based ``emission standards'' set under CAA section 
112(d)(3) versus ``health threshold'' based ``emission standards'' set 
under CAA section 112(d)(4). Instead, the statute explicitly treats 
emission standards promulgated under section 112(d)(3) and 112(d)(4) as 
equivalent by not distinguishing between those emission standards under 
the residual risk provisions of CAA section 112(f). One commenter added 
that EPA is permitted to establish alternative standards as long as it 
ensures that ambient concentrations are less than the health thresholds 
plus a margin of safety and the emissions do not cause adverse 
environmental effects. Multiple commenters pointed out that EPA has 
exercised such authority and cited the NESHAP for Chemical Recovery 
Combustion Sources at Kraft, Soda, Sulfite, and Stand-Alone 
Semichemical Pulp Mills. In addition, the commenters added that in that 
NESHAP, EPA identified circumstances in which they would decline to 
exercise 112(d)(4) authority-where significant or widespread 
environmental harm would occur as a result of emissions from the 
category and the estimated health thresholds are subject to substantial 
scientific uncertainty. The commenters concluded that EPA determined 
that these considerations were not relevant to emissions from the pulp 
and paper source category, and the commenters stated that the same is 
true for their source categories and that the same treatment is 
warranted for many facilities within the source categories. The 
commenters noted that facilities that cannot meet the risk criteria 
would remain subject to the MACT requirements.
    One commenter added that the risk-based approaches are squarely in 
line with the plain meaning of section CAA 112(d)(4). The commenters 
cited the Senate report (Sen Rep. No. 228, 101st Congress, 1st Sess 
175-6 (1990)) showed that Congress contemplated that sources within the 
same category or subcategory would be subject to varied regulatory 
requirements, depending on the risk they pose to public health. The 
commenters added that nothing in the statutory definition of ``emission 
standard'' suggests that the term is limited to a requirement for the 
installation of control technology. The commenters added that the risk-
based compliance alternatives would meet this requirement because they 
would apply to an entire source category or subcategory. The EPA could 
create a subcategory for low-risk sources and tailor an emission 
standard to this subcategory, or apply to all sources in the category a 
NESHAP containing multiple compliance options, one or more being risk-
based.
    Multiple commenters stated that the plain meaning of CAA section 
112(d)(4) does not allow EPA to make MACT standards for individual 
sources. Two commenters noted that section 112(d)(4) states that ``with 
respect to pollutants for which a health threshold has been 
established, the EPA Administrator may consider such threshold level, 
with ample margin of safety, when establishing emission standards under 
this subsection.''
    Several commenters contended that EPA has misinterpreted the 
provision in CAA section 112(d)(4) in that section 112(d)(4) does not 
state that EPA can use applicability thresholds ``in lieu of'' the CAA 
section 112(d)(3) MACT floor requirements. The commenter interpreted 
section 112(d)(4) to state that health based thresholds can be 
considered when establishing the degree of the MACT floor requirements, 
but it should not be used to supplant the requirements established 
pursuant to section 112(d)(3).
    Many commenters stated that the legislative history of CAA section 
112(d)(4) clearly rejects EPA's proposed facility-by-facility MACT 
exemptions. The commenters noted that Congress considered and rejected 
the applicability cutoffs upon which EPA now solicits comment. The 
commenters noted that the House version of the 1990 Amendments allowed 
States to issue permits that exempted a source from compliance with 
MACT rules if the source presented sufficient evidence to demonstrate 
negligible risk, and the Senate version of the 1990 Amendments 
contained no such provision. In conference, Congress considered both 
the House and Senate versions and rejected the House bill's exemption 
for specific facilities in favor of the Senate bill's language.
    Response: The EPA has properly exercised the authority granted to 
it pursuant to CAA section 112(d)(4) of the CAA in establishing health-
based emission standards for HCl and manganese which are applicable to 
the large solid fuel-fired subcategory. Section 112(d)(4) authorizes it 
to by-pass the mandate in section 112(d)(3) in appropriate 
circumstances. Those circumstances are present in the large solid fuel-
fired Boiler subcategories.
    Section 112(d)(4) of the CAA provides EPA with authority, at its 
discretion, to develop health-based emission standards for HAP ``for 
which a health threshold has been established,'' provided that the 
standard reflects the health threshold ``with an ample margin of 
safety.'' (The full text of the section 112(d)(4): ``[with respect to 
pollutants for which a health threshold has been established, the 
Administrator may consider such threshold level, within an ample margin 
of safety, when establishing emission standards under this 
subsection.'')
    Both the plain language of CAA section 112(d)(4) and the 
legislative history cited above indicate that EPA has the discretion 
under section 112(d)(4) to develop health-based standards for some 
source categories emitting threshold pollutants, and that those 
standards may be less stringent than the corresponding ``floor''-based 
MACT standard would be. The EPA's use of such standards is not limited 
to situations where every source in the category or subcategory can 
comply with them. As is the case with technology-based standards, a 
particular source's ability to comply with a health-based standard will 
depend on its individual circumstances, as will what it must do to 
achieve compliance.
    In developing health-based emission standards under CAA section 
112(d)(4), EPA seeks to assure that those standards ensure that the 
concentration of the particular HAP to which an individual exposed at 
the upper end of the exposure distribution is exposed does not exceed 
the health threshold. The upper end of the exposure distribution is 
calculated using the ``high end exposure estimate,'' defined as ``a 
plausible estimate of individual exposure for those persons at the 
upper end of the exposure distribution, conceptually above the 90th 
percentile, but not higher than the individual in the population who 
has the highest exposure'' (EPA Exposure Assessment Guidelines, 57 FR 
22888, May 29, 1992). Assuring protection to persons at the upper end 
of the exposure distribution is consistent with the ``ample margin of 
safety'' requirement in section 112(d)(4).
    We agree that section 112(d)(4) is appropriate for establishing 
emission standards for HCl and manganese applicable to the large solid 
fuel-fired subcategories, and, therefore, we have established such 
standards as an alternate compliance requirement for affected sources 
in those subcategories. Affected sources in the large solid fuel-fired 
subcategories which believe that

[[Page 55243]]

they can demonstrate compliance with one or both of the health-based 
emission standards may choose to comply with those standards in lieu of 
the otherwise applicable MACT-based standard.
    For purposes of the final rule, we are not considering background 
HAP emissions in developing the section CAA 112(d)(4) compliance 
alternatives. As we indicated in the Residual Risk Report to Congress, 
however, the Agency intends to consider facility-wide HAP emissions in 
future CAA section 112(f) residual risk actions.
    Comment: Many commenters contended that the proposal will place a 
very intensive resource demand on State and local agencies to review 
source's risk assessments, and State/local agencies may not have 
expertise in risk assessment methodology or the resources needed to 
verify information (e.g., emissions data and stack parameters) 
submitted with each risk assessment.
    Other commenters stated that a risk-based program can be structured 
and implemented in a manner that does not adversely impact limited 
State resources. One commenter asserted that EPA should work closely 
with States and industry to implement the risk-based approach in a non-
burdensome manner. Another commenter stated that the risk-based 
approaches, like other MACT standards, would simply be incorporated 
into each State's existing title V program. The commenter concluded 
that because the title V framework already exists, the addition of a 
risk-based MACT standard would not require States to overhaul existing 
permitting programs. Another commenter contended that the final MACT 
rule itself should set forth the applicability criteria--including the 
threshold levels of exposure--that sources must meet to qualify for a 
risk-based determination. Each source would have the burden of 
demonstrating that its exposures are below this limit and, therefore, 
the States would not be required to develop their own risk assessment 
guidance or to conduct source-specific risk assessments.
    Response: The health-based emission limits for HCl and TSM which 
EPA has adopted in the final rule should not impose significant 
resource burdens on States. Further, the required compliance 
demonstration methodology is structured in such a way as to avoid the 
need for States to have significant expertise in risk assessment 
methodology. We have considered the commenters' concerns in developing 
the criteria defining eligibility for these compliance alternatives, 
and the approach that is included in the final rule provides clear, 
flexible requirements and enforceable compliance parameters. The final 
rule provides two ways that a facility may demonstrate eligibility for 
complying with the alternative health-based emission standard. First, 
look-up tables, which are included as Tables 2 (HCl) and 3 (manganese) 
in appendix A of the final rule, allow facilities to determine, using a 
limited number of site-specific input parameters, whether emissions 
from their sources might cause a hazard index limit (hazard quotient in 
the case of manganese) to be exceeded. If a facility cannot demonstrate 
eligibility using a look-up table, a modeling approach can be followed. 
Appendix A to the final rule presents the criteria for performing this 
modeling.
    Regarding commenters' concerns with looking for a threshold level 
for carcinogens, the compliance alternatives only apply to HCl and 
manganese, which are not currently expected to be carcinogens. Also, 
the concern expressed by a commenter about exempting a facility based 
on limited emission data if EPA established a subcategory listing low-
risk sources is not relevant here, because we have not used CAA section 
112(c)(9) authority to establish a low-risk subcategory for the 
Industrial/Commercial/Institutional Boilers and Process Heaters source 
category. With respect to guidance for performing site-specific 
modeling, all of the procedures for performing such modeling are 
available in peer-reviewed scientific literature and, therefore, no 
additional guidance needs to be developed.
    Only a portion of the major facilities in the large solid fuel-
fired boilers and process heaters subcategory will submit eligibility 
demonstrations for the compliance alternatives. Of this portion of 
major sources, most will be able to demonstrate eligibility based on 
simple analyses (e.g., using the look-up tables provided in appendix A 
of the final rule). However, it is likely that some facilities will 
require more detailed modeling. The criteria for demonstrating 
eligibility for the compliance alternatives are clearly spelled out in 
the final rule. Because these requirements are clearly spelled out and 
because any standards or requirements created under CAA section 112 are 
considered applicable requirements under 40 CFR part 70, the compliance 
alternatives would be incorporated into title V programs, and States 
would not have to overhaul existing permitting programs.
    Finally, with respect to the burden associated with ongoing 
assurance that facilities which opt to do so continue to comply with 
the health-based compliance alternatives, the burden to States will be 
minimal. In accordance with the provisions of title V of the CAA and 
part 70 of 40 CFR (collectively ``title V''), the owner or operator of 
any affected source opting to comply with the health-based emission 
standards will be required to certify compliance with those standards 
on an annual basis. Additionally, before changing key parameters that 
may impact an affected source's ability to continue to meet one or both 
of the health-based emission standards, the affected source is required 
to evaluate its ability to continue to comply with the health-based 
emission standard(s) and submit documentation to the permitting 
authority supporting continued eligibility for the compliance 
alternative.
    The promulgation of specific alternative health-based emission 
limits and a uniform methodology for demonstrating compliance with 
those alternatives alleviates any concern regarding the public process 
required in reviewing/approving the proposed approaches and making 
substantial changes to existing regulations. It also addresses concerns 
regarding the costs and resources associated with assuring adequate 
public participation in the process of reviewing site-specific risk 
analyses.
    To ensure that affected sources which choose to comply with the 
alternative health-based emission standards continue to comply with 
those standards after the initial compliance demonstration, specified 
assessment parameters (e.g., HCl and/or manganese emission rate, boiler 
heat output, etc.) must be included in their title V permit as 
enforceable requirements. Draft permits and permit applications must be 
made available to the public from the State or local agency responsible 
for issuing the permit, or in the case where EPA is issuing the permit, 
from the EPA regional office. Members of the public may request that 
the State or local agency include them on their public notice mailing 
list, thus providing the public the opportunity to review the 
appropriateness of these requirements. Every proposed title V permit 
has a 30-day public comment period and a 45-day EPA review period. If 
EPA does not object to the permit, any member of the public may 
petition EPA to object to the permit within 60 days of the end of the 
EPA review period.
    Comment: A commenter contended that exempting HCl emissions from 
control is inappropriate, particularly since EPA proposed HCl as a 
surrogate measure for all the inorganic HAP

[[Page 55244]]

emitted by this source category. Hence, an exemption that excluded HCl 
emission points from control requirements would also exclude emissions 
of all the other inorganic HAP that would likely include hydrogen 
cyanide and hydrogen fluoride.
    Response: Facilities attempting to utilize the health-based 
compliance alternative for HCl will not be required to evaluate 
emissions of other inorganic HAP except for chlorine. We conducted an 
assessment of boiler emissions and determined that, of the acid gas HAP 
controlled by scrubbing technology, chlorine is responsible for the 
great majority of risk and HCl is responsible for the next largest 
portion of the total risk. The contributions of other HAP, including 
hydrogen fluoride, to the total risk were negligible. Therefore, 
facilities attempting to demonstrate eligibility for the health-based 
compliance alternative for HCl, either by conducting a lookup table 
analysis or by conducting a site-specific compliance demonstration, 
must include emission rates of chlorine and HCl from their boilers. We 
do not expect hydrogen cyanide emissions from boilers covered under the 
final rule.
    Comment: Commenters stated that the proposal does not address 
ecological risk that may result from uncontrolled HAP emissions, 
especially in those areas with sensitive habitats but few people nearby 
to be exposed and that EPA provided inadequate discussion of how 
environmental risks will be evaluated.
    Response: To identify HAP with potential to cause multimedia and/or 
environmental effects, the EPA has identified HAP with significant 
potential to persist in the environment and to bioaccumulate. This list 
does not include HCl or manganese which are the only HAP with health-
based compliance alternatives in the final rule. Additionally, a 
screening level analysis conducted by the EPA indicates that acute 
impacts of these HAP from industrial boiler facilities are highly 
unlikely. For these reasons we do not believe that emissions of HCl or 
manganese from industrial boiler facilities will pose a significant 
risk to the environment and facilities attempting to comply with the 
health-based alternatives for these HAP are not required to perform an 
ecological assessment.

V. Impacts of the Final Rule

A. What Are the Air Impacts?

    Nationwide emissions of selected HAP (i.e., HCl, hydrogen fluoride, 
lead, and nickel) will be reduced by 58,500 tpy for existing units and 
73 tpy for new units. Depending on the number of facilities 
demonstrating eligibility for the health-based compliance alternatives, 
the total HAP reduction for existing units could be 50,600 tpy. 
Emissions of HCl will be reduced by 42,000 tpy for existing units and 
72 tpy for new units. Depending on the number of facilities 
demonstrating eligibility for the health-based compliance alternatives, 
the total HCl emissions reduction for existing units could be 36,400 
tpy. Emissions of mercury will be reduced by 1.9 tpy for existing units 
and 0.006 tpy for new units. Emissions of PM will be reduced by 565,000 
tpy for existing units and 480 tpy for new units. Depending on the 
number of facilities demonstrating eligibility for the health-based 
compliance alternatives, the total PM emissions reduction for existing 
units could be 547,000 tpy. Emissions of total selected nonmercury 
metals (i.e., arsenic, beryllium, cadmium, chromium, lead, manganese, 
nickel, and selenium) will be reduced by 1,100 tpy for existing units 
and will be reduced by 1.4 tpy for new units. Depending on the number 
of facilities demonstrating eligibility for the health-based compliance 
alternatives, the total nonmercury metals emissions reduction for 
existing units could be 950 tpy. In addition, emissions of sulfur 
dioxide (SO2) are established to be reduced by 113,000 tpy 
for existing sources and 110 tpy for new sources. Depending on the 
number of facilities demonstrating eligibility for the health-based 
compliance alternatives, the total SO2 emissions reduction 
for existing units could be 49,000 tpy.
    As noted above, use of the health-based compliance alternatives by 
eligible facilities will affect reductions in HAP, PM (and total non-
mercury metals that are generally controlled along with PM), and 
SO2. Nevertheless, our analysis indicates that the 
difference in emissions of HCl and manganese with and without the 
compliance alternatives will not affect health risks because the 
compliance alternative is available only to those facilities that 
demonstrate that their emissions pose little risks. Emissions of PM and 
SO2 will still be reduced by the implementation of other 
provisions of the Clean Air Act, such as attainment of the health-based 
National Ambient Air Quality Standards, which include mechanisms to 
control such emissions.
    A discussion of the methodology used to estimate emissions and 
emissions reductions is presented in ``Estimation of Baseline Emissions 
and Emissions Reductions for Industrial, Commercial, and Institutional 
Boilers and Process Heaters'' in the docket. To estimate the potential 
impacts of the health-based compliance alternatives, we performed a 
preliminary ``rough'' assessment of the large solid fuel subcategory to 
determine the extent to which facilities might become eligible for the 
health-based compliance alternatives. Based on the results of this 
rough assessment, 448 coal-fired boilers could potentially be eligible 
for the HCl compliance alternative and 386 biomass-fired boilers could 
be potentially eligible for the TSM compliance alternative.

B. What Are the Water and Solid Waste Impacts?

    The EPA estimates the additional water usage that would result from 
the MACT floor level of control to be 110 million gallons per year for 
existing sources and 0.6 million gallons per year for new sources. In 
addition to the increased water usage, an additional 3.7 million 
gallons per year of wastewater will be produced for existing sources 
and 0.6 million gallons per year for new sources. The costs of treating 
the additional wastewater are $18,000 for existing sources and $2,300 
for new sources, in advance of any facility demonstrating eligibility 
for the health-based compliance alternatives. These costs are accounted 
for in the control costs estimates.
    The EPA estimates the additional solid waste that would result from 
the MACT floor level of control to be 102,000 tpy for existing sources 
and 1 tpy for new sources. The estimated costs of handling the 
additional solid waste generated are $1.5 million for existing sources 
and $17,000 for new sources, in advance of any facility demonstrating 
eligibility for the health-based compliance alternatives. These costs 
are also accounted for in the control costs estimates.
    A discussion of the methodology used to estimate impacts is 
presented in ``Estimation of Impacts for Industrial, Commercial, and 
Institutional Boilers and Process Heaters NESHAP'' in the docket.

C. What Are the Energy Impacts?

    The EPA expects an increase of approximately 1,130 million kilowatt 
hours (kWh) in national annual energy usage as a result of the final 
rule, in advance of any facility demonstrating eligibility for the 
health-based compliance alternatives. Of this amount, 1,120 million kWh 
is estimated from existing sources and 13 million kWh is estimated from 
new sources. The increase results from the electricity required to 
operate control devices

[[Page 55245]]

installed to meet the final rule, such as wet scrubbers and fabric 
filters.

D. What Are the Control Costs?

    To estimate the national cost impacts of the final rule for 
existing sources, EPA developed several model boilers and process 
heaters and determined the cost of control equipment for these model 
boilers. The EPA assigned a model boiler or heater to each existing 
unit in the database based on the fuel, size, design, and current 
controls. The analysis considered all air pollution control equipment 
currently in operation at existing boilers and process heaters. Model 
costs were then assigned to all existing units that could not otherwise 
meet the proposed emission limits. The resulting total national cost 
impact of the final rule is $1,790 million in capital expenditures and 
$860 million per year in total annual costs. Depending on the number of 
facilities demonstrating eligibility for the health-based compliance 
alternatives, these costs could be $1,440 million in capital 
expenditures and $690 million per year in total annual costs. The total 
capital and annual costs include costs for testing, monitoring, and 
recordkeeping and reporting. Costs include testing and monitoring 
costs, but not recordkeeping and reporting costs.
    Using Department of Energy projections on fuel expenditures, EPA 
estimated the number of additional boilers that could be potentially 
constructed. The resulting total national cost impact of the final rule 
in the 5th year is $58 million in capital expenditures and $18.6 
million per year in total annual costs, in advance of any facility 
demonstrating eligibility for the health-based provisions. Costs are 
mainly for testing and monitoring.
    A discussion of the methodology used to estimate cost impacts is 
presented in ``Methodology for Estimating Control Cost for the 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants'' in the 
docket.

E. What Are the Economic Impacts?

    The economic impact analysis shows that the expected price increase 
for output in the 40 affected industries would be no more than 0.04 
percent as a result of the final rule for industrial boilers and 
process heaters. The expected change in production of affected output 
is a reduction of only 0.03 percent or less in the same industries. In 
addition, impacts to affected energy markets show that prices of 
petroleum, natural gas, electricity and coal should increase by no more 
than 0.05 percent as a result of implementation of the final rule, and 
output of these types of energy should decrease by no more than 0.01 
percent. These impacts are generated in advance of any facility 
demonstrating eligibility for the health-based compliance alternatives. 
Depending on the number of affected facilities demonstrating 
eligibility for the health-based compliance alternatives, these impacts 
on product prices could fall to a 0.03 percent increase, and a decrease 
in output of the energy types mentioned previously of less than 0.01 
percent. Therefore, it is likely that there is no adverse impact 
expected to occur for those industries that produce output affected by 
the final rule, such as lumber and wood products, chemical 
manufacturers, petroleum refining, and furniture manufacturing.

F. What Are the Social Costs and Benefits of the Final Rule?

    Our assessment of costs and benefits of the final rule is detailed 
in the ``Regulatory Impact Analysis for the Final Industrial, 
Commercial, and Institutional Boilers and Process Heaters MACT.'' The 
Regulatory Impact Analysis (RIA) is located in the Docket.
    It is estimated that 3 years after implementation of the final 
rule, HAP will be reduced by 58,500 tpy (53,200 megagrams per year (Mg/
yr)) due to reductions in arsenic, beryllium, HCl, and several other 
HAP from existing affected emission sources. Of these reductions, 
42,000 tpy (38,200 Mg/yr) are of HCl. In addition to these reductions, 
there are 73 tpy (66 Mg/yr) of HAP reductions expected from new 
sources. Of these reductions, virtually all of them are of HCl. The 
health effects associated with these HAP are discussed earlier in this 
preamble. While it is beneficial to society to reduce these HAP, we are 
unable to quantify and provide a monetized estimate of the benefits at 
this time.
    Despite our inability to quantify and provide monetized benefit 
estimates from HAP reductions, it is possible to derive rough estimates 
for one of the more important benefit categories, i.e., the potential 
number of cancer cases avoided and cancer risk reduced as a result of 
the imposition of the MACT level of control on this source category. 
Our analysis suggests that imposition of the MACT level of control 
would reduce cancer cases at worst case baseline assumptions by 
possibly tens of cases per year, on average, starting some years after 
implementation of the final rule. This risk reduction estimate is 
uncertain, is likely to overestimate benefits, and should be regarded 
as an extremely rough estimate. Furthermore, the estimate should be 
viewed in the context of the full spectrum of unquantified noncancer 
effects associated with the HAP reductions. Noncancer effects 
associated with the HAP are presented earlier in this preamble.
    The control technologies used to reduce the level of HAP emitted 
from affected sources are also expected to reduce emissions of PM 
(PM10, PM2.5), and sulfur dioxide 
(SO2). It is estimated that PM10 emissions 
reductions total approximately 562,000 tpy (510,000 Mg/yr), 
PM2.5 emissions reductions total approximately 159,000 tpy 
(145,000 Mg/yr), and SO2 emissions reductions total 
approximately 113,000 tpy (102,670 Mg/yr). These estimated reductions 
occur from existing sources in operation 3 years after the 
implementation of the requirements of the final rule and are expected 
to continue throughout the life of the sources.
    In general, exposure to high concentrations of PM may aggravate 
existing respiratory and cardiovascular disease including asthma, 
bronchitis and emphysema, especially in children and the elderly. 
SO2 is also a contributor to acid deposition, or acid rain, 
which causes acidification of lakes and streams and can damage trees, 
crops, historic buildings and statues. Exposure to PM2.5 can 
lead to decreased lung function, and alterations in lung tissue and 
structure and in respiratory tract defense mechanisms which may then 
lead to, increased respiratory symptoms and disease, or in more severe 
cases, premature death or increased hospital admissions and emergency 
room visits. Children, the elderly, and people with cardiopulmonary 
disease, such as asthma, are most at risk from these health effects. 
Fine PM can also form a haze that reduces the visibility of scenic 
areas, can cause acidification of water bodies, and have other impacts 
on soil, plants, and materials. As SO2 emissions transform 
into PM, they can lead to the same health and welfare effects listed 
above.
    For PM10 and PM2.5 (including SO2 
contributions to ambient concentrations of PM2.5), we 
provide a monetary estimate for the benefits associated with the 
reduction in emissions associated with the final rule. To do so, we 
conducted an air quality assessment to determine the change in ambient 
concentrations of PM10 and PM2.5 that result from 
reductions of PM and SO2 at existing affected facilities. 
Unfortunately, our data are not able to define the exact location of 
the reductions for every affected boiler and process heater. Because of 
this

[[Page 55246]]

limitation, the benefits assessment is conducted in two phases. First, 
an air quality analysis was conducted for emissions reductions from 
those emissions sources that have an known link to a specific control 
device, which represents approximately 50 percent of the total 
emissions reductions mentioned above. Using this subset of information, 
we determined the air quality change nationwide. The results of the air 
quality assessment served as input to a model that estimates the total 
monetary value of benefits of the health effects listed above. Total 
benefits associated with this portion of the analysis (in phase one) 
are $8.2 billion in the year 2005 (presented in 1999 dollars).
    In the second phase of our analysis, for those emissions reductions 
from affected sources that do not have a known link to a specific 
control device, the results of the air quality analysis in phase one 
serve as a reasonable approximation of air quality changes to transfer 
to the remaining emissions reductions of the final rule. Because there 
is not a reasonable way to apportion the total benefits of the combined 
impact of the PM and SO2 reductions from the air quality and 
benefit analyses completed above, we performed two additional air 
quality analyses. One analysis was performed to evaluate the impact on 
air quality of the PM reductions alone (holding SO2 
unchanged), and one to evaluate the impact on air quality from the 
SO2 reductions alone (holding PM unchanged). With 
independent PM and SO2 air quality assessments, we can 
determine the total benefit associated with each component of total 
pollutant reductions. The total benefit associated with the PM and 
SO2 reductions with unspecified location (in phase two) are 
$7.9 billion.
    The benefit estimates derived from the air quality modeling in the 
first phase of our analysis uses an analytical structure and sequence 
similar to that used in the benefits analyses for the proposed Nonroad 
Diesel rule and proposed Integrated Air Quality Rule (IAQR) and in the 
``section 812 studies'' analysis of the total benefits and costs of the 
Clean Air Act. We used many of the same models and assumptions used in 
the Nonroad Diesel and IAQR analyses as well as other Regulatory Impact 
Analyses (RIAs) prepared by the Office of Air and Radiation. By 
adopting the major design elements, models, and assumptions developed 
for the section 812 studies and other RIAs, we have largely relied on 
methods which have already received extensive review by the independent 
Science Advisory Board (SAB), the National Academies of Sciences, by 
the public, and by other federal agencies.
    The benefits transfer method used in the second phase of the 
analysis is similar to that used to estimate benefits at the proposal 
of the rule, and in the proposed Reciprocating Internal Combustion 
Engines NESHAP. A similar method has also been used in recent benefits 
analyses for the proposed Nonroad Large Spark-Ignition Engines and 
Recreational Engines standards (67 FR 68241, November 8, 2002).
    The sum of benefits from the two phases of analysis provide an 
estimate of the total benefits of the rule. Total benefits of the final 
rule are approximately $16.3 billion (1999$). This economic benefit is 
associated with approximately 2,270 avoided premature mortalities, 
5,100 avoided cases of chronic bronchitis, thousands of avoided 
hospital and emergency room visits for respiratory and cardiovascular 
diseases, tens of thousands of avoided days with respiratory symptoms, 
and millions of avoided work loss and restricted activity days. This 
estimate is generated in advance of any facility demonstrating 
eligibility for the health-based compliance alternatives.
    Every benefit-cost analysis examining the potential effects of a 
change in environmental protection requirements is limited, to some 
extent, by data gaps, limitations in model capabilities (such as 
geographic coverage), and uncertainties in the underlying scientific 
and economic studies used to configure the benefit and cost models. 
Deficiencies in the scientific literature often result in the inability 
to estimate changes in health and environmental effects. Deficiencies 
in the economics literature often result in the inability to assign 
economic values even to those health and environmental outcomes that 
can be quantified. While these general uncertainties in the underlying 
scientific and economics literatures are discussed in detail in the RIA 
and its supporting documents and references, the key uncertainties 
which have a bearing on the results of the benefit-cost analysis of 
today's action are the following:
    1. The exclusion of potentially significant benefit categories 
(e.g., health and ecological benefits of reduction in hazardous air 
pollutants emissions);
    2. Errors in measurement and projection for variables such as 
population growth;
    3. Uncertainties in the estimation of future year emissions 
inventories and air quality;
    4. Uncertainties associated with the extrapolation of air quality 
monitoring data to some unmonitored areas required to better capture 
the effects of the standards on the affected population;
    5. Variability in the estimated relationships of health and welfare 
effects to changes in pollutant concentrations; and
    6. Uncertainties associated with the benefit transfer approach.
    7. Uncertainties in the size of the effect estimates linking air 
pollution and health endpoints.
    8. Uncertainties about relative toxicity of different components 
within the complex mixture.
    Despite these uncertainties, we believe the benefit-cost analysis 
provides a reasonable indication of the expected economic benefits of 
the final rule under a given set of assumptions.
    Based on estimated compliance costs (control + administrative costs 
associated with Paperwork Reduction Act requirements associated with 
the rule and predicted changes in the price and output of electricity), 
the estimated annualized social costs of the Industrial, Commercial, 
and Institutional Boilers and Process Heaters NESHAP are $863 million 
(1999$). Depending on the number of affected facilities demonstrating 
eligibility for the health-based compliance alternatives, these 
annualized social costs could fall to $746 million. Social costs are 
different from compliance costs in that social costs take into account 
the interactions between affected producers and the consumers of 
affected products in response to the imposition of the compliance 
costs.
    As explained above, we estimate $16.3 billion in benefits from the 
final rule, compared to $863 million in costs. It is important to put 
the results of this analysis in the proper context. The large benefit 
estimate is not attributable to reducing human and environmental 
exposure to the HAPs that are reduced by this rule. It arises from 
ancillary reductions in PM and SO2 that result from controls 
aimed at complying with the NESHAP. Although consideration of ancillary 
benefits is reasonable, we note that these benefits are not uniquely 
attributable to the regulation. The Agency believes nonetheless that 
the key rationale for controlling arsenic, beryllium, HCl, and the 
other HAPs associated with this rule is to reduce public and 
environmental exposure to these HAPs, thereby reducing risk to public 
health and wildlife. Although the available science does not support 
quantification of these benefits at this time, the Agency believes the 
qualitative

[[Page 55247]]

benefits are large enough to justify substantial investment in these 
emission reductions.
    It should be recognized, however, that this analysis does not 
account for many of the potential benefits that may result from these 
actions. Thus, our estimate of total benefits also includes a ``B'' to 
represent those additional health and environmental benefits which 
could not be expressed in quantitative incidence and/or economic value 
terms. The net benefits would be greater if all the benefits of the 
other pollutant reductions could be quantified. Notable omissions to 
the net benefits include all benefits of HAP reductions, including 
reduced cancer incidences, toxic morbidity effects, and cardiovascular 
and CNS effects, and all welfare effects from reduction of ambient PM 
and SO2. A full appreciation of the overall economic 
consequences of the industrial boiler and process heater standards 
requires consideration of all benefits and costs expected to result 
from the final rule, not just those benefits and costs that could be 
expressed here in dollar terms. A full listing of the benefit 
categories that could not be quantified or monetized in our base 
estimate are provided in Table 2 of this preamble.

                                    Table 2.--Unquantified Benefit Categories
----------------------------------------------------------------------------------------------------------------
                                                Unquantified benefit categories  Unquantified benefit categories
                                                associated with HAP  reductions   associated with PM  reductions
----------------------------------------------------------------------------------------------------------------
Health Categories............................  --Airway responsiveness.........  --Changes in pulmonary
                                               --Pulmonary inflammation........   function.
                                               --Susceptibility to respiratory   --Morphological changes.
                                                infection.                        Altered host defense
                                               --Acute inflammation and           mechanisms.
                                                respiratory cell damage.         --Other chronic respiratory
                                               --Chronic respiratory damage/      disease.
                                                Premature aging of lungs.        --Emergency room visits for
                                               --Emergency room visits for        asthma.
                                                asthma.                          --Emergency visits for non-
                                                                                  asthma respiratory and
                                                                                  cardiovascular causes.
                                                                                 --Lower and upper respiratory
                                                                                  systems.
                                                                                 --Acute bronchitis.
                                                                                 --Shortness of breath.
Welfare Categories...........................  --Ecosystem and vegetation        --School absence rates.
                                                effects.                         --Materials damage.
                                               --Damage to urban ornamentals     --Damage to ecosystems (e.g.,
                                                (e.g., grass, flowers, shrubs,    acid sulfate deposition).
                                                and trees in urban areas).       --Nitrates in drinking water.
                                               --Commercial field crops........  --Visibility in recreational
                                               --Fruit and vegetable crops.....   and residential areas.
                                               --Yields of tree seedlings,
                                                commercial and non-commercial
                                                forests.
                                               --Damage to ecosystems..........
                                               --Materials damage..............
----------------------------------------------------------------------------------------------------------------

    Using the results of the benefit analysis, we can use benefit-cost 
comparison (or net benefits) as another tool to evaluate the 
reallocation of society's resources needed to address the pollution 
externality created by the operation of industrial boilers and process 
heaters. The additional costs of internalizing the pollution produced 
at major sources of emissions from industrial boilers and process 
heaters are compared to the improvement in society's well-being from a 
cleaner and healthier environment. Comparing benefits of the final rule 
to the costs imposed by alternative ways to control emissions optimally 
identifies a strategy that results in the highest net benefit to 
society. In the final rule, we include only one option, the minimal 
level of control mandated by the CAA, or the MACT floor. Other 
alternatives that lead to higher levels of control (or beyond-the-floor 
alternatives) lead to higher estimates of benefits net of costs, but 
also lead to additional economic impacts, including more substantial 
impacts to small entities. For more details, please refer to the RIA 
for the final rule.
    Based on estimated compliance costs associated with the final rule 
and the predicted change in prices and production in the affected 
industries, the estimated annualized social costs of the final rule are 
$863 million (1999 dollars). This estimate of social cost is generated 
in advance of any facility demonstrating eligibility for the health-
based compliance alternatives. Depending on the number of affected 
facilities demonstrating eligibility for the health-based compliance 
alternatives, these annualized social costs could fall to $746 million. 
Social costs are different from compliance costs in that social costs 
take into account the interactions of consumers and producers of 
affected products in response to the imposition of the compliance 
costs. Therefore, the Agency's estimate of monetized benefits net of 
costs is $15.4 billion + B (1999 dollars) in 2005.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the EPA 
must determine whether a regulatory action is ``significant'' and, 
therefore, subject to review by the OMB and the requirements of the 
Executive Order. The Executive Order defines ``significant regulatory 
action'' as one that is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs, or the rights and obligation of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, the EPA has 
determined that the final rule is a ``significant regulatory action'' 
because it has an annual effect on the economy of over $100 million. As 
such, the final rule was submitted to OMB for review.

[[Page 55248]]

B. Paperwork Reduction Act

    The information collection requirements in the final rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
information collection requirements are not enforceable until OMB 
approves them.
    The information requirements are based on notification, 
recordkeeping, and reporting requirements in the NESHAP General 
Provisions (40 CFR part 63, subpart A), which are mandatory for all 
operators subject to national emission standards. These recordkeeping 
and reporting requirements are specifically authorized by section 114 
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant 
to the recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to Agency policies set 
forth in 40 CFR part 2, subpart B.
    The final rule requires maintenance inspections of the control 
devices, but does not require any notifications or reports beyond those 
required by the General Provisions. The recordkeeping requirements 
require only the specific information needed to determine compliance.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the final rule) is estimated to be $91 million. This includes 1.2 
million labor hours per year at a total labor cost of $67 million per 
year, and total non-labor capital costs of $24 million per year. This 
estimate includes a one-time performance test, semiannual excess 
emission reports, maintenance inspections, notifications, and 
recordkeeping. The total burden for the Federal government (averaged 
over the first 3 years after the effective date of the final rule) is 
estimated to be 346,000 hours per year at a total labor cost of $14 
million per year. Table 3 of this preamble shows the average annualized 
burden for monitoring, reporting, and recordkeeping for each 
subcategory.

                       Table 3.--Summary of the Average Reporting and Recordkeeping Costs
----------------------------------------------------------------------------------------------------------------
                                                               Total labor      Total capital
                        Subcategory                             costs ($)         costs ($)      Total costs ($)
----------------------------------------------------------------------------------------------------------------
Large Solid Fuel Units....................................        56,253,000        12,488,000        68,741,000
Limited Use Solid Fuel Units..............................         2,565,000         2,267,000         4,832,000
Small Solid Fuel Units....................................           627,000           111,000           738,000
Large Liquid Fuel Units...................................           498,000           491,000           989,000
Limited Use Liquid Fuel Units.............................           214,000           264,000           478,000
Small Liquid Fuel Units...................................           442,000                 0           442,000
Large Gaseous Fuel Units..................................         3,673,000         6,615,000        10,288,000
Limited Use Gaseous Fuel Units............................           663,000         1,209,000         1,872,000
Small Gaseous Fuel Units..................................         2,413,000                 0         2,413,000
----------------------------------------------------------------------------------------------------------------

    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9. When this ICR is approved by 
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in 
the Federal Register to display the OMB control number for the approved 
information collection requirements contained in this final rule.
    The EPA requested comments on the need for this information, the 
accuracy of the provided burden estimates, and any suggested methods 
for minimizing respondent burden, including through the use of 
automated collection techniques.

C. Regulatory Flexibility Act

    The EPA has determined that it is not necessary to prepare a 
regulatory flexibility analysis in connection with the final rule. We 
have also determined that the final rule will not have a significant 
impact on a substantial number of small entities.
    For purposes of assessing the impacts of the final rule on small 
entities, small entity is defined as:
    (1) A small business according to Small Business Administration 
size standards by the North American Industry Classification System 
(NAICS) category of the owning entity. The range of small business size 
standards for the 40 affected industries ranges from 500 to 1,000 
employees, except for petroleum refining and electric utilities. In 
these latter two industries, the size standard is 1,500 employees and a 
mass throughput of 75,000 barrels/day or less, and 4 million kilowatt-
hours of production or less, respectively;
    (2) A small governmental jurisdiction that is a government of a 
city, county, town, school district or special district with a 
population of less than 50,000; and
    (3) A small organization that is any not-for-profit enterprise that 
is independently owned and operated and is not dominant in its field.
    After considering the economic impact of the final rule on small 
entities, we have determined that the final rule will not have a 
significant economic impact on a substantial number of small entities. 
Based on SBA size definitions for the affected industries and reported 
sales and employment data, EPA identified 185 of the 576 entities, or 
32 percent, owning affected facilities as small entities. Although 
small entities represent 32 percent of the entities within the source 
category, they are expected to incur only 4 percent of the total 
compliance costs of $862.7 million (1998 dollars). There are only ten 
small entities with compliance costs equal to or greater than 3 percent 
of their sales. In addition, there are only 24 small entities with 
cost-to-sales ratios between 1 and 3 percent.

[[Page 55249]]

    An economic impact analysis was performed to estimate the changes 
in product price and production quantities for the final rule. As 
mentioned in the summary of economic impacts earlier in this preamble, 
the estimated changes in prices and output for affected entities is no 
more than 0.05 percent. For more information, consult the docket for 
the final rule.
    It should be noted that these small entity impacts are in advance 
of any facility demonstrating eligibility for the health-based 
compliance alternatives. Depending on the number of affected facilities 
demonstrating eligibility for the health-based compliance alternatives, 
the estimated small entity impacts could fall to eight small entities 
with compliance costs equal to or greater than 3 percent of their 
sales, and 14 small entities with compliance costs between 1 and 3 
percent of their sales.
    The final rule will not have a significant economic impact on a 
substantial number of small entities as a result of several decisions 
EPA made regarding the development of the rule, which resulted in 
limiting the impact of the rule on small entities. First, as mentioned 
earlier in this preamble, EPA identified small units (heat input of 10 
MMBtu/hr or less) and limited use boilers (operate less than 10 percent 
of the time) as separate subcategories different from large units. Many 
small and limited use units are located at small entities. As also 
discussed earlier, the results of the MACT floor analysis for these 
subcategories of existing sources was that no MACT floor could be 
identified except for the limited use solid fuel subcategory, which is 
less stringent than the MACT floor for large units. Furthermore, the 
results of the beyond-the-floor analysis for these subcategories 
indicated that the costs would be too high to consider them feasible 
options. Consequently, the final rule contains no emission limitations 
for any of the existing small and limited use subcategories except the 
existing limited use solid fuel subcategory. In addition, the 
alternative metals emission limit resulted in minimizing the impacts on 
small entities since some of the potential entities burning a fuel 
containing very little metals are small entities.

D. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, we 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
1 year. Before promulgating a rule for which a written statement is 
needed, section 205 of the UMRA generally requires us to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows us to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the EPA 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, we must develop a small 
government agency plan under section 203 of the UMRA. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of regulatory promulgation with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    We determined that the final rule contains a Federal mandate that 
may result in expenditures of $100 million or more for State, local, 
and Tribal governments, in the aggregate, or the private sector in any 
1 year. Accordingly, we have prepared a written statement (titled 
``Unfunded Mandates Reform Act Analysis for the Industrial Boilers and 
Process Heaters NESHAP)'' under section 202 of the UMRA, which is 
summarized below.
Statutory Authority
    As discussed in this preamble, the statutory authority for the 
final rulemaking is section 112 of the CAA. Title III of the CAA 
Amendments was enacted to reduce nationwide air toxic emissions. 
Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups 
of chemicals deemed by Congress to be HAP. These toxic air pollutants 
are to be regulated by NESHAP.
    Section 112(d) of the CAA directs us to develop NESHAP, which 
require existing and new major sources to control emissions of HAP 
using MACT based standards. The final rule applies to all industrial, 
commercial, and institutional boilers and process heaters located at 
major sources of HAP emissions.
    In compliance with section 205(a) of the UMRA, we identified and 
considered a reasonable number of regulatory alternatives. Additional 
information on the costs and environmental impacts of these regulatory 
alternatives is presented in the docket.
    The regulatory alternative upon which the final rule is based 
represents the MACT floor for industrial boilers and process heaters 
and, as a result, it is the least costly and least burdensome 
alternative.
Social Costs and Benefits
    The regulatory impact analysis prepared for the final rule 
including the EPA's assessment of costs and benefits, is detailed in 
the ``Regulatory Impact Analysis for the Industrial Boilers and Process 
Heaters MACT'' in the docket. Based on estimated compliance costs 
associated with the final rule and the predicted change in prices and 
production in the affected industries, the estimated social costs of 
the final rule are $863 million (1999 dollars). Depending on the number 
of affected facilities demonstrating eligibility for the health-based 
compliance alternatives, these annualized social costs could fall to 
$746 million.
    It is estimated that 5 years after implementation of the final 
rule, HAP will be reduced by 58,500 tpy due to reductions in arsenic, 
beryllium, dioxin, hydrochloric acid, and several other HAP from 
industrial boilers and process heaters. Studies have determined a 
relationship between exposure to these HAP and the onset of cancer, 
however, there are some questions remaining on how cancers that may 
result from exposure to these HAP can be quantified in terms of 
dollars. Therefore, the EPA is unable to provide a monetized estimate 
of the benefits of the HAP reduced by the final rule at this time. 
However, there are significant reductions in PM and in SO2 
that occur. Reductions of 560,000 tons of PM with a diameter of less 
than or equal to 10 micrometers (PM10), 159,000 tons of PM 
with a diameter of less than or equal to 2.5 micrometers 
(PM2.5), and 112,000 tons of SO2 are expected to 
occur. These reductions occur from existing sources in operation 5 
years after the implementation of the regulation and are expected to 
continue throughout the life of the affected sources. The major health 
effect that results from these PM

[[Page 55250]]

and SO2 emissions reductions is a reduction in premature 
mortality. Other health effects that occur are reductions in chronic 
bronchitis, asthma attacks, and work-lost days (i.e., days when 
employees are unable to work).
    While we are unable to monetize the benefits associated with the 
HAP emissions reductions, we are able to monetize the benefits 
associated with the PM and SO2 emissions reductions. For 
SO2 and PM, we estimated the benefits associated with health 
effects of PM, but were unable to quantify all categories of benefits 
(particularly those associated with ecosystem and environmental 
effects). Unquantified benefits are noted with ``B'' in the estimates 
presented below. Our primary estimate of the monetized benefits in 2005 
associated with the implementation of the proposed alternative is $16.3 
billion + B (1999 dollars). This estimate is about $15.3 billion + B 
(1999 dollars) higher than the estimated social costs shown earlier in 
this section. These benefit estimates are in advance of any facility 
demonstrating eligibility for the health-based compliance alternatives. 
Depending on the number of affected facilities demonstrating 
eligibility for the health-based compliance alternatives, the benefit 
estimate presuming the health-based compliance alternatives is $14.5 
billion + B, which is $1.7 billion lower than the estimate for the 
final rule. This estimate is $13.8 billion + B higher than the 
estimated social costs presuming the health-based compliance 
alternatives. The general approach to calculating monetized benefits is 
discussed in more detail earlier in this preamble. For more detailed 
information on the benefits estimated for the final rule, refer to the 
RIA in the docket.
Future and Disproportionate Costs
    The Unfunded Mandates Act requires that we estimate, where accurate 
estimation is reasonably feasible, future compliance costs imposed by 
the rule and any disproportionate budgetary effects. Our estimates of 
the future compliance costs of the final rule are discussed previously 
in this preamble.
    We do not feel that there will be any disproportionate budgetary 
effects of the final rule on any particular areas of the country, State 
or local governments, types of communities (e.g., urban, rural), or 
particular industry segments. This is true for the 257 facilities owned 
by 54 different government bodies, and this is borne out by the results 
of the ``Economic Impact Analysis of the Industrial Boilers and Process 
Heaters NESHAP,'' the results of which are discussed previously in this 
preamble.
Effects on the National Economy
    The Unfunded Mandates Act requires that we estimate the effect of 
the final rule on the national economy. To the extent feasible, we must 
estimate the effect on productivity, economic growth, full employment, 
creation of productive jobs, and international competitiveness of the 
U.S. goods and services, if we determine that accurate estimates are 
reasonably feasible and that such effect is relevant and material.
    The nationwide economic impact of the final rule is presented in 
the ``Economic Impact Analysis for the Industrial Boilers and Process 
Heaters MACT'' in the docket. This analysis provides estimates of the 
effect of the final rule on some of the categories mentioned above. The 
results of the economic impact analysis are summarized previously in 
this preamble. The results show that there will be little impact on 
prices and output from the affected industries, and little impact on 
communities that may be affected by the final rule. In addition, there 
should be little impact on energy markets (in this case, coal, natural 
gas, petroleum products, and electricity). Hence, the potential impacts 
on the categories mentioned above should be minimal.
Consultation With Government Officials
    The Unfunded Mandates Act requires that we describe the extent of 
the EPA's prior consultation with affected State, local, and tribal 
officials, summarize the officials' comments or concerns, and summarize 
our response to those comments or concerns. In addition, section 203 of 
the UMRA requires that we develop a plan for informing and advising 
small governments that may be significantly or uniquely impacted by a 
rule. Although the final rule does not significantly affect any State, 
local, or Tribal governments, we have consulted with State and local 
air pollution control officials. We also have held meetings on the 
final rule with many of the stakeholders from numerous individual 
companies, environmental groups, consultants and vendors, labor unions, 
and other interested parties. We have added materials to the docket to 
document these meetings.
    In addition, we have determined that the final rule contains no 
regulatory requirements that might significantly or uniquely affect 
small governments. While some small governments may have some sources 
affected by the final rule, the impacts are not expected to be 
significant. Therefore, the final rule is not subject to the 
requirements of section 203 of the UMRA. However, EPA did complete a 
report containing analyses called for in the UMRA as a response to 
comments from many municipal utilities regarding the final rule and its 
potential impacts. This report, ``Unfunded Mandates Reform Act Analysis 
for the Industrial Boilers and Process Heaters NESHAP,'' is in the 
docket.

E. Executive Order 13132: Federalism

    Executive Order 13132 requires EPA to develop an accountable 
process to ensure ``meaningful and timely input by State and local 
officials in the development of regulatory policies that have 
federalism implications.'' ``Policies that have federalism 
implications'' are defined in the Executive Order to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.
    The final rule does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132.
    The agency is required by section 112 of the CAA, to establish the 
standards in the final rule. The final rule primarily affects private 
industry, and does not impose significant economic costs on State or 
local governments. The final rule does not include an express provision 
preempting State or local regulations. Thus, the requirements of 
section 6 of the Executive Order do not apply to the final rule.
    Although section 6 of Executive Order 13132 does not apply to the 
final rule, we consulted with representatives of State and local 
governments to enable them to provide meaningful and timely input into 
the development of the final rule. This consultation took place during 
the ICCR Federal Advisory Committee Act (FACA) committee meetings where 
members representing State and local governments participated in 
developing recommendations for EPA's combustion-related rulemakings, 
including the final rule. The concerns raised by representatives of 
State and local governments were considered during the development of 
the final rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to

[[Page 55251]]

promote communications between EPA and State and local governments, EPA 
specifically solicited comment on the final rule from State and local 
officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175 (65 FR 67249, November 9, 2000) requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' The final rule does not have tribal 
implications, as specified in Executive Order 13175.
    The final rule does not significantly or uniquely affect the 
communities of Indian tribal governments. We do not know of any 
industrial-commercial-institutional boilers or process heaters owned or 
operated by Indian tribal governments. However, if there are any, the 
effect of these rules on communities of tribal governments would not be 
unique or disproportionate to the effect on other communities. Thus, 
Executive Order 13175 does not apply to the final rule. The EPA 
specifically solicited additional comment on the final rule from tribal 
officials, but received none.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any 
regulation that: (1) Is determined to be ``economically significant'' 
as defined under Executive Order 12866, and (2) concerns an 
environmental health or safety risk that we have reason to believe may 
have a disproportionate effect on children.
    If the regulatory action meets both criteria, the EPA must evaluate 
the environmental health or safety effects of the planned regulation on 
children, and explain why the planned regulation is preferable to other 
potentially effective and reasonably feasible alternatives considered 
by the EPA.
    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that are based on health or safety risks, such that 
the analysis required under section 5-501 of the Executive Order has 
the potential to influence the regulation. The final rule is not 
subject to Executive Order 13045 because it is based on technology 
performance and not on health or safety risks.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Executive Order 13211 (66 FR 28355, May 22, 2001) provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Information and Regulatory Affairs, Office of Management and Budget, a 
Statement of Energy Effects for certain actions identified as 
``significant energy actions.'' Section 4(b) of Executive Order 13211 
defines ``significant energy actions'' as ``any action by an agency 
(normally published in the Federal Register) that promulgates or is 
expected to lead to the promulgation of a final rule or regulation, 
including notices of inquiry, advance notices of final rulemaking, and 
notices of final rulemaking: (1)(i) That is a significant regulatory 
action under Executive Order 12866 or any successor order, and (ii) is 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy; or (2) that is designated by the 
Administrator of the Office of Information and Regulatory Affairs as a 
``significant energy action.'' The final rule is not a ``significant 
energy action'' because it is not likely to have a significant adverse 
effect on the supply, distribution, or use of energy. The basis for the 
determination is as follows.
    The reduction in petroleum product output, which includes 
reductions in fuel production, is estimated at only 0.001 percent, or 
about 68 barrels per day based on 2000 U.S. fuel production nationwide. 
That is a minimal reduction in nationwide petroleum product output. The 
reduction in coal production is estimated at only 0.014 percent, or 
about 3.5 million tpy (or less than 1,000 tons per day) based on 2000 
U.S. coal production nationwide. The combination of the increase in 
electricity usage estimated with the effect of the increased price of 
affected output yields an increase in electricity output estimated at 
only 0.012 percent, or about 0.72 billion kilowatt-hours per year based 
on 2000 U.S. electricity production nationwide. All energy price 
changes estimated show no increase in price more than 0.05 percent 
nationwide, and a similar result occurs for energy distribution costs. 
We also expect that there will be no discernable impact on the import 
of foreign energy supplies, and no other adverse outcomes are expected 
to occur with regards to energy supplies. All of the results presented 
above account for the pass through of costs to consumers, as well as 
the cost impact to producers. For more information on the estimated 
energy effects, please refer to the economic impact analysis for the 
final rule. The analysis is available in the public docket. It should 
be noted that these energy impact estimates are in advance of any 
facility demonstrating eligibility for the health-based compliance 
alternatives.
    Depending on the number of affected facilities demonstrating 
eligibility for the health-based compliance alternatives, the reduction 
in petroleum product output, which includes reductions in fuel 
production, could fall to 65 barrels per day, or only 0.001 percent. 
The reduction in coal production could fall to only 0.010 percent, or 
about 2.5 million tpy based on 2000 U.S. coal production nationwide. 
The combination of the increase in electricity usage estimated with the 
effect of the increased price of affected output could yield an 
increase in electricity output could fall to only 0.0067 percent, or 
about 0.40 billion kilowatt-hours per year based on 2000 U.S. 
electricity production nationwide. All energy price changes estimated 
could now fall to increases of no more than 0.04 percent nationwide, 
and a similar result occurs for energy distribution costs. There should 
be no discernable impact on import of foreign energy supplies, and no 
other adverse outcomes are expected to occur with regards to energy 
supplies. All of the results presented with presumption of the health-
based compliance alternatives also account for the pass through of 
costs to consumers as well as the cost impact to producers.
    Therefore, we conclude that the final rule when implemented is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the 
EPA to use voluntary consensus standards in their regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, business practices) developed or adopted by one or 
more voluntary consensus bodies. The NTTAA directs EPA to provide 
Congress, through annual reports to the OMB, with explanations when an 
agency does not use available and applicable voluntary consensus 
standards.

[[Page 55252]]

    The final rule involves technical standards. The EPA cites the 
following standards in the final rule: EPA Methods 1, 2, 2F, 2G, 3A, 
3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with 
the NTTAA, EPA conducted searches to identify voluntary consensus 
standards in addition to these EPA methods. No applicable voluntary 
consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. 
The search and review results have been documented and are placed in 
the docket for the final rule.
    The three voluntary consensus standards described below were 
identified as acceptable alternatives to EPA test methods for the 
purposes of the final rule.
    The voluntary consensus standard ASME PTC 19-10-1981-Part 10, 
``Flue and Exhaust Gas Analyses,'' is cited in the final rule for its 
manual method for measuring the oxygen, carbon dioxide, and carbon 
monoxide content of exhaust gas. This part of ASME PTC 19-10-1981-Part 
10 is an acceptable alternative to Method 3B.
    The voluntary consensus standard ASTM D6522-00, ``Standard Test 
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and 
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers and Process Heaters Using 
Portable Analyzers'' is an acceptable alternative to EPA Methods 3A and 
10 for identifying carbon monoxide and oxygen concentrations for the 
final rule when the fuel is natural gas.
    The voluntary consensus standard ASTM Z65907, ``Standard Method for 
Both Speciated and Elemental Mercury Determination,'' is an acceptable 
alternative to EPA Method 29 (portion for mercury only) for the purpose 
of the final rule. This standard can be used in the final rule to 
determine the mercury concentration in stack gases for boilers with 
rated heat input capacities of greater than 250 MMBtu per hour.
    In addition to the voluntary consensus standards EPA uses in the 
final rule, the search for emissions measurement procedures identified 
15 other voluntary consensus standards. The EPA determined that 13 of 
these 15 standards identified for measuring emissions of the HAP or 
surrogates subject to the emission standards were impractical 
alternatives to EPA test methods for the purposes of the final rule. 
Therefore, EPA does not intend to adopt these standards for this 
purpose. (See Docket ID No. OAR-2002-0058 for further information on 
the methods.)
    Two of the 15 voluntary consensus standards identified in this 
search were not available at the time the review was conducted for the 
purposes of the final rule because they are under development by a 
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by 
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR 
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot 
Primary Flowmeters,'' for EPA Method 2.
    Section 63.7520 and Tables 4A through 4D of the final rule list the 
EPA testing methods. Under Sec.  63.7(f) and Sec.  63.8(f) of subpart 
A, 40 CFR part 63, of the General Provisions, a source may apply to EPA 
for permission to use alternative test methods or alternative 
monitoring requirements in place of any of the EPA testing methods, 
performance specifications, or procedures.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by 
the Small Business Regulatory Enforcement Fairness Act of 1996, 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. The EPA will submit a report containing 
the final rule and other required information to the United States 
Senate, the United States House of Representatives, and the Comptroller 
General of the United States prior to publication of the final rule in 
the Federal Register. A major rule cannot take effect until 60 days 
after it is published in the Federal Register. This action is a ``major 
rule'' as defined by 5 U.S.C. section 804(2). The rule will be 
effective on November 12, 2004.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances, Incorporation by 
reference, Intergovernmental relations, Reporting and recordkeeping 
requirements.

    Dated: February 26, 2004.
Michael O. Leavitt,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, part 63 of 
the Code of Federal Regulations is amended as follows:

PART 63--[AMENDED]

0
1. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--[Amended]

0
2. Section 63.14 is amended by revising paragraph (b)(27) and paragraph 
(i)(3) and adding paragraph (b)(35) and paragraphs (b)(39) through (53) 
to read as follows:


Sec.  63.14  Incorporations by reference.

* * * * *
    (b) * * *
    (27) ASTM D6522-00, Standard Test Method for Determination of 
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in 
Emissions from Natural Gas Fired Reciprocating Engines, Combustion 
Turbines, Boilers, and Process Heaters Using Portable Analyzers,\1\ IBR 
approved for Sec.  63.9307(c)(2), Table 4 of Subpart ZZZZ, and Table 5 
to Subpart DDDDD of this part.
* * * * *
    (35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method),\1\ IBR approved for Table 5 
to Subpart DDDDD of this part.
* * * * *
    (39) ASTM Method D388-99,.\1\ Standard Classification of Coals by 
Rank,\1\ IBR approved for Sec.  63.7575.
    (40) ASTM D396-02a, Standard Specification for Fuel Oils,\1\ IBR 
approved for Sec.  63.7575.
    (41) ASTM D1835-03a, Standard Specification for Liquified Petroleum 
(LP) Gases,\1\ IBR approved for Sec.  63.7575.
    (42) ASTM D2013-01, Standard Practice for Preparing Coal Samples 
for Analysis,\1\ IBR approved for Table 6 to Subpart DDDDD of this 
part.
    (43) ASTM D2234-00, .\1\ Standard Practice for Collection of a 
Gross Sample of Coal,\1\ IBR approved for Table 6 to Subpart DDDDD of 
this part.
    (44) ASTM D3173-02, Standard Test Method for Moisture in the 
Analysis Sample of Coal and Coke,\1\ IBR approved for Table 6 to 
Subpart DDDDD of this part.
    (45) ASTM D3683-94 (Reapproved 2000), Standard Test Method for 
Trace Elements in Coal and Coke Ash Absorption,\1\ IBR approved for 
Table 6 to Subpart DDDDD of this part.
    (46) ASTM D3684-01, Standard Test Method for Total Mercury in Coal 
by the Oxygen Bomb Combustion/Atomic Absorption Method,\1\ IBR approved 
for Table 6 to Subpart DDDDD of this part.
    (47) ASTM D5198-92 (Reapproved 2003), Standard Practice for Nitric 
Acid Digestion of Solid Waste,\1\ IBR approved for Table 6 to Subpart 
DDDDD of this part.

[[Page 55253]]

    (48) ASTM D5865-03a, Standard Test Method for Gross Calorific Value 
of Coal and Coke,\1\ IBR approved for Table 6 to Subpart DDDDD of this 
part.
    (49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory 
Subsampling of Media Related to Waste Management Activities,\1\ IBR 
approved for Table 6 to Subpart DDDDD of this part.
    (50) ASTM E711-87 (Reapproved 1996), Standard Test Method for Gross 
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter,\1\ IBR 
approved for Table 6 to Subpart DDDDD of this part.
    (51) ASTM E776-87 (Reapproved 1996), Standard Test Method for Forms 
of Chlorine in Refuse-Derived Fuel,\1\ IBR approved for Table 6 to 
Subpart DDDDD of this part.
    (52) ASTM E871-82 (Reapproved 1998), Standard Method of Moisture 
Analysis of Particulate Wood Fuels,\1\ IBR approved for Table 6 to 
Subpart DDDDD of this part.
    (53) ASTM E885-88 (Reapproved 1996), Standard Test Methods for 
Analyses of Metals in Refuse-Derived Fuel by Atomic Absorption 
Spectroscopy,\1\ IBR approved for Table 6 to Subpart DDDDD of this part 
63.
* * * * *
    (i) * * *
    (3) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.  
63.865(b), 63.3166(a), 63.3360(e)(1)(iii), 63.3545(a)(3), 
63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 
63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), and 
Table 5 to Subpart DDDDD of this part.
* * * * *

0
3. Part 63 is amended by adding subpart DDDDD to read as follows:

Subpart DDDDD--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
and Process Heaters

Sec.

What This Subpart Covers

63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this subpart?
63.7491 Are any boilers or process heaters not subject to this 
subpart?
63.7495 When do I have to comply with this subpart?

Emission Limits and Work Practice Standards

63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limits, work practice standards, and operating 
limits must I meet?

General Compliance Requirements

63.7505 What are my general requirements for complying with this 
subpart?
63.7506 Do any boilers or process heaters have limited requirements?
63.7507 What are the health-based compliance alternatives for the 
hydrogen chloride (HCl) and total selected metals (TSM) standards?

Testing, Fuel Analyses, and Initial Compliance Requirements

63.7510 What are my initial compliance requirements and by what date 
must I conduct them?
63.7515 When must I conduct subsequent performance tests or fuel 
analyses?
63.7520 What performance tests and procedures must I use?
63.7521 What fuel analyses and procedures must I use?
63.7522 Can I use emission averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and 
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission 
limits and work practice standards?

Continuous Compliance Requirements

63.7535 How do I monitor and collect data to demonstrate continuous 
compliance?
63.7540 How do I demonstrate continuous compliance with the emission 
limits and work practice standards?
63.7541 How do I demonstrate continuous compliance under the 
emission averaging provision?

Notifications, Reports, and Records

63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?

Other Requirements and Information

63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63--Emission Limits and Work 
Practice Standards
Table 2 to Subpart DDDDD of Part 63--Operating Limits for Boilers 
and Process Heaters With Particulate Matter Emission Limits
Table 3 to Subpart DDDDD of Part 63--Operating Limits for Boilers 
and Process Heaters With Mercury Emission Limits and Boilers and 
Process Heaters That Choose to Comply With the Alternative Total 
Selected Metals Emission Limits
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers 
and Process Heaters With Hydrogen Chloride Emission Limits
Table 5 to Subpart DDDDD of Part 63--Performance Testing 
Requirements
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous 
Compliance
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
Table 10 to Subpart DDDDD of Part 63--Applicability of General 
Provisions to Subpart DDDDD

Appendix

Appendix A to Subpart DDDDD--Methodology and Criteria for 
Demonstrating Eligibility for the Health-Based Compliance 
Alternatives Specified for the Large Solid Fuel Subcategory

Subpart DDDDD--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
and Process Heaters

What This Subpart Covers


Sec.  63.7480  What is the purpose of this subpart?

    This subpart establishes national emission limits and work practice 
standards for hazardous air pollutants (HAP) emitted from industrial, 
commercial, and institutional boilers and process heaters. This subpart 
also establishes requirements to demonstrate initial and continuous 
compliance with the emission limits and work practice standards.


Sec.  63.7485  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an 
industrial, commercial, or institutional boiler or process heater as 
defined in Sec.  63.7575 that is located at, or is part of, a major 
source of HAP as defined in Sec.  63.2 or Sec.  63.761 (40 CFR part 63, 
subpart HH, National Emission Standards for Hazardous Air Pollutants 
from Oil and Natural Gas Production Facilities), except as specified in 
Sec.  63.7491.


Sec.  63.7490  What is the affected source of this subpart?

    (a) This subpart applies to new, reconstructed, or existing 
affected sources as described in paragraphs (a)(1) and (2) of this 
section.
    (1) The affected source of this subpart is the collection of all 
existing industrial, commercial, and institutional boilers and process 
heaters within a subcategory located at a major source as defined in 
Sec.  63.7575.
    (2) The affected source of this subpart is each new or 
reconstructed industrial, commercial, or institutional boiler or

[[Page 55254]]

process heater located at a major source as defined in Sec.  63.7575.
    (b) A boiler or process heater is new if you commence construction 
of the boiler or process heater after January 13, 2003, and you meet 
the applicability criteria at the time you commence construction.
    (c) A boiler or process heater is reconstructed if you meet the 
reconstruction criteria as defined in Sec.  63.2, you commence 
reconstruction after January 13, 2003, and you meet the applicability 
criteria at the time you commence reconstruction.
    (d) A boiler or process heater is existing if it is not new or 
reconstructed.


Sec.  63.7491  Are any boilers or process heaters not subject to this 
subpart?

    The types of boilers and process heaters listed in paragraphs (a) 
through (o) of this section are not subject to this subpart.
    (a) A municipal waste combustor covered by 40 CFR part 60, subpart 
AAAA, subpart BBBB, subpart Cb or subpart Eb.
    (b) A hospital/medical/infectious waste incinerator covered by 40 
CFR part 60, subpart Ce or subpart Ec.
    (c) An electric utility steam generating unit that is a fossil 
fuel-fired combustion unit of more than 25 megawatts that serves a 
generator that produces electricity for sale. A fossil fuel-fired unit 
that cogenerates steam and electricity, and supplies more than one-
third of its potential electric output capacity, and more than 25 
megawatts electrical output to any utility power distribution system 
for sale is considered an electric utility steam generating unit.
    (d) A boiler or process heater required to have a permit under 
section 3005 of the Solid Waste Disposal Act or covered by 40 CFR part 
63, subpart EEE (e.g., hazardous waste boilers).
    (e) A commercial and industrial solid waste incineration unit 
covered by 40 CFR part 60, subpart CCCC or subpart DDDD.
    (f) A recovery boiler or furnace covered by 40 CFR part 63, subpart 
MM.
    (g) A boiler or process heater that is used specifically for 
research and development. This does not include units that only provide 
heat or steam to a process at a research and development facility.
    (h) A hot water heater as defined in this subpart.
    (i) A refining kettle covered by 40 CFR part 63, subpart X.
    (j) An ethylene cracking furnace covered by 40 CFR part 63, subpart 
YY.
    (k) Blast furnace stoves as described in the EPA document, entitled 
``National Emission Standards for Hazardous Air Pollutants (NESHAP) for 
Integrated Iron and Steel Plants--Background Information for Proposed 
Standards,'' (EPA-453/R-01-005).
    (l) Any boiler and process heater specifically listed as an 
affected source in another standard(s) under 40 CFR part 63.
    (m) Any boiler and process heater specifically listed as an 
affected source in another standard(s) established under section 129 of 
the Clean Air Act (CAA).
    (n) Temporary boilers as defined in this subpart.
    (o) Blast furnace gas fuel-fired boilers and process heaters as 
defined in this subpart.


Sec.  63.7495  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed boiler or process heater, 
you must comply with this subpart by November 12, 2004 or upon startup 
of your boiler or process heater, whichever is later.
    (b) If you have an existing boiler or process heater, you must 
comply with this subpart no later than September 13, 2007.
    (c) If you have an area source that increases its emissions or its 
potential to emit such that it becomes a major source of HAP, 
paragraphs (c)(1) and (2) of this section apply to you.
    (1) Any new or reconstructed boiler or process heater at the 
existing facility must be in compliance with this subpart upon startup.
    (2) Any existing boiler or process heater at the existing facility 
must be in compliance with this subpart within 3 years after the 
facility becomes a major source.
    (d) You must meet the notification requirements in Sec.  63.7545 
according to the schedule in Sec.  63.7545 and in subpart A of this 
part. Some of the notifications must be submitted before you are 
required to comply with the emission limits and work practice standards 
in this subpart.

Emission Limits and Work Practice Standards


Sec.  63.7499  What are the subcategories of boilers and process 
heaters?

    The subcategories of boilers and process heaters are large solid 
fuel, limited use solid fuel, small solid fuel, large liquid fuel, 
limited use liquid fuel, small liquid fuel, large gaseous fuel, limited 
use gaseous fuel, and small gaseous fuel. Each subcategory is defined 
in Sec.  63.7575.


Sec.  63.7500  What emission limits, work practice standards, and 
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) and (2) of 
this section.
    (1) You must meet each emission limit and work practice standard in 
Table 1 to this subpart that applies to your boiler or process heater, 
except as provided under Sec.  63.7507.
    (2) You must meet each operating limit in Tables 2 through 4 to 
this subpart that applies to your boiler or process heater. If you use 
a control device or combination of control devices not covered in 
Tables 2 through 4 to this subpart, or you wish to establish and 
monitor an alternative operating limit and alternative monitoring 
parameters, you must apply to the United States Environmental 
Protection Agency (EPA) Administrator for approval of alternative 
monitoring under Sec.  63.8(f).
    (b) As provided in Sec.  63.6(g), EPA may approve use of an 
alternative to the work practice standards in this section.

General Compliance Requirements


Sec.  63.7505  What are my general requirements for complying with this 
subpart?

    (a) You must be in compliance with the emission limits (including 
operating limits) and the work practice standards in this subpart at 
all times, except during periods of startup, shutdown, and malfunction.
    (b) You must always operate and maintain your affected source, 
including air pollution control and monitoring equipment, according to 
the provisions in Sec.  63.6(e)(1)(i).
    (c) You can demonstrate compliance with any applicable emission 
limit using fuel analysis if the emission rate calculated according to 
Sec.  63.7530(d) is less than the applicable emission limit. Otherwise, 
you must demonstrate compliance using performance testing.
    (d) If you demonstrate compliance with any applicable emission 
limit through performance testing, you must develop a site-specific 
monitoring plan according to the requirements in paragraphs (d)(1) 
through (4) of this section. This requirement also applies to you if 
you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
    (1) For each continuous monitoring system (CMS) required in this 
section, you must develop and submit to the EPA Administrator for 
approval a site-specific monitoring plan that addresses paragraphs 
(d)(1)(i) through (iii) of this section. You must submit this site-
specific monitoring plan at least 60 days

[[Page 55255]]

before your initial performance evaluation of your CMS.
    (i) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device);
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations).
    (2) In your site-specific monitoring plan, you must also address 
paragraphs (d)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  63.8(c)(1), (c)(3), and (c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in 
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation 
according to the site-specific monitoring plan.
    (e) If you have an applicable emission limit or work practice 
standard, you must develop and implement a written startup, shutdown, 
and malfunction plan (SSMP) according to the provisions in Sec.  
63.6(e)(3).


Sec.  63.7506  Do any boilers or process heaters have limited 
requirements?

    (a) New or reconstructed boilers and process heaters in the large 
liquid fuel subcategory or the limited use liquid fuel subcategory that 
burn only fossil fuels and other gases and do not burn any residual oil 
are subject to the emission limits and applicable work practice 
standards in Table 1 to this subpart. You are not required to conduct a 
performance test to demonstrate compliance with the emission limits. 
You are not required to set and maintain operating limits to 
demonstrate continuous compliance with the emission limits. However, 
you must meet the requirements in paragraphs (a)(1) and (2) of this 
section and meet the CO work practice standard in Table 1 to this 
subpart.
    (1) To demonstrate initial compliance, you must include a signed 
statement in the Notification of Compliance Status report required in 
Sec.  63.7545(e) that indicates you burn only liquid fossil fuels other 
than residual oils, either alone or in combination with gaseous fuels.
    (2) To demonstrate continuous compliance with the applicable 
emission limits, you must also keep records that demonstrate that you 
burn only liquid fossil fuels other than residual oils, either alone or 
in combination with gaseous fuels. You must also include a signed 
statement in each semiannual compliance report required in Sec.  
63.7550 that indicates you burned only liquid fossil fuels other than 
residual oils, either alone or in combination with gaseous fuels, 
during the reporting period.
    (b) The affected boilers and process heaters listed in paragraphs 
(b)(1) through (3) of this section are subject to only the initial 
notification requirements in Sec.  63.9(b) (i.e., they are not subject 
to the emission limits, work practice standards, performance testing, 
monitoring, SSMP, site-specific monitoring plans, recordkeeping and 
reporting requirements of this subpart or any other requirements in 
subpart A of this part).
    (1) Existing large and limited use gaseous fuel units.
    (2) Existing large and limited use liquid fuel units.
    (3) New or reconstructed small liquid fuel units that burn only 
gaseous fuels or distillate oil. New or reconstructed small liquid fuel 
boilers and process heaters that commence burning of any other type of 
liquid fuel must comply with all applicable requirements of this 
subpart and subpart A of this part upon startup of burning the other 
type of liquid fuel.
    (c) The affected boilers and process heaters listed in paragraphs 
(c)(1) through (4) of this section are not subject to the initial 
notification requirements in Sec.  63.9(b) and are not subject to any 
requirements in this subpart or in subpart A of this part (i.e., they 
are not subject to the emission limits, work practice standards, 
performance testing, monitoring, SSM plans, site-specific monitoring 
plans, recordkeeping and reporting requirements of this subpart, or any 
other requirements in subpart A of this part.
    (1) Existing small solid fuel boilers and process heaters.
    (2) Existing small liquid fuel boilers and process heaters.
    (3) Existing small gaseous fuel boilers and process heaters.
    (4) New or reconstructed small gaseous fuel units.


Sec.  63.7507  What are the health-based compliance alternatives for 
the hydrogen chloride (HCl) and total selected metals (TSM) standards?

    (a) As an alternative to the requirement for large solid fuel 
boilers located at a single facility to demonstrate compliance with the 
HCl emission limit in Table 1 to this subpart, you may demonstrate 
eligibility for the health-based compliance alternative for HCl 
emissions under the procedures prescribed in appendix A to this 
subpart.
    (b) In lieu of complying with the TSM emission standards in Table 1 
to this subpart based on the sum of emissions for the eight selected 
metals, you may demonstrate eligibility for complying with the TSM 
emission standards in Table 1 based on the sum of emissions for seven 
selected metals (by excluding manganese emissions from the summation of 
TSM emissions) under the procedures prescribed in appendix A to this 
subpart.

Testing, Fuel Analyses, and Initial Compliance Requirements


Sec.  63.7510  What are my initial compliance requirements and by what 
date must I conduct them?

    (a) For affected sources that elect to demonstrate compliance with 
any of the emission limits of this subpart through performance testing, 
your initial compliance requirements include conducting performance 
tests according to Sec.  63.7520 and Table 5 to this subpart, 
conducting a fuel analysis for each type of fuel burned in your boiler 
or process heater according to Sec.  63.7521 and Table 6 to this 
subpart, establishing operating limits according to Sec.  63.7530 and 
Table 7 to this subpart, and conducting CMS performance evaluations 
according to Sec.  63.7525.
    (b) For affected sources that elect to demonstrate compliance with 
the emission limits for HCl, mercury, or TSM through fuel analysis, 
your initial compliance requirement is to conduct a fuel analysis for 
each type of fuel burned in your boiler or process heater according to 
Sec.  63.7521 and Table 6 to this subpart and establish operating 
limits according to Sec.  63.7530 and Table 8 to this subpart.
    (c) For affected sources that have an applicable work practice 
standard, your initial compliance requirements depend on the 
subcategory and rated capacity of your boiler or process heater. If 
your boiler or process heater is in any of the limited use 
subcategories or has a heat input capacity less than 100 MMBtu per 
hour, your initial compliance demonstration is conducting a performance 
test for carbon monoxide

[[Page 55256]]

according to Table 5 to this subpart. If your boiler or process heater 
is in any of the large subcategories and has a heat input capacity of 
100 MMBtu per hour or greater, your initial compliance demonstration is 
conducting a performance evaluation of your continuous emission 
monitoring system for carbon monoxide according to Sec.  63.7525(a).
    (d) For existing affected sources, you must demonstrate initial 
compliance no later than 180 days after the compliance date that is 
specified for your source in Sec.  63.7495 and according to the 
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this 
subpart.
    (e) If your new or reconstructed affected source commenced 
construction or reconstruction between January 13, 2003 and November 
12, 2004, you must demonstrate initial compliance with either the 
proposed emission limits and work practice standards or the promulgated 
emission limits and work practice standards no later than 180 days 
after November 12, 2004 or within 180 days after startup of the source, 
whichever is later, according to Sec.  63.7(a)(2)(ix).
    (f) If your new or reconstructed affected source commenced 
construction or reconstruction between January 13, 2003, and November 
12, 2004, and you chose to comply with the proposed emission limits and 
work practice standards when demonstrating initial compliance, you must 
conduct a second compliance demonstration for the promulgated emission 
limits and work practice standards within 3 years after November 12, 
2004 or within 3 years after startup of the affected source, whichever 
is later.
    (g) If your new or reconstructed affected source commences 
construction or reconstruction after November 12, 2004, you must 
demonstrate initial compliance with the promulgated emission limits and 
work practice standards no later than 180 days after startup of the 
source.


Sec.  63.7515  When must I conduct subsequent performance tests or fuel 
analyses?

    (a) You must conduct all applicable performance tests according to 
Sec.  63.7520 on an annual basis, unless you follow the requirements 
listed in paragraphs (b) through (d) of this section. Annual 
performance tests must be completed between 10 and 12 months after the 
previous performance test, unless you follow the requirements listed in 
paragraphs (b) through (d) of this section.
    (b) You can conduct performance tests less often for a given 
pollutant if your performance tests for the pollutant (particulate 
matter, HCl, mercury, or TSM) for at least 3 consecutive years show 
that you comply with the emission limit. In this case, you do not have 
to conduct a performance test for that pollutant for the next 2 years. 
You must conduct a performance test during the third year and no more 
than 36 months after the previous performance test.
    (c) If your boiler or process heater continues to meet the emission 
limit for particulate matter, HCl, mercury, or TSM, you may choose to 
conduct performance tests for these pollutants every third year, but 
each such performance test must be conducted no more than 36 months 
after the previous performance test.
    (d) If a performance test shows noncompliance with an emission 
limit for particulate matter, HCl, mercury, or TSM, you must conduct 
annual performance tests for that pollutant until all performance tests 
over a consecutive 3-year period show compliance.
    (e) If you have an applicable work practice standard for carbon 
monoxide and your boiler or process heater is in any of the limited use 
subcategories or has a heat input capacity less than 100 MMBtu per 
hour, you must conduct annual performance tests for carbon monoxide 
according to Sec.  63.7520. Each annual performance test must be 
conducted between 10 and 12 months after the previous performance test.
    (f) You must conduct a fuel analysis according to Sec.  63.7521 for 
each type of fuel burned no later than 5 years after the previous fuel 
analysis for each fuel type. If you burn a new type of fuel, you must 
conduct a fuel analysis before burning the new type of fuel in your 
boiler or process heater. You must still meet all applicable continuous 
compliance requirements in Sec.  63.7540.
    (g) You must report the results of performance tests and fuel 
analyses within 60 days after the completion of the performance tests 
or fuel analyses. This report should also verify that the operating 
limits for your affected source have not changed or provide 
documentation of revised operating parameters established according to 
Sec.  63.7530 and Table 7 to this subpart, as applicable. The reports 
for all subsequent performance tests and fuel analyses should include 
all applicable information required in Sec.  63.7550.


Sec.  63.7520  What performance tests and procedures must I use?

    (a) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific test 
plan according to the requirements in Sec.  63.7(c) if you elect to 
demonstrate compliance through performance testing.
    (b) You must conduct each performance test according to the 
requirements in Table 5 to this subpart.
    (c) New or reconstructed boilers or process heaters in one of the 
liquid fuel subcategories that burn only fossil fuels and other gases 
and do not burn any residual oil must demonstrate compliance according 
to Sec.  63.7506(a).
    (d) You must conduct each performance test under the specific 
conditions listed in Tables 5 and 7 to this subpart. You must conduct 
performance tests at the maximum normal operating load while burning 
the type of fuel or mixture of fuels that have the highest content of 
chlorine, mercury, and total selected metals, and you must demonstrate 
initial compliance and establish your operating limits based on these 
tests. These requirements could result in the need to conduct more than 
one performance test.
    (e) You may not conduct performance tests during periods of 
startup, shutdown, or malfunction.
    (f) You must conduct three separate test runs for each performance 
test required in this section, as specified in Sec.  63.7(e)(3). Each 
test run must last at least 1 hour.
    (g) To determine compliance with the emission limits, you must use 
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA 
Method 19 of appendix A to part 60 of this chapter to convert the 
measured particulate matter concentrations, the measured HCl 
concentrations, the measured TSM concentrations, and the measured 
mercury concentrations that result from the initial performance test to 
pounds per million Btu heat input emission rates using F-factors.


Sec.  63.7521  What fuel analyses and procedures must I use?

    (a) You must conduct fuel analyses according to the procedures in 
paragraphs (b) through (e) of this section and Table 6 to this subpart, 
as applicable.
    (b) You must develop and submit a site-specific fuel analysis plan 
to the EPA Administrator for review and approval according to the 
following procedures and requirements in paragraphs (b)(1) and (2) of 
this section.
    (1) You must submit the fuel analysis plan no later than 60 days 
before the date that you intend to demonstrate compliance.
    (2) You must include the information contained in paragraphs 
(b)(2)(i)

[[Page 55257]]

through (vi) of this section in your fuel analysis plan.
    (i) The identification of all fuel types anticipated to be burned 
in each boiler or process heater.
    (ii) For each fuel type, the notification of whether you or a fuel 
supplier will be conducting the fuel analysis.
    (iii) For each fuel type, a detailed description of the sample 
location and specific procedures to be used for collecting and 
preparing the composite samples if your procedures are different from 
paragraph (c) or (d) of this section. Samples should be collected at a 
location that most accurately represents the fuel type, where possible, 
at a point prior to mixing with other dissimilar fuel types.
    (iv) For each fuel type, the analytical methods, with the expected 
minimum detection levels, to be used for the measurement of selected 
total metals, chlorine, or mercury.
    (v) If you request to use an alternative analytical method other 
than those required by Table 6 to this subpart, you must also include a 
detailed description of the methods and procedures that will be used.
    (vi) If you will be using fuel analysis from a fuel supplier in 
lieu of site-specific sampling and analysis, the fuel supplier must use 
the analytical methods required by Table 6 to this subpart.
    (c) At a minimum, you must obtain three composite fuel samples for 
each fuel type according to the procedures in paragraph (c)(1) or (2) 
of this section.
    (1) If sampling from a belt (or screw) feeder, collect fuel samples 
according to paragraphs (c)(1)(i) and (ii) of this section.
    (i) Stop the belt and withdraw a 6-inch wide sample from the full 
cross-section of the stopped belt to obtain a minimum two pounds of 
sample. Collect all the material (fines and coarse) in the full cross-
section. Transfer the sample to a clean plastic bag.
    (ii) Each composite sample will consist of a minimum of three 
samples collected at approximately equal intervals during the testing 
period.
    (2) If sampling from a fuel pile or truck, collect fuel samples 
according to paragraphs (c)(2)(i) through (iii) of this section.
    (i) For each composite sample, select a minimum of five sampling 
locations uniformly spaced over the surface of the pile.
    (ii) At each sampling site, dig into the pile to a depth of 18 
inches. Insert a clean flat square shovel into the hole and withdraw a 
sample, making sure that large pieces do not fall off during sampling.
    (iii) Transfer all samples to a clean plastic bag for further 
processing.
    (d) Prepare each composite sample according to the procedures in 
paragraphs (d)(1) through (7) of this section.
    (1) Throughly mix and pour the entire composite sample over a clean 
plastic sheet.
    (2) Break sample pieces larger than 3 inches into smaller sizes.
    (3) Make a pie shape with the entire composite sample and subdivide 
it into four equal parts.
    (4) Separate one of the quarter samples as the first subset.
    (5) If this subset is too large for grinding, repeat the procedure 
in paragraph (d)(3) of this section with the quarter sample and obtain 
a one-quarter subset from this sample.
    (6) Grind the sample in a mill.
    (7) Use the procedure in paragraph (d)(3) of this section to obtain 
a one-quarter subsample for analysis. If the quarter sample is too 
large, subdivide it further using the same procedure.
    (e) Determine the concentration of pollutants in the fuel (mercury, 
chlorine, and/or total selected metals) in units of pounds per million 
Btu of each composite sample for each fuel type according to the 
procedures in Table 6 to this subpart.


Sec.  63.7522  Can I use emission averaging to comply with this 
subpart?

    (a) As an alternative to meeting the requirements of Sec.  63.7500, 
if you have more than one existing large solid fuel boiler located at 
your facility, you may demonstrate compliance by emission averaging 
according to the procedures in this section in a State that does not 
choose to exclude emission averaging.
    (b) For each existing large solid fuel boiler in the averaging 
group, the emission rate achieved during the initial compliance test 
for the HAP being averaged must not exceed the emission level that was 
being achieved on November 12, 2004 or the control technology employed 
during the initial compliance test must not be less effective for the 
HAP being averaged than the control technology employed on November 12, 
2004.
    (c) You may average particulate matter or TSM, HCl, and mercury 
emissions from existing large solid fuel boilers to demonstrate 
compliance with the limits in Table 1 to this subpart if you satisfy 
the requirements in paragraphs (d), (e), and (f) of this section.
    (d) The weighted average emissions from the existing large solid 
fuel boilers participating in the emissions averaging option must be in 
compliance with the limits in Table 1 to this subpart at all times 
following the compliance date specified in Sec.  63.7495.
    (e) You must demonstrate initial compliance according to paragraphs 
(e)(1) or (2) of this section.
    (1) You must use Equation 1 of this section to demonstrate that the 
particulate matter or TSM, HCl, and mercury emissions from all existing 
large solid fuel boilers participating in the emissions averaging 
option do not exceed the emission limits in Table 1 to this subpart.

[[Page 55258]]

[GRAPHIC] [TIFF OMITTED] TR13SE04.000

Where:

AveWeighted = Average weighted emissions for particulate matter or TSM, 
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this subpart) 
or fuel analysis (as calculated by the applicable equation in Sec.  
63.7530(d)) for boiler, i, for particulate matter or TSM, HCl, or 
mercury, in units of pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of boiler, i, in units of 
million Btu per hour.
n = Number of large solid fuel boilers participating in the emissions 
averaging option.

    (2) If you are not capable of monitoring heat input, you can use 
Equation 2 of this section as an alternative to using equation 1 of 
this section to demonstrate that the particulate matter or TSM, HCl, 
and mercury emissions from all existing large solid fuel boilers 
participating in the emissions averaging option do not exceed the 
emission limits in Table 1 to this subpart.
[GRAPHIC] [TIFF OMITTED] TR13SE04.001

Where:

AveWeighted = Average weighted emission level for PM or TSM, HCl, or 
mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this subpart) 
or fuel analysis (as calculated by the applicable equation in Sec.  
63.7530(d)) for boiler, i, for particulate matter or TSM, HCl, or 
mercury, in units of pounds per million Btu of heat input.
Sm = Maximum steam generation by boiler, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance 
test, in units of million Btu of heat input per pounds of steam 
generated.

    (f) You must demonstrate continuous compliance on a 12-month 
rolling average basis determined at the end of every month (12 times 
per year) according to paragraphs (f)(1) and (2). The first 12-month 
rolling-average period begins on the compliance date specified in Sec.  
63.7495.
    (1) For each calendar month, you must use Equation 3 of this 
section to calculate the 12-month rolling average weighted emission 
limit using the actual heat capacity for each existing large solid fuel 
boiler participating in the emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TR13SE04.002

Where:

AveWeighted Emissions = 12-month rolling average weighted emission 
level for particulate matter or TSM, HCl, or mercury, in units of 
pounds per million Btu of heat input.
Er = Emission rate, calculated during the most recent compliance test, 
(as calculated according to Table 5 to this subpart) or fuel analysis 
(as calculated by the applicable equation in Sec.  63.7530(d)) for 
boiler, i, for particulate matter or TSM, HCl, or mercury, in units of 
pounds per million Btu of heat input.
Hb = The average heat input for each calendar month of boiler, i, in 
units of million Btu.
n = Number of large solid fuel boilers participating in the emissions 
averaging option.
    (2) If you are not capable of monitoring heat input, you can use 
Equation 4 of this section as an alternative to using Equation 3 of 
this section to calculate the 12-month rolling average weighted 
emission limit using the actual steam generation from the large solid 
fuel boilers participating in the emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TR13SE04.003

Where:

AveWeighted Emissions = 12-month rolling average weighted emission 
level for PM or TSM, HCl, or mercury, in units of pounds per million 
Btu of heat input.
Er = Emission rate, calculated during the most recent compliance test 
(as calculated according to Table 5 to this subpart) or fuel analysis 
(as calculated by the applicable equation in Sec.  63.7530(d)) for 
boiler, i, for particulate matter or TSM, HCl, or mercury, in units of 
pounds per million Btu of heat input.
Sa = Actual steam generation for each calender month by boiler, i, in 
units of pounds.
Cf = Conversion factor, as calculated during the most recent compliance 
test, in units of million Btu of heat input per pounds of steam 
generated.

    (g) You must develop and submit an implementation plan for emission 
averaging to the applicable regulatory authority for review and 
approval according to the following procedures and requirements in 
paragraphs (g)(1) through (4).

[[Page 55259]]

    (1) You must submit the implementation plan no later than 180 days 
before the date that the facility intends to demonstrate compliance 
using the emission averaging option.
    (2) You must include the information contained in paragraphs 
(g)(2)(i) through (vii) of this section in your implementation plan for 
all emission sources included in an emissions average:
    (i) The identification of all existing large solid fuel boilers in 
the averaging group, including for each either the applicable HAP 
emission level or the control technology installed on;
    (ii) The process parameter (heat input or steam generated) that 
will be monitored for each averaging group of large solid fuel boilers;
    (iii) The specific control technology or pollution prevention 
measure to be used for each emission source in the averaging group and 
the date of its installation or application. If the pollution 
prevention measure reduces or eliminates emissions from multiple 
sources, the owner or operator must identify each source;
    (iv) The test plan for the measurement of particulate matter (or 
TSM), HCl, or mercury emissions in accordance with the requirements in 
Sec.  63.7520;
    (v) The operating parameters to be monitored for each control 
system or device and a description of how the operating limits will be 
determined;
    (vi) If you request to monitor an alternative operating parameter 
pursuant to Sec.  63.7525, you must also include:
    (A) A description of the parameter(s) to be monitored and an 
explanation of the criteria used to select the parameter(s); and
    (B) A description of the methods and procedures that will be used 
to demonstrate that the parameter indicates proper operation of the 
control device; the frequency and content of monitoring, reporting, and 
recordkeeping requirements; and a demonstration, to the satisfaction of 
the applicable regulatory authority, that the proposed monitoring 
frequency is sufficient to represent control device operating 
conditions; and
    (vii) A demonstration that compliance with each of the applicable 
emission limit(s) will be achieved under representative operating 
conditions.
    (3) Upon receipt, the regulatory authority shall review and approve 
or disapprove the plan according to the following criteria:
    (i) Whether the content of the plan includes all of the information 
specified in paragraph (g)(2) of this section; and
    (ii) Whether the plan presents sufficient information to determine 
that compliance will be achieved and maintained.
    (4) The applicable regulatory authority shall not approve an 
emission averaging implementation plan containing any of the following 
provisions:
    (i) Any averaging between emissions of differing pollutants or 
between differing sources; or
    (ii) The inclusion of any emission source other than an existing 
large solid fuel boiler.


Sec.  63.7525  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If you have an applicable work practice standard for carbon 
monoxide, and your boiler or process heater is in any of the large 
subcategories and has a heat input capacity of 100 MMBtu per hour or 
greater, you must install, operate, and maintain a continuous emission 
monitoring system (CEMS) for carbon monoxide according to the 
procedures in paragraphs (a)(1) through (6) of this section by the 
compliance date specified in Sec.  63.7495.
    (1) Each CEMS must be installed, operated, and maintained according 
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and 
according to the site-specific monitoring plan developed according to 
Sec.  63.7505(d).
    (2) You must conduct a performance evaluation of each CEMS 
according to the requirements in Sec.  63.8 and according to PS 4A of 
40 CFR part 60, appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period.
    (4) The CEMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must calculate and record a 30-day rolling average emission 
rate on a daily basis. A new 30-day rolling average emission rate is 
calculated as the average of all of the hourly CO emission data for the 
preceding 30 operating days.
    (6) For purposes of calculating data averages, you must not use 
data recorded during periods of monitoring malfunctions, associated 
repairs, out-of-control periods, required quality assurance or control 
activities, or when your boiler or process heater is operating at less 
than 50 percent of its rated capacity. You must use all the data 
collected during all other periods in assessing compliance. Any period 
for which the monitoring system is out of control and data are not 
available for required calculations constitutes a deviation from the 
monitoring requirements.
    (b) If you have an applicable opacity operating limit, you must 
install, operate, certify and maintain each continuous opacity 
monitoring system (COMS) according to the procedures in paragraphs 
(b)(1) through (7) of this section by the compliance date specified in 
Sec.  63.7495.
    (1) Each COMS must be installed, operated, and maintained according 
to PS 1 of 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each COMS 
according to the requirements in Sec.  63.8 and according to PS 1 of 40 
CFR part 60, appendix B.
    (3) As specified in Sec.  63.8(c)(4)(i), each COMS must complete a 
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
    (4) The COMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  63.8(d). At a minimum, the 
monitoring plan must include a daily calibration drift assessment, a 
quarterly performance audit, and an annual zero alignment audit of each 
COMS.
    (6) You must operate and maintain each COMS according to the 
requirements in the monitoring plan and the requirements of Sec.  
63.8(e). Identify periods the COMS is out of control including any 
periods that the COMS fails to pass a daily calibration drift 
assessment, a quarterly performance audit, or an annual zero alignment 
audit.
    (7) You must determine and record all the 6-minute averages (and 1-
hour block averages as applicable) collected for periods during which 
the COMS is not out of control.
    (c) If you have an operating limit that requires the use of a CMS, 
you must install, operate, and maintain each continuous parameter 
monitoring system (CPMS) according to the procedures in paragraphs 
(c)(1) through (5) of this section by the compliance date specified in 
Sec.  63.7495.
    (1) The CPMS must complete a minimum of one cycle of operation for 
each successive 15-minute period. You must have a minimum of four 
successive cycles of operation to have a valid hour of data.
    (2) Except for monitoring malfunctions, associated repairs, and 
required quality assurance or control

[[Page 55260]]

activities (including, as applicable, calibration checks and required 
zero and span adjustments), you must conduct all monitoring in 
continuous operation at all times that the unit is operating. A 
monitoring malfunction is any sudden, infrequent, not reasonably 
preventable failure of the monitoring to provide valid data. Monitoring 
failures that are caused in part by poor maintenance or careless 
operation are not malfunctions.
    (3) For purposes of calculating data averages, you must not use 
data recorded during monitoring malfunctions, associated repairs, out 
of control periods, or required quality assurance or control 
activities. You must use all the data collected during all other 
periods in assessing compliance. Any period for which the monitoring 
system is out-of-control and data are not available for required 
calculations constitutes a deviation from the monitoring requirements.
    (4) Determine the 3-hour block average of all recorded readings, 
except as provided in paragraph (c)(3) of this section.
    (5) Record the results of each inspection, calibration, and 
validation check.
    (d) If you have an operating limit that requires the use of a flow 
measurement device, you must meet the requirements in paragraphs (c) 
and (d)(1) through (4) of this section.
    (1) Locate the flow sensor and other necessary equipment in a 
position that provides a representative flow.
    (2) Use a flow sensor with a measurement sensitivity of 2 percent 
of the flow rate.
    (3) Reduce swirling flow or abnormal velocity distributions due to 
upstream and downstream disturbances.
    (4) Conduct a flow sensor calibration check at least semiannually.
    (e) If you have an operating limit that requires the use of a 
pressure measurement device, you must meet the requirements in 
paragraphs (c) and (e)(1) through (6) of this section.
    (1) Locate the pressure sensor(s) in a position that provides a 
representative measurement of the pressure.
    (2) Minimize or eliminate pulsating pressure, vibration, and 
internal and external corrosion.
    (3) Use a gauge with a minimum tolerance of 1.27 centimeters of 
water or a transducer with a minimum tolerance of 1 percent of the 
pressure range.
    (4) Check pressure tap pluggage daily.
    (5) Using a manometer, check gauge calibration quarterly and 
transducer calibration monthly.
    (6) Conduct calibration checks any time the sensor exceeds the 
manufacturer's specified maximum operating pressure range or install a 
new pressure sensor.
    (f) If you have an operating limit that requires the use of a pH 
measurement device, you must meet the requirements in paragraphs (c) 
and (f)(1) through (3) of this section.
    (1) Locate the pH sensor in a position that provides a 
representative measurement of scrubber effluent pH.
    (2) Ensure the sample is properly mixed and representative of the 
fluid to be measured.
    (3) Check the pH meter's calibration on at least two points every 8 
hours of process operation.
    (g) If you have an operating limit that requires the use of 
equipment to monitor voltage and secondary current (or total power 
input) of an electrostatic precipitator (ESP), you must use voltage and 
secondary current monitoring equipment to measure voltage and secondary 
current to the ESP.
    (h) If you have an operating limit that requires the use of 
equipment to monitor sorbent injection rate (e.g., weigh belt, weigh 
hopper, or hopper flow measurement device), you must meet the 
requirements in paragraphs (c) and (h)(1) through (3) of this section.
    (1) Locate the device in a position(s) that provides a 
representative measurement of the total sorbent injection rate.
    (2) Install and calibrate the device in accordance with 
manufacturer's procedures and specifications.
    (3) At least annually, calibrate the device in accordance with the 
manufacturer's procedures and specifications.
    (i) If you elect to use a fabric filter bag leak detection system 
to comply with the requirements of this subpart, you must install, 
calibrate, maintain, and continuously operate a bag leak detection 
system as specified in paragraphs (i)(1) through (8) of this section.
    (1) You must install and operate a bag leak detection system for 
each exhaust stack of the fabric filter.
    (2) Each bag leak detection system must be installed, operated, 
calibrated, and maintained in a manner consistent with the 
manufacturer's written specifications and recommendations and in 
accordance with the guidance provided in EPA-454/R-98-015, September 
1997.
    (3) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting particulate matter emissions at 
concentrations of 10 milligrams per actual cubic meter or less.
    (4) The bag leak detection system sensor must provide output of 
relative or absolute particulate matter loadings.
    (5) The bag leak detection system must be equipped with a device to 
continuously record the output signal from the sensor.
    (6) The bag leak detection system must be equipped with an alarm 
system that will sound automatically when an increase in relative 
particulate matter emissions over a preset level is detected. The alarm 
must be located where it is easily heard by plant operating personnel.
    (7) For positive pressure fabric filter systems that do not duct 
all compartments of cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
    (8) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors.


Sec.  63.7530  How do I demonstrate initial compliance with the 
emission limits and work practice standards?

    (a) You must demonstrate initial compliance with each emission 
limit and work practice standard that applies to you by either 
conducting initial performance tests and establishing operating limits, 
as applicable, according to Sec.  63.7520, paragraph (c) of this 
section, and Tables 5 and 7 to this subpart OR conducting initial fuel 
analyses to determine emission rates and establishing operating limits, 
as applicable, according to Sec.  63.7521, paragraph (d) of this 
section, and Tables 6 and 8 to this subpart.
    (b) New or reconstructed boilers or process heaters in one of the 
liquid fuel subcategories that burn only fossil fuels and other gases 
and do not burn any residual oil must demonstrate compliance according 
to Sec.  63.7506(a).
    (c) If you demonstrate compliance through performance testing, you 
must establish each site-specific operating limit in Tables 2 through 4 
to this subpart that applies to you according to the requirements in 
Sec.  63.7520, Table 7 to this subpart, and paragraph (c)(4) of this 
section, as applicable. You must also conduct fuel analyses according 
to Sec.  63.7521 and establish maximum fuel pollutant input levels 
according to paragraphs (c)(1) through (3) of this section, as 
applicable.
    (1) You must establish the maximum chlorine fuel input 
(Cinput) during the initial performance testing according to 
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in

[[Page 55261]]

your boiler or process heater that has the highest content of chlorine.
    (ii) During the performance testing for HCl, you must determine the 
fraction of the total heat input for each fuel type burned 
(Qi) based on the fuel mixture that has the highest content 
of chlorine, and the average chlorine concentration of each fuel type 
burned (Ci).
    (iii) You must establish a maximum chlorine input level using 
Equation 5 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.004

Where:

Clinput = Maximum amount of chlorine entering the boiler or 
process heater through fuels burned in units of pounds per million Btu.
Ci = Arithmetic average concentration of chlorine in fuel 
type, i, analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
Qi = Fraction of total heat input from fuel type, i, based 
on the fuel mixture that has the highest content of chlorine. If you do 
not burn multiple fuel types during the performance testing, it is not 
necessary to determine the value of this term. Insert a value of ``1'' 
for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of chlorine.

    (2) If you choose to comply with the alternative TSM emission limit 
instead of the particulate matter emission limit, you must establish 
the maximum TSM fuel input level (TSMinput) during the 
initial performance testing according to the procedures in paragraphs 
(c)(2)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your boiler or process heater that has the highest content of 
TSM.
    (ii) During the performance testing for TSM, you must determine the 
fraction of total heat input from each fuel burned (Qi) 
based on the fuel mixture that has the highest content of total 
selected metals, and the average TSM concentration of each fuel type 
burned (Mi).
    (iii) You must establish a baseline TSM input level using Equation 
6 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.005

Where:

TSMinput = Maximum amount of TSM entering the boiler or 
process heater through fuels burned in units of pounds per million Btu.
Mi = Arithmetic average concentration of TSM in fuel type, 
i, analyzed according to Sec.  63.7521, in units of pounds per million 
Btu.
Qi = Fraction of total heat input from based fuel type, i, 
based on the fuel mixture that has the highest content of TSM. If you 
do not burn multiple fuel types during the performance test, it is not 
necessary to determine the value of this term. Insert a value of ``1'' 
for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of TSM.

    (3) You must establish the maximum mercury fuel input level 
(Mercuryinput) during the initial performance testing using 
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your boiler or process heater that has the highest content of 
mercury.
    (ii) During the compliance demonstration for mercury, you must 
determine the fraction of total heat input for each fuel burned 
(Qi) based on the fuel mixture that has the highest content 
of mercury, and the average mercury concentration of each fuel type 
burned (HGi).
    (iii) You must establish a maximum mercury input level using 
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.006

Where:

Mercuryinput = Maximum amount of mercury entering the boiler 
or process heater through fuels burned in units of pounds per million 
Btu.
HGi = Arithmetic average concentration of mercury in fuel 
type, i, analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
Qi = Fraction of total heat input from fuel type, i, based 
on the fuel mixture that has the highest mercury content. If you do not 
burn multiple fuel types during the performance test, it is not 
necessary to determine the value of this term. Insert a value of ``1'' 
for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of mercury.

    (4) You must establish parameter operating limits according to 
paragraphs (c)(4)(i) through (iv) of this section.
    (i) For a wet scrubber, you must establish the minimum scrubber 
effluent pH, liquid flowrate, and pressure drop as defined in Sec.  
63.7575, as your operating limits during the three-run performance 
test. If you use a wet scrubber and you conduct separate performance 
tests for particulate matter, HCl, and mercury emissions, you must 
establish one set of minimum scrubber effluent pH, liquid flowrate, and 
pressure drop operating limits. The minimum scrubber effluent pH 
operating limit must be established during the HCl performance test. If 
you conduct multiple performance tests, you must set the minimum liquid 
flowrate and pressure drop operating limits at the highest minimum 
values established during the performance tests.
    (ii) For an electrostatic precipitator, you must establish the 
minimum voltage and secondary current (or total power input), as 
defined in Sec.  63.7575, as your operating limits during the three-run 
performance test.
    (iii) For a dry scrubber, you must establish the minimum sorbent 
injection rate, as defined in Sec.  63.7575, as your operating limit 
during the three-run performance test.
    (iv) The operating limit for boilers or process heaters with fabric 
filters that choose to demonstrate continuous compliance through bag 
leak detection systems is that a bag leak detection system be installed 
according to the requirements in Sec.  63.7525, and that each fabric 
filter must be operated such that the bag leak detection system alarm 
does not sound more than 5 percent of the operating time during a 6-
month period.
    (d) If you elect to demonstrate compliance with an applicable 
emission limit through fuel analysis, you must conduct fuel analyses 
according to Sec.  63.7521 and follow the procedures in paragraphs 
(d)(1) through (5) of this section.
    (1) If you burn more than one fuel type, you must determine the 
fuel mixture you could burn in your boiler or process heater that would 
result in the maximum emission rates of the pollutants that you elect 
to demonstrate compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel 
pollutant concentration of the composite samples analyzed for each fuel 
type using the one-sided z-statistic test described in Equation 8 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR13SE04.012

Where:

P90 = 90th percentile confidence level pollutant 
concentration, in pounds per million Btu.

[[Page 55262]]

mean = Arithmetic average of the fuel pollutant concentration in the 
fuel samples analyzed according to Sec.  63.7521, in units of pounds 
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel 
samples analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
t = t distribution critical value for 90th percentile (0.1) probability 
for the appropriate degrees of freedom (number of samples minus one) as 
obtained from a Distribution Critical Value Table.

    (3) To demonstrate compliance with the applicable emission limit 
for HCl, the HCl emission rate that you calculate for your boiler or 
process heater using Equation 9 of this section must be less than the 
applicable emission limit for HCl.
[GRAPHIC] [TIFF OMITTED] TR13SE04.007

Where:

HCl = HCl emission rate from the boiler or process heater in units of 
pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of 
chlorine in fuel type, i, in units of pounds per million Btu as 
calculated according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based 
on the fuel mixture that has the highest content of chlorine. If you do 
not burn multiple fuel types, it is not necessary to determine the 
value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    (4) To demonstrate compliance with the applicable emission limit 
for TSM, the TSM emission rate that you calculate for your boiler or 
process heater using Equation 10 of this section must be less than the 
applicable emission limit for TSM.
[GRAPHIC] [TIFF OMITTED] TR13SE04.008

Where:

TSM = TSM emission rate from the boiler or process heater in units of 
pounds per million Btu.
Mi90 = 90th percentile confidence level concentration of TSM 
in fuel, i, in units of pounds per million Btu as calculated according 
to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based 
on the fuel mixture that has the highest content of total selected 
metals. If you do not burn multiple fuel types, it is not necessary to 
determine the value of this term. Insert a value of ``1'' for 
Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of TSM.

    (5) To demonstrate compliance with the applicable emission limit 
for mercury, the mercury emission rate that you calculate for your 
boiler or process heater using Equation 11 of this section must be less 
than the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TR13SE04.009

Where:

Mercury = Mercury emission rate from the boiler or process heater in 
units of pounds per million Btu.
HGi90 = 90th percentile confidence level concentration of 
mercury in fuel, i, in units of pounds per million Btu as calculated 
according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, based 
on the fuel mixture that has the highest mercury content. If you do not 
burn multiple fuel types, it is not necessary to determine the value of 
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest mercury content.

    (e) You must submit the Notification of Compliance Status 
containing the results of the initial compliance demonstration 
according to the requirements in Sec.  63.7545(e).

Continuous Compliance Requirements


Sec.  63.7535  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) You must monitor and collect data according to this section and 
the site-specific monitoring plan required by Sec.  63.7505(d).
    (b) Except for monitor malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must monitor continuously (or collect data at all required 
intervals) at all times that the affected source is operating.
    (c) You may not use data recorded during monitoring malfunctions, 
associated repairs, or required quality assurance or control activities 
in data averages and calculations used to report emission or operating 
levels. You must use all the data collected during all other periods in 
assessing the operation of the control device and associated control 
system. Boilers and process heaters that have an applicable carbon 
monoxide work practice standard and are required to install and operate 
a CEMS, may not use data recorded during periods when the boiler or 
process heater is operating at less than 50 percent of its rated 
capacity.


Sec.  63.7540  How do I demonstrate continuous compliance with the 
emission limits and work practice standards?

    (a) You must demonstrate continuous compliance with each emission 
limit, operating limit, and work practice standard in Tables 1 through 
4 to this subpart that applies to you according to the methods 
specified in Table 8 to this subpart and paragraphs (a)(1) through (10) 
of this section.
    (1) Following the date on which the initial performance test is 
completed or is required to be completed under Sec. Sec.  63.7 and 
63.7510, whichever date comes first, you must not operate above any of 
the applicable maximum operating limits or below any of the applicable 
minimum operating limits listed in Tables 2 through 4 to this subpart 
at all times except during periods of startup, shutdown and 
malfunction. Operating limits do not apply during performance tests. 
Operation above the established maximum or below the established 
minimum operating limits shall constitute a deviation of established 
operating limits.
    (2) You must keep records of the type and amount of all fuels 
burned in each boiler or process heater during the reporting period to 
demonstrate that all fuel types and mixtures of fuels burned would 
either result in lower emissions of TSM, HCl, and mercury, than the 
applicable emission limit for each pollutant (if you demonstrate 
compliance through fuel analysis), or result in lower fuel input of 
TSM, chlorine, and mercury than the maximum values calculated during 
the last performance tests (if you demonstrate compliance through 
performance testing).
    (3) If you demonstrate compliance with an applicable HCl emission 
limit through fuel analysis and you plan to burn a new type of fuel, 
you must recalculate the HCl emission rate using Equation 9 of Sec.  
63.7530 according to paragraphs (a)(3)(i) through (iii) of this 
section.

[[Page 55263]]

    (i) You must determine the chlorine concentration for any new fuel 
type in units of pounds per million Btu, based on supplier data or your 
own fuel analysis, according to the provisions in your site-specific 
fuel analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of chlorine.
    (iii) Recalculate the HCl emission rate from your boiler or process 
heater under these new conditions using Equation 9 of Sec.  63.7530. 
The recalculated HCl emission rate must be less than the applicable 
emission limit.
    (4) If you demonstrate compliance with an applicable HCl emission 
limit through performance testing and you plan to burn a new type of 
fuel type or a new mixture of fuels, you must recalculate the maximum 
chlorine input using Equation 5 of Sec.  63.7530. If the results of 
recalculating the maximum chlorine input using Equation 5 of Sec.  
63.7530 are higher than the maximum chlorine input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.7520 to demonstrate 
that the HCl emissions do not exceed the emission limit. You must also 
establish new operating limits based on this performance test according 
to the procedures in Sec.  63.7530(c).
    (5) If you demonstrate compliance with an applicable TSM emission 
limit through fuel analysis, and you plan to burn a new type of fuel, 
you must recalculate the TSM emission rate using Equation 10 of Sec.  
63.7530 according to the procedures specified in paragraphs (a)(5)(i) 
through (iii) of this section.
    (i) You must determine the TSM concentration for any new fuel type 
in units of pounds per million Btu, based on supplier data or your own 
fuel analysis, according to the provisions in your site-specific fuel 
analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of TSM.
    (iii) Recalculate the TSM emission rate from your boiler or process 
heater under these new conditions using Equation 10 of Sec.  63.7530. 
The recalculated TSM emission rate must be less than the applicable 
emission limit.
    (6) If you demonstrate compliance with an applicable TSM emission 
limit through performance testing, and you plan to burn a new type of 
fuel or a new mixture of fuels, you must recalculate the maximum TSM 
input using Equation 6 of Sec.  63.7530. If the results of 
recalculating the maximum total selected metals input using Equation 6 
of Sec.  63.7530 are higher than the maximum TSM input level 
established during the previous performance test, then you must conduct 
a new performance test within 60 days of burning the new fuel type or 
fuel mixture according to the procedures in Sec.  63.7520 to 
demonstrate that the TSM emissions do not exceed the emission limit. 
You must also establish new operating limits based on this performance 
test according to the procedures in Sec.  63.7530(c).
    (7) If you demonstrate compliance with an applicable mercury 
emission limit through fuel analysis, and you plan to burn a new type 
of fuel, you must recalculate the mercury emission rate using Equation 
11 of Sec.  63.7530 according to the procedures specified in paragraphs 
(a)(7)(i) through (iii) of this section.
    (i) You must determine the mercury concentration for any new fuel 
type in units of pounds per million Btu, based on supplier data or your 
own fuel analysis, according to the provisions in your site-specific 
fuel analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of mercury.
    (iii) Recalculate the mercury emission rate from your boiler or 
process heater under these new conditions using Equation 11 of Sec.  
63.7530. The recalculated mercury emission rate must be less than the 
applicable emission limit.
    (8) If you demonstrate compliance with an applicable mercury 
emission limit through performance testing, and you plan to burn a new 
type of fuel or a new mixture of fuels, you must recalculate the 
maximum mercury input using Equation 7 of Sec.  63.7530. If the results 
of recalculating the maximum mercury input using Equation 7 of Sec.  
63.7530 are higher than the maximum mercury input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.7520 to demonstrate 
that the mercury emissions do not exceed the emission limit. You must 
also establish new operating limits based on this performance test 
according to the procedures in Sec.  63.7530(c).
    (9) If your unit is controlled with a fabric filter, and you 
demonstrate continuous compliance using a bag leak detection system, 
you must initiate corrective action within 1 hour of a bag leak 
detection system alarm and complete corrective actions according to 
your SSMP, and operate and maintain the fabric filter system such that 
the alarm does not sound more than 5 percent of the operating time 
during a 6-month period. You must also keep records of the date, time, 
and duration of each alarm, the time corrective action was initiated 
and completed, and a brief description of the cause of the alarm and 
the corrective action taken. You must also record the percent of the 
operating time during each 6-month period that the alarm sounds. In 
calculating this operating time percentage, if inspection of the fabric 
filter demonstrates that no corrective action is required, no alarm 
time is counted. If corrective action is required, each alarm shall be 
counted as a minimum of 1 hour. If you take longer than 1 hour to 
initiate corrective action, the alarm time shall be counted as the 
actual amount of time taken to initiate corrective action.
    (10) If you have an applicable work practice standard for carbon 
monoxide, and you are required to install a CEMS according to Sec.  
63.7525(a), then you must meet the requirements in paragraphs 
(a)(10)(i) through (iii) of this section.
    (i) You must continuously monitor carbon monoxide according to 
Sec. Sec.  63.7525(a) and 63.7535.
    (ii) Maintain a carbon monoxide emission level below your 
applicable carbon monoxide work practice standard in Table 1 to this 
subpart at all times except during periods of startup, shutdown, 
malfunction, and when your boiler or process heater is operating at 
less than 50 percent of rated capacity.
    (iii) Keep records of carbon monoxide levels according to Sec.  
63.7555(b).
    (b) You must report each instance in which you did not meet each 
emission limit, operating limit, and work practice standard in Tables 1 
through 4 to this subpart that apply to you. You must also report each 
instance during a startup, shutdown, or malfunction when you did not 
meet each applicable emission limit, operating limit, and work practice 
standard. These instances are deviations from the emission limits and 
work practice standards in this subpart. These deviations must be 
reported according to the requirements in Sec.  63.7550.
    (c) During periods of startup, shutdown, and malfunction, you must 
operate in accordance with the SSMP as required in Sec.  63.7505(e).
    (d) Consistent with Sec. Sec.  63.6(e)and 63.7(e)(1), deviations 
that occur during a period of startup, shutdown, or malfunction are not 
violations if you demonstrate to the EPA Administrator's satisfaction 
that you were operating in accordance with your SSMP. The EPA 
Administrator will determine whether

[[Page 55264]]

deviations that occur during a period of startup, shutdown, or 
malfunction are violations, according to the provisions in Sec.  
63.6(e).


Sec.  63.7541  How do I demonstrate continuous compliance under the 
emission averaging provision?

    (a) Following the compliance date, the owner or operator must 
demonstrate compliance with this subpart on a continuous basis by 
meeting the requirements of paragraphs (a)(1) through (4) of this 
section.
    (1) For each calendar month, demonstrate compliance with the 
average weighted emissions limit for the existing large solid fuel 
boilers participating in the emissions averaging option as determined 
in Sec.  63.7522(f) and (g);
    (2) For each existing solid fuel boiler participating in the 
emissions averaging option that is equipped with a dry control system, 
maintain opacity at or below the applicable limit;
    (3) For each existing solid fuel boiler participating in the 
emissions averaging option that is equipped with a wet scrubber, 
maintain the 3-hour average parameter values at or below the operating 
limits established during the most recent performance test; and
    (4) For each existing solid fuel boiler participating in the 
emissions averaging option that has an approved alternative operating 
plan, maintain the 3-hour average parameter values at or below the 
operating limits established in the most recent performance test.
    (b) Any instance where the owner or operator fails to comply with 
the continuous monitoring requirements in paragraphs (a)(1) through (4) 
of this section, except during periods of startup, shutdown, and 
malfunction, is a deviation.

Notification, Reports, and Records


Sec.  63.7545  What notifications must I submit and when?

    (a) You must submit all of the notifications in Sec. Sec.  63.7(b) 
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply 
to you by the dates specified.
    (b) As specified in Sec.  63.9(b)(2), if you startup your affected 
source before November 12, 2004, you must submit an Initial 
Notification not later than 120 days after November 12, 2004. The 
Initial Notification must include the information required in 
paragraphs (b)(1) and (2) of this section, as applicable.
    (1) If your affected source has an annual capacity factor of 
greater than 10 percent, your Initial Notification must include the 
information required by Sec.  63.9(b)(2).
    (2) If your affected source has a federally enforceable permit that 
limits the annual capacity factor to less than or equal to 10 percent 
such that the unit is in one of the limited use subcategories (the 
limited use solid fuel subcategory, the limited use liquid fuel 
subcategory, or the limited use gaseous fuel subcategory), your Initial 
Notification must include the information required by Sec.  63.9(b)(2) 
and also a signed statement indicating your affected source has a 
federally enforceable permit that limits the annual capacity factor to 
less than or equal to 10 percent.
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup 
your new or reconstructed affected source on or after November 12, 
2004, you must submit an Initial Notification not later than 15 days 
after the actual date of startup of the affected source.
    (d) If you are required to conduct a performance test you must 
submit a Notification of Intent to conduct a performance test at least 
30 days before the performance test is scheduled to begin.
    (e) If you are required to conduct an initial compliance 
demonstration as specified in Sec.  63.7530(a), you must submit a 
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii). 
For each initial compliance demonstration, you must submit the 
Notification of Compliance Status, including all performance test 
results and fuel analyses, before the close of business on the 60th day 
following the completion of the performance test and/or other initial 
compliance demonstrations according to Sec.  63.10(d)(2). The 
Notification of Compliance Status report must contain all the 
information specified in paragraphs (e)(1) through (9), as applicable.
    (1) A description of the affected source(s) including 
identification of which subcategory the source is in, the capacity of 
the source, a description of the add-on controls used on the source 
description of the fuel(s) burned, and justification for the fuel(s) 
burned during the performance test.
    (2) Summary of the results of all performance tests, fuel analyses, 
and calculations conducted to demonstrate initial compliance including 
all established operating limits.
    (3) Identification of whether you are complying with the 
particulate matter emission limit or the alternative total selected 
metals emission limit.
    (4) Identification of whether you plan to demonstrate compliance 
with each applicable emission limit through performance testing or fuel 
analysis.
    (5) Identification of whether you plan to demonstrate compliance by 
emissions averaging.
    (6) A signed certification that you have met all applicable 
emission limits and work practice standards.
    (7) A summary of the carbon monoxide emissions monitoring data and 
the maximum carbon monoxide emission levels recorded during the 
performance test to show that you have met any applicable work practice 
standard in Table 1 to this subpart.
    (8) If your new or reconstructed boiler or process heater is in one 
of the liquid fuel subcategories and burns only liquid fossil fuels 
other than residual oil either alone or in combination with gaseous 
fuels, you must submit a signed statement certifying this in your 
Notification of Compliance Status report.
    (9) If you had a deviation from any emission limit or work practice 
standard, you must also submit a description of the deviation, the 
duration of the deviation, and the corrective action taken in the 
Notification of Compliance Status report.


Sec.  63.7550  What reports must I submit and when?

    (a) You must submit each report in Table 9 to this subpart that 
applies to you.
    (b) Unless the EPA Administrator has approved a different schedule 
for submission of reports under Sec.  63.10(a), you must submit each 
report by the date in Table 9 to this subpart and according to the 
requirements in paragraphs (b)(1) through (5) of this section.
    (1) The first compliance report must cover the period beginning on 
the compliance date that is specified for your affected source in Sec.  
63.7495 and ending on June 30 or December 31, whichever date is the 
first date that occurs at least 180 days after the compliance date that 
is specified for your source in Sec.  63.7495.
    (2) The first compliance report must be postmarked or delivered no 
later than July 31 or January 31, whichever date is the first date 
following the end of the first calendar half after the compliance date 
that is specified for your source in Sec.  63.7495.
    (3) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (4) Each subsequent compliance report must be postmarked or 
delivered

[[Page 55265]]

no later than July 31 or January 31, whichever date is the first date 
following the end of the semiannual reporting period.
    (5) For each affected source that is subject to permitting 
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the 
permitting authority has established dates for submitting semiannual 
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance 
reports according to the dates the permitting authority has established 
instead of according to the dates in paragraphs (b)(1) through (4) of 
this section.
    (c) The compliance report must contain the information required in 
paragraphs (c)(1) through (11) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official with that official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (3) Date of report and beginning and ending dates of the reporting 
period.
    (4) The total fuel use by each affected source subject to an 
emission limit, for each calendar month within the semiannual reporting 
period, including, but not limited to, a description of the fuel and 
the total fuel usage amount with units of measure.
    (5) A summary of the results of the annual performance tests and 
documentation of any operating limits that were reestablished during 
this test, if applicable.
    (6) A signed statement indicating that you burned no new types of 
fuel. Or, if you did burn a new type of fuel, you must submit the 
calculation of chlorine input, using Equation 5 of Sec.  63.7530, that 
demonstrates that your source is still within its maximum chlorine 
input level established during the previous performance testing (for 
sources that demonstrate compliance through performance testing) or you 
must submit the calculation of HCl emission rate using Equation 9 of 
Sec.  63.7530 that demonstrates that your source is still meeting the 
emission limit for HCl emissions (for boilers or process heaters that 
demonstrate compliance through fuel analysis). If you burned a new type 
of fuel, you must submit the calculation of TSM input, using Equation 6 
of Sec.  63.7530, that demonstrates that your source is still within 
its maximum TSM input level established during the previous performance 
testing (for sources that demonstrate compliance through performance 
testing), or you must submit the calculation of TSM emission rate using 
Equation 10 of Sec.  63.7530 that demonstrates that your source is 
still meeting the emission limit for TSM emissions (for boilers or 
process heaters that demonstrate compliance through fuel analysis). If 
you burned a new type of fuel, you must submit the calculation of 
mercury input, using Equation 7 of Sec.  63.7530, that demonstrates 
that your source is still within its maximum mercury input level 
established during the previous performance testing (for sources that 
demonstrate compliance through performance testing), or you must submit 
the calculation of mercury emission rate using Equation 11 of Sec.  
63.7530 that demonstrates that your source is still meeting the 
emission limit for mercury emissions (for boilers or process heaters 
that demonstrate compliance through fuel analysis).
    (7) If you wish to burn a new type of fuel and you can not 
demonstrate compliance with the maximum chlorine input operating limit 
using Equation 5 of Sec.  63.7530, the maximum TSM input operating 
limit using Equation 6 of Sec.  63.7530, or the maximum mercury input 
operating limit using Equation 7 of Sec.  63.7530, you must include in 
the compliance report a statement indicating the intent to conduct a 
new performance test within 60 days of starting to burn the new fuel.
    (8) The hours of operation for each boiler and process heater that 
is subject to an emission limit for each calendar month within the 
semiannual reporting period. This requirement applies only to limited 
use boilers and process heaters.
    (9) If you had a startup, shutdown, or malfunction during the 
reporting period and you took actions consistent with your SSMP, the 
compliance report must include the information in Sec.  63.10(d)(5)(i).
    (10) If there are no deviations from any emission limits or 
operating limits in this subpart that apply to you, and there are no 
deviations from the requirements for work practice standards in this 
subpart, a statement that there were no deviations from the emission 
limits, operating limits, or work practice standards during the 
reporting period.
    (11) If there were no periods during which the CMSs, including 
CEMS, COMS, and CPMS, were out of control as specified in Sec.  
63.8(c)(7), a statement that there were no periods during which the 
CMSs were out of control during the reporting period.
    (d) For each deviation from an emission limit or operating limit in 
this subpart and for each deviation from the requirements for work 
practice standards in this subpart that occurs at an affected source 
where you are not using a CMSs to comply with that emission limit, 
operating limit, or work practice standard, the compliance report must 
contain the information in paragraphs (c)(1) through (10) of this 
section and the information required in paragraphs (d)(1) through (4) 
of this section. This includes periods of startup, shutdown, and 
malfunction.
    (1) The total operating time of each affected source during the 
reporting period.
    (2) A description of the deviation and which emission limit, 
operating limit, or work practice standard from which you deviated.
    (3) Information on the number, duration, and cause of deviations 
(including unknown cause), as applicable, and the corrective action 
taken.
    (4) A copy of the test report if the annual performance test showed 
a deviation from the emission limit for particulate matter or the 
alternative TSM limit, a deviation from the HCl emission limit, or a 
deviation from the mercury emission limit.
    (e) For each deviation from an emission limitation and operating 
limit or work practice standard in this subpart occurring at an 
affected source where you are using a CMS to comply with that emission 
limit, operating limit, or work practice standard, you must include the 
information in paragraphs (c) (1) through (10) of this section and the 
information required in paragraphs (e) (1) through (12) of this 
section. This includes periods of startup, shutdown, and malfunction 
and any deviations from your site-specific monitoring plan as required 
in Sec.  63.7505(d).
    (1) The date and time that each malfunction started and stopped and 
description of the nature of the deviation (i.e., what you deviated 
from).
    (2) The date and time that each CMS was inoperative, except for 
zero (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control, 
including the information in Sec.  63.8(c)(8).
    (4) The date and time that each deviation started and stopped, and 
whether each deviation occurred during a period of startup, shutdown, 
or malfunction or during another period.
    (5) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (6) A breakdown of the total duration of the deviations during the 
reporting period into those that are due to startup, shutdown, control 
equipment problems,

[[Page 55266]]

process problems, other known causes, and other unknown causes.
    (7) A summary of the total duration of CMSs downtime during the 
reporting period and the total duration of CMS downtime as a percent of 
the total source operating time during that reporting period.
    (8) An identification of each parameter that was monitored at the 
affected source for which there was a deviation, including opacity, 
carbon monoxide, and operating parameters for wet scrubbers and other 
control devices.
    (9) A brief description of the source for which there was a 
deviation.
    (10) A brief description of each CMS for which there was a 
deviation.
    (11) The date of the latest CMS certification or audit for the 
system for which there was a deviation.
    (12) A description of any changes in CMSs, processes, or controls 
since the last reporting period for the source for which there was a 
deviation.
    (f) Each affected source that has obtained a title V operating 
permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all 
deviations as defined in this subpart in the semiannual monitoring 
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A). If an affected source submits a compliance report 
pursuant to Table 9 to this subpart along with, or as part of, the 
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all 
required information concerning deviations from any emission limit, 
operating limit, or work practice requirement in this subpart, 
submission of the compliance report satisfies any obligation to report 
the same deviations in the semiannual monitoring report. However, 
submission of a compliance report does not otherwise affect any 
obligation the affected source may have to report deviations from 
permit requirements to the permit authority.
    (g) If you operate a new gaseous fuel unit that is subject to the 
work practice standard specified in Table 1 to this subpart, and you 
intend to use a fuel other than natural gas or equivalent to fire the 
affected unit, you must submit a notification of alternative fuel use 
within 48 hours of the declaration of a period of natural gas 
curtailment or supply interruption, as defined in Sec.  63.7575. The 
notification must include the information specified in paragraphs 
(g)(1) through (5) of this section.
    (1) Company name and address.
    (2) Identification of the affected unit.
    (3) Reason you are unable to use natural gas or equivalent fuel, 
including the date when the natural gas curtailment was declared or the 
natural gas supply interruption began.
    (4) Type of alternative fuel that you intend to use.
    (5) Dates when the alternative fuel use is expected to begin and 
end.


Sec.  63.7555  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) through 
(3) of this section.
    (1) A copy of each notification and report that you submitted to 
comply with this subpart, including all documentation supporting any 
Initial Notification or Notification of Compliance Status or semiannual 
compliance report that you submitted, according to the requirements in 
Sec.  63.10(b)(2)(xiv).
    (2) The records in Sec.  63.6(e)(3)(iii) through (v) related to 
startup, shutdown, and malfunction.
    (3) Records of performance tests, fuel analyses, or other 
compliance demonstrations, performance evaluations, and opacity 
observations as required in Sec.  63.10(b)(2)(viii).
    (b) For each CEMS, CPMS, and COMS, you must keep records according 
to paragraphs (b)(1) through (5) of this section.
    (1) Records described in Sec.  63.10(b)(2) (vi) through (xi).
    (2) Monitoring data for continuous opacity monitoring system during 
a performance evaluation as required in Sec.  63.6(h)(7)(i) and (ii).
    (3) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (4) Request for alternatives to relative accuracy test for CEMS as 
required in Sec.  63.8(f)(6)(i).
    (5) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (c) You must keep the records required in Table 8 to this subpart 
including records of all monitoring data and calculated averages for 
applicable operating limits such as opacity, pressure drop, carbon 
monoxide, and pH to show continuous compliance with each emission 
limit, operating limit, and work practice standard that applies to you.
    (d) For each boiler or process heater subject to an emission limit, 
you must also keep the records in paragraphs (d)(1) through (5) of this 
section.
    (1) You must keep records of monthly fuel use by each boiler or 
process heater, including the type(s) of fuel and amount(s) used.
    (2) You must keep records of monthly hours of operation by each 
boiler or process heater. This requirement applies only to limited-use 
boilers and process heaters.
    (3) A copy of all calculations and supporting documentation of 
maximum chlorine fuel input, using Equation 5 of Sec.  63.7530, that 
were done to demonstrate continuous compliance with the HCl emission 
limit, for sources that demonstrate compliance through performance 
testing. For sources that demonstrate compliance through fuel analysis, 
a copy of all calculations and supporting documentation of HCl emission 
rates, using Equation 9 of Sec.  63.7530, that were done to demonstrate 
compliance with the HCl emission limit. Supporting documentation should 
include results of any fuel analyses and basis for the estimates of 
maximum chlorine fuel input or HCl emission rates. You can use the 
results from one fuel analysis for multiple boilers and process heaters 
provided they are all burning the same fuel type. However, you must 
calculate chlorine fuel input, or HCl emission rate, for each boiler 
and process heater.
    (4) A copy of all calculations and supporting documentation of 
maximum TSM fuel input, using Equation 6 of Sec.  63.7530, that were 
done to demonstrate continuous compliance with the TSM emission limit 
for sources that demonstrate compliance through performance testing. 
For sources that demonstrate compliance through fuel analysis, a copy 
of all calculations and supporting documentation of TSM emission rates, 
using Equation 10 of Sec.  63.7530, that were done to demonstrate 
compliance with the TSM emission limit. Supporting documentation should 
include results of any fuel analyses and basis for the estimates of 
maximum TSM fuel input or TSM emission rates. You can use the results 
from one fuel analysis for multiple boilers and process heaters 
provided they are all burning the same fuel type. However, you must 
calculate TSM fuel input, or TSM emission rates, for each boiler and 
process heater.
    (5) A copy of all calculations and supporting documentation of 
maximum mercury fuel input, using Equation 7 of Sec.  63.7530, that 
were done to demonstrate continuous compliance with the mercury 
emission limit for sources that demonstrate compliance through 
performance testing. For sources that demonstrate compliance through 
fuel analysis, a copy of all calculations and supporting documentation 
of mercury emission rates, using Equation 11 of Sec.  63.7530, that 
were done to demonstrate compliance with the mercury emission limit. 
Supporting documentation should

[[Page 55267]]

include results of any fuel analyses and basis for the estimates of 
maximum mercury fuel input or mercury emission rates. You can use the 
results from one fuel analysis for multiple boilers and process heaters 
provided they are all burning the same fuel type. However, you must 
calculate mercury fuel input, or mercury emission rates, for each 
boiler and process heater.
    (e) If your boiler or process heater is subject to an emission 
limit or work practice standard in Table 1 to this subpart and has a 
federally enforceable permit that limits the annual capacity factor to 
less than or equal to 10 percent such that the unit is in one of the 
limited use subcategories, you must keep the records in paragraphs 
(e)(1) and (2) of this section.
    (1) A copy of the federally enforceable permit that limits the 
annual capacity factor of the source to less than or equal to 10 
percent.
    (2) Fuel use records for the days the boiler or process heater was 
operating.


Sec.  63.7560  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec.  63.10(b)(1).
    (b) As specified in Sec.  63.10(b)(1), you must keep each record 
for 5 years following the date of each occurrence, measurement, 
maintenance, corrective action, report, or record.
    (c) You must keep each record on site for at least 2 years after 
the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec.  63.10(b)(1). You can keep 
the records off site for the remaining 3 years.

Other Requirements and Information


Sec.  63.7565  What parts of the General Provisions apply to me?

    Table 10 to this subpart shows which parts of the General 
Provisions in Sec. Sec.  63.1 through 63.15 apply to you.


Sec.  63.7570  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by U.S. EPA, or a 
delegated authority such as your State, local, or tribal agency. If the 
EPA Administrator has delegated authority to your State, local, or 
tribal agency, then that agency (as well as the U.S. EPA) has the 
authority to implement and enforce this subpart. You should contact 
your EPA Regional Office to find out if this subpart is delegated to 
your State, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a State, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities listed in paragraphs (b)(1) through (5) of 
this section are retained by the EPA Administrator and are not 
transferred to the State, local, or tribal agency, however, the U.S. 
EPA retains oversight of this subpart and can take enforcement actions, 
as appropriate.
    (1) Approval of alternatives to the non-opacity emission limits and 
work practice standards in Sec.  63.7500(a) and (b) under Sec.  
63.6(g).
    (2) Approval of alternative opacity emission limits in Sec.  
63.7500(a) under Sec.  63.6(h)(9).
    (3) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90.
    (4) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90.
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(f) and as defined in Sec.  63.90.


Sec.  63.7575  What definitions apply to this subpart?

    Terms used in this subpart are defined in the CAA, in Sec.  63.2 
(the General Provisions), and in this section as follows:
    Annual capacity factor means the ratio between the actual heat 
input to a boiler or process heater from the fuels burned during a 
calendar year, and the potential heat input to the boiler or process 
heater had it been operated for 8,760 hours during a year at the 
maximum steady state design heat input capacity.
    Bag leak detection system means an instrument that is capable of 
monitoring particulate matter loadings in the exhaust of a fabric 
filter (i.e., baghouse) in order to detect bag failures. A bag leak 
detection system includes, but is not limited to, an instrument that 
operates on electrodynamic, triboelectric, light scattering, light 
transmittance, or other principle to monitor relative particulate 
matter loadings.
    Biomass fuel means unadulterated wood as defined in this subpart, 
wood residue, and wood products (e.g., trees, tree stumps, tree limbs, 
bark, lumber, sawdust, sanderdust, chips, scraps, slabs, millings, and 
shavings); animal litter; vegetative agricultural and silvicultural 
materials, such as logging residues (slash), nut and grain hulls and 
chaff (e.g., almond, walnut, peanut, rice, and wheat), bagasse, orchard 
prunings, corn stalks, coffee bean hulls and grounds.
    Blast furnace gas fuel-fired boiler or process heater means an 
industrial/commercial/institutional boiler or process heater that 
receives 90 percent or more of its total heat input (based on an annual 
average) from blast furnace gas.
    Boiler means an enclosed device using controlled flame combustion 
and having the primary purpose of recovering thermal energy in the form 
of steam or hot water. Waste heat boilers are excluded from this 
definition.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials in ASTM D388-991 .\1\, ``Standard Specification for 
Classification of Coals by Rank \1\'' (incorporated by reference, see 
Sec.  63.14(b)), coal refuse, and petroleum coke. Synthetic fuels 
derived from coal for the purpose of creating useful heat including but 
not limited to, solvent-refined coal, coal-oil mixtures, and coal-water 
mixtures, for the purposes of this subpart. Coal derived gases are 
excluded from this definition.
    Coal refuse means any by-product of coal mining or coal cleaning 
operations with an ash content greater than 50 percent (by weight) and 
a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per 
pound) on a dry basis.
    Commercial/institutional boiler means a boiler used in commercial 
establishments or institutional establishments such as medical centers, 
research centers, institutions of higher education, hotels, and 
laundries to provide electricity, steam, and/or hot water.
    Construction/demolition material means waste building material that 
result from the construction or demolition operations on houses and 
commercial and industrial buildings.
    Deviation. (1) Deviation means any instance in which an affected 
source subject to this subpart, or an owner or operator of such a 
source:
    (i) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;
    (ii) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit; or
    (iii) Fails to meet any emission limit, operating limit, or work 
practice standard in this subpart during startup, shutdown, or 
malfunction, regardless or whether or not such failure is permitted by 
this subpart.
    (2) A deviation is not always a violation. The determination of 
whether a deviation constitutes a violation of the

[[Page 55268]]

standard is up to the discretion of the entity responsible for 
enforcement of the standards.
    Distillate oil means fuel oils, including recycled oils, that 
comply with the specifications for fuel oil numbers 1 and 2, as defined 
by the American Society for Testing and Materials in ASTM D396-02a, 
``Standard Specifications for Fuel Oils 1'' (incorporated by 
reference, see Sec.  63.14(b)).
    Dry scrubber means an add-on air pollution control system that 
injects dry alkaline sorbent (dry injection) or sprays an alkaline 
sorbent (spray dryer) to react with and neutralize acid gas in the 
exhaust stream forming a dry powder material. Sorbent injection systems 
in fluidized bed boilers and process heaters are included in this 
definition.
    Electric utility steam generating unit means a fossil fuel-fired 
combustion unit of more than 25 megawatts that serves a generator that 
produces electricity for sale. A fossil fuel-fired unit that 
cogenerates steam and electricity and supplies more than one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit.
    Electrostatic precipitator means an add-on air pollution control 
device used to capture particulate matter by charging the particles 
using an electrostatic field, collecting the particles using a grounded 
collecting surface, and transporting the particles into a hopper.
    Fabric filter means an add-on air pollution control device used to 
capture particulate matter by filtering gas streams through filter 
media, also known as a baghouse.
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including the requirements of 40 
CFR parts 60 and 61, requirements within any applicable State 
implementation plan, and any permit requirements established under 40 
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
    Firetube boiler means a boiler in which hot gases of combustion 
pass through the tubes and water contacts the outside surfaces of the 
tubes.
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid, liquid, or gaseous fuel derived from such materials.
    Fuel type means each category of fuels that share a common name or 
classification. Examples include, but are not limited to, bituminous 
coal, subbituminous coal, lignite, anthracite, biomass, construction/
demolition material, salt water laden wood, creosote treated wood, 
tires, residual oil. Individual fuel types received from different 
suppliers are not considered new fuel types except for construction/
demolition material.
    Gaseous fuel includes, but is not limited to, natural gas, process 
gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast 
furnace gas is exempted from this definition.
    Heat input means heat derived from combustion of fuel in a boiler 
or process heater and does not include the heat input from preheated 
combustion air, recirculated flue gases, or exhaust gases from other 
sources such as gas turbines, internal combustion engines, kilns, etc.
    Hot water heater means a closed vessel with a capacity of no more 
than 120 U.S. gallons in which water is heated by combustion of gaseous 
or liquid fuel and is withdrawn for use external to the vessel at 
pressures not exceeding 160 psig, including the apparatus by which the 
heat is generated and all controls and devices necessary to prevent 
water temperatures from exceeding 210[deg]F (99[deg]C).
    Industrial boiler means a boiler used in manufacturing, processing, 
mining, and refining or any other industry to provide steam, hot water, 
and/or electricity.
    Large gaseous fuel subcategory includes any watertube boiler or 
process heater that burns gaseous fuels not combined with any solid 
fuels, burns liquid fuel only during periods of gas curtailment or gas 
supply emergencies, has a rated capacity of greater than 10 MMBtu per 
hour heat input, and has an annual capacity factor of greater than 10 
percent.
    Large liquid fuel subcategory includes any watertube boiler or 
process heater that does not burn any solid fuel and burns any liquid 
fuel either alone or in combination with gaseous fuels, has a rated 
capacity of greater than 10 MMBtu per hour heat input, and has an 
annual capacity factor of greater than 10 percent. Large gaseous fuel 
boilers and process heaters that burn liquid fuel during periods of gas 
curtailment or gas supply emergencies are not included in this 
definition.
    Large solid fuel subcategory includes any watertube boiler or 
process heater that burns any amount of solid fuel either alone or in 
combination with liquid or gaseous fuels, has a rated capacity of 
greater than 10 MMBtu per hour heat input, and has an annual capacity 
factor of greater than 10 percent.
    Limited use gaseous fuel subcategory includes any watertube boiler 
or process heater that burns gaseous fuels not combined with any liquid 
or solid fuels, burns liquid fuel only during periods of gas 
curtailment or gas supply emergencies, has a rated capacity of greater 
than 10 MMBtu per hour heat input, and has a federally enforceable 
annual average capacity factor of equal to or less than 10 percent.
    Limited use liquid fuel subcategory includes any watertube boiler 
or process heater that does not burn any solid fuel and burns any 
liquid fuel either alone or in combination with gaseous fuels, has a 
rated capacity of greater than 10 MMBtu per hour heat input, and has a 
federally enforceable annual average capacity factor of equal to or 
less than 10 percent. Limited use gaseous fuel boilers and process 
heaters that burn liquid fuel during periods of gas curtailment or gas 
supply emergencies are not included in this definition.
    Limited use solid fuel subcategory includes any watertube boiler or 
process heater that burns any amount of solid fuel either alone or in 
combination with liquid or gaseous fuels, has a rated capacity of 
greater than 10 MMBtu per hour heat input, and has a federally 
enforceable annual average capacity factor of equal to or less than 10 
percent.
    Liquid fossil fuel means petroleum, distillate oil, residual oil 
and any form of liquid fuel derived from such material.
    Liquid fuel includes, but is not limited to, distillate oil, 
residual oil, waste oil, and process liquids.
    Minimum pressure drop means 90 percent of the lowest test-run 
average pressure drop measured according to Table 7 to this subpart 
during the most recent performance test demonstrating compliance with 
the applicable emission limit.
    Minimum scrubber effluent pH means 90 percent of the lowest test-
run average effluent pH measured at the outlet of the wet scrubber 
according to Table 7 to this subpart during the most recent performance 
test demonstrating compliance with the applicable hydrogen chloride 
emission limit.
    Minimum scrubber flow rate means 90 percent of the lowest test-run 
average flow rate measured according to Table 7 to this subpart during 
the most recent performance test demonstrating compliance with the 
applicable emission limit.
    Minimum sorbent flow rate means 90 percent of the lowest test-run 
average sorbent (or activated carbon) flow rate measured according to 
Table 7 to this subpart during the most recent performance test 
demonstrating compliance with the applicable emission limits.

[[Page 55269]]

    Minimum voltage or amperage means 90 percent of the lowest test-run 
average voltage or amperage to the electrostatic precipitator measured 
according to Table 7 to this subpart during the most recent performance 
test demonstrating compliance with the applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath the earth's surface, of 
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society for 
Testing and Materials in ASTM D1835-03a, ``Standard Specification for 
Liquid Petroleum Gases'' (incorporated by reference, see Sec.  
63.14(b)).
    Opacity means the degree to which emissions reduce the transmission 
of light and obscure the view of an object in the background.
    Particulate matter means any finely divided solid or liquid 
material, other than uncombined water, as measured by the test methods 
specified under this subpart, or an alternative method.
    Period of natural gas curtailment or supply interruption means a 
period of time during which the supply of natural gas to an affected 
facility is halted for reasons beyond the control of the facility. An 
increase in the cost or unit price of natural gas does not constitute a 
period of natural gas curtailment or supply interruption.
    Process heater means an enclosed device using controlled flame, 
that is not a boiler, and the unit's primary purpose is to transfer 
heat indirectly to a process material (liquid, gas, or solid) or to a 
heat transfer material for use in a process unit, instead of generating 
steam. Process heaters are devices in which the combustion gases do not 
directly come into contact with process materials. Process heaters do 
not include units used for comfort heat or space heat, food preparation 
for on-site consumption, or autoclaves.
    Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, 
as defined by the American Society for Testing and Materials in ASTM 
D396-02a, ``Standard Specifications for Fuel Oils 1'' 
(incorporated by reference, see Sec.  63.14(b)).
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    Small gaseous fuel subcategory includes any firetube boiler that 
burns gaseous fuels not combined with any solid fuels and burns liquid 
fuel only during periods of gas curtailment or gas supply emergencies, 
and any boiler or process heater that burns gaseous fuels not combined 
with any solid fuels, burns liquid fuel only during periods of gas 
curtailment or gas supply emergencies, and has a rated capacity of less 
than or equal to 10 MMBtu per hour heat input.
    Small liquid fuel subcategory includes any firetube boiler that 
does not burn any solid fuel and burns any liquid fuel either alone or 
in combination with gaseous fuels, and any boiler or process heater 
that does not burn any solid fuel and burns any liquid fuel either 
alone or in combination with gaseous fuels, and has a rated capacity of 
less than or equal to 10 MMBtu per hour heat input. Small gaseous fuel 
boilers and process heaters that burn liquid fuel during periods of gas 
curtailment or gas supply emergencies are not included in this 
definition.
    Small solid fuel subcategory includes any firetube boiler that 
burns any amount of solid fuel either alone or in combination with 
liquid or gaseous fuels, and any other boiler or process heater that 
burns any amount of solid fuel either alone or in combination with 
liquid or gaseous fuels and has a rated capacity of less than or equal 
to 10 MMBtu per hour heat input.
    Solid fuel includes, but is not limited to, coal, wood, biomass, 
tires, plastics, and other nonfossil solid materials.
    Temporary boiler means any gaseous or liquid fuel boiler that is 
designed to, and is capable of, being carried or moved from one 
location to another. A temporary boiler that remains at a location for 
more than 180 consecutive days is no longer considered to be a 
temporary boiler. Any temporary boiler that replaces a temporary boiler 
at a location and is intended to perform the same or similar function 
will be included in calculating the consecutive time period.
    Total selected metals means the combination of the following 
metallic HAP: arsenic, beryllium, cadmium, chromium, lead, manganese, 
nickel and selenium.
    Unadulterated wood means wood or wood products that have not been 
painted, pigment-stained, or pressure treated with compounds such as 
chromate copper arsenate, pentachlorophenol, and creosote. Plywood, 
particle board, oriented strand board, and other types of wood products 
bound by glues and resins are included in this definition.
    Waste heat boiler means a device that recovers normally unused 
energy and converts it to usable heat. Waste heat boilers incorporating 
duct or supplemental burners that are designed to supply 50 percent or 
more of the total rated heat input capacity of the waste heat boiler 
are not considered waste heat boilers, but are considered boilers. 
Waste heat boilers are also referred to as heat recovery steam 
generators.
    Watertube boiler means a boiler in which water passes through the 
tubes and hot gases of combustion pass over the outside surfaces of the 
tubes.
    Wet scrubber means any add-on air pollution control device that 
mixes an aqueous stream or slurry with the exhaust gases from a boiler 
or process heater to control emissions of particulate matter and/or to 
absorb and neutralize acid gases, such as hydrogen chloride.
    Work practice standard means any design, equipment, work practice, 
or operational standard, or combination thereof, that is promulgated 
pursuant to section 112(h) of the CAA.

Tables to Subpart DDDDD of Part 63

 Table 1 to Subpart DDDDD of Part 63.--Emission Limits and Work Practice
                                Standards
     As stated in Sec.   63.7500, you must comply with the following
         applicable emission limits and work practice standards:
------------------------------------------------------------------------
                                                      You must meet the
  If your boiler or process                          following emission
      heater is in this         For the following      limits and work
      subcategory . . .         pollutants . . .    practice standards .
                                                             . .
------------------------------------------------------------------------
1. New or reconstructed       a. Particulate        0.025 lb per MMBtu
 large solid fuel.             Matter (or Total      of heat input; or
                               Selected Metals).     (0.0003 lb per
                                                     MMBtu of heat
                                                     input).
                              b. Hydrogen Chloride  0.02 lb per MMBtu of
                                                     heat input.
                              c. Mercury..........  0.000003 lb per
                                                     MMBtu of heat
                                                     input.
                              d. Carbon Monoxide..  400 ppm by volume on
                                                     a dry basis
                                                     corrected to 7
                                                     percent oxygen (30-
                                                     day rolling average
                                                     for units 100 MMBtu/
                                                     hr or greater, 3-
                                                     run average for
                                                     units less than 100
                                                     MMBtu/hr).

[[Page 55270]]

 
2. New or reconstructed       a. Particulate        0.025 lb per MMBtu
 limited use solid fuel.       Matter (or Total      of heat input; or
                               Selected Metals).     (0.0003 lb per
                                                     MMBtu of heat
                                                     input).
                              b. Hydrogen Chloride  0.02 lb per MMBtu of
                                                     heat input.
                              c. Mercury..........  0.000003 lb per
                                                     MMBtu of heat
                                                     input.
                              d. Carbon Monoxide..  400 ppm by volume on
                                                     a dry basis
                                                     corrected to 7
                                                     percent oxygen (3-
                                                     run average).
3. New or reconstructed       a. Particulate        0.025 lb per MMBtu
 small solid fuel.             Matter (or Total      of heat input; or
                               Selected Metals).     (0.0003 lb per
                                                     MMBtu of heat
                                                     input).
                              b. Hydrogen Chloride  0.02 lb per MMBtu of
                                                     heat input.
                              c. Mercury..........  0.000003 lb per
                                                     MMBtu of heat
                                                     input.
4. New reconstructed large    a. Particulate        0.03 lb per MMBtu of
 liquid fuel.                  Matter.               heat input.
                              b. Hydrogen Chloride  0.0005 lb per MMBtu
                                                     of heat input.
                              c. Carbon Monoxide..  400 ppm by volume on
                                                     a dry basis
                                                     corrected to 3
                                                     percent oxygen (30-
                                                     day rolling average
                                                     for units 100 MMBtu/
                                                     hr or greater, 3-
                                                     run average for
                                                     units less than 100
                                                     MMBtu/hr).
5. New or reconstructed       a. Particulate        0.03 lb per MMBtu of
 limited use liquid fuel.      Matter.               heat input.
                              b. Hydrogen Chloride  0.0009 lb per MMBtu
                                                     of heat input.
                              c. Carbon Monoxide..  400 ppm by volume on
                                                     a dry basis liquid
                                                     corrected to 3
                                                     percent oxygen (3-
                                                     run average).
6. New or reconstructed       a. Particulate        0.03 lb per MMBtu of
 small liquid fuel.            Matter.               heat input.
                              b. Hydrogen Chloride  0.0009 lb per MMBtu
                                                     of heat input.
7. New reconstructed large    Carbon Monoxide.....  400 ppm by volume on
 gaseous fuel.                                       a dry basis
                                                     corrected to 3
                                                     percent oxygen (30-
                                                     day rolling average
                                                     for units 100 MMBtu/
                                                     hr or greater, 3-
                                                     run average for
                                                     units less than 100
                                                     MMBtu/hr).
8. New or reconstructed       Carbon Monoxide.....  400 ppm by volume on
 limited use gaseous fuel.                           a dry basis
                                                     corrected to 3
                                                     percent oxygen (3-
                                                     run average).
9. Existing large solid fuel  a. Particulate        0.07 lb per MMBtu of
                               Matter (or Total      heat input; or
                               Selected Metals).     (0.001 lb per MMBtu
                                                     of heat input).
                              b. Hydrogen Chloride  0.09 lb per MMBtu of
                                                     heat input.
                              c. Mercury..........  0.000009 lb per
                                                     MMBtu of heat
                                                     input.
10. Existing limited use      Particulate Matter    0.21 lb per MMBtu of
 solid fuel.                   (or Total Selected    heat input; or
                               Metals).              (0.004 lb per MMBtu
                                                     of heat input).
------------------------------------------------------------------------


 Table 2 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
         Process Heaters With Particulate Matter Emission Limits
    As stated in Sec.   63.7500, you must comply with the applicable
                            operating limits:
------------------------------------------------------------------------
 If you demonstrate compliance with
   applicable particulate matter        You must meet these operating
    emission limits using . . .                  limits . . .
------------------------------------------------------------------------
1. Wet scrubber control............  a. Maintain the minimum pressure
                                      drop and liquid flow-rate at or
                                      above the operating levels
                                      established during the performance
                                      test according to Sec.
                                      63.7530(c) and Table 7 to this
                                      subpart that demonstrated
                                      compliance with the applicable
                                      emission limit for particulate
                                      matter.
2. Fabric filter control...........  a. Install and operate a bag leak
                                      detection system according to Sec.
                                        63.7525 and operate the fabric
                                      filter such that the bag leak
                                      detection system alarm does not
                                      sound more than 5 percent of the
                                      operating time during each 6-month
                                      period; or
                                     b. This option is for boilers and
                                      process heaters that operate dry
                                      control systems. Existing boilers
                                      and process heaters must maintain
                                      opacity to less than or equal to
                                      20 percent (6-minute average)
                                      except for one 6-minute period per
                                      hour of not more than 27 percent.
                                      New boilers and process heaters
                                      must maintain opacity to less than
                                      or equal to 10 percent opacity (1-
                                      hour block average).
3. Electrostatic precipitator        a. This option is for boilers and
 control.                             process heaters that operate dry
                                      control systems. Existing boilers
                                      and process heaters must maintain
                                      opacity to less than or equal to
                                      20 percent (6-minute average)
                                      except for one 6-minute period per
                                      hour of not more than 27 percent.
                                      New boilers and process heaters
                                      must maintain opacity to less than
                                      or equal to 10 percent opacity (1-
                                      hour block average); or

[[Page 55271]]

 
                                     b. This option is only for boilers
                                      and process heaters that operate
                                      additional wet control systems.
                                      Maintain the minimum voltage and
                                      secondary current or total power
                                      input of the electrostatic
                                      precipitator at or above the
                                      operating limits established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limit for
                                      particulate matter.
4. Any other control type..........  This option is for boilers and
                                      process heaters that operate dry
                                      control systems. Existing boilers
                                      and process heaters must maintain
                                      opacity to less than or equal to
                                      20 percent (6-minute average)
                                      except for one 6-minute period per
                                      hour of not more than 27 percent.
                                      New boilers and process heaters
                                      must maintain opacity to less than
                                      or equal to 10 percent opacity (1-
                                      hour block average).
------------------------------------------------------------------------


 Table 3 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
  Process Heaters With Mercury Emission Limits and Boilers and Process
Heaters That Choose To Comply With the Alternative Total Selected Metals
                             Emission Limits
    As stated in Sec.   63.7500, you must comply with the applicable
                            operating limits:
------------------------------------------------------------------------
 If you demonstrate compliance with
  applicable mercury and/or total       You must meet these operating
  selected metals emission limits                limits . . .
            using . . .
------------------------------------------------------------------------
1. Wet scrubber control............  Maintain the minimum pressure drop
                                      and liquid flow-rate at or above
                                      the operating levels established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limits for
                                      mercury and/or total selected
                                      metals.
2. Fabric filter control...........  a. Install and operate a bag leak
                                      detection system according to Sec.
                                        63.7525 and operate the fabric
                                      filter such that the bag leak
                                      detection system alarm does not
                                      sound more than 5 percent of the
                                      operating time during a 6-month
                                      period; or
                                     b. This option is for boilers and
                                      process heaters that operate dry
                                      control systems. Existing sources
                                      must maintain opacity to less than
                                      or equal to 20 percent (6-minute
                                      average) except for one 6-minute
                                      period per hour of not more than
                                      27 percent. New sources must
                                      maintain opacity to less than or
                                      equal to 10 percent opacity (1-
                                      hour block average).
3. Electrostatic precipitator        a. This option is for boilers and
 control.                             process heaters that operate dry
                                      control systems. Existing sources
                                      must maintain opacity to less than
                                      or equal to 20 percent (6-minute
                                      average) except for one 6-minute
                                      period per hour of not more than
                                      27 percent. New sources must
                                      maintain opacity to less than or
                                      equal to 10 percent opacity (1-
                                      hour block average); or
                                     b. This option is only for boilers
                                      and process heaters that operate
                                      additional wet control systems.
                                      Maintain the minimum voltage and
                                      secondary current or total power
                                      input of the electrostatic
                                      precipitator at or above the
                                      operating limits established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limits for
                                      mercury and/or total selected
                                      metals.
4. Dry scrubber or carbon injection  Maintain the minimum sorbent or
 control.                             carbon injection rate at or above
                                      the operating levels established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limit for
                                      mercury.
5. Any other control type..........  This option is only for boilers and
                                      process heaters that operate dry
                                      control systems. Existing sources
                                      must maintain opacity to less than
                                      or equal to 20 percent (6-minute
                                      average) except for one 6-minute
                                      period per hour of not more than
                                      27 percent. New sources must
                                      maintain opacity to less than or
                                      equal to 10 percent opacity (1-
                                      hour block average).
6. Fuel analysis...................  Maintain the fuel type or fuel
                                      mixture such that the mercury and/
                                      or total selected metals emission
                                      rates calculated according to Sec.
                                        63.7530(d)(4) and/or (5) is less
                                      than the applicable emission
                                      limits for mercury and/or total
                                      selected metals.
------------------------------------------------------------------------


[[Page 55272]]


 Table 4 to Subpart DDDDD of Part 63.--Operating Limits for Boilers and
         Process Heaters With Hydrogen Chloride Emission Limits
     As stated in Sec.   63.7500, you must comply with the following
                      applicable operating limits:
------------------------------------------------------------------------
 If you demonstrate compliance with
    applicable hydrogen chloride        You must meet these operating
    emission limits using . . .                  limits . . .
------------------------------------------------------------------------
1. Wet scrubber control............  Maintain the minimum scrubber
                                      effluent pH, pressure drop, and
                                      liquid flow-rate at or above the
                                      operating levels established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limit for
                                      hydrogen chloride.
2. Dry scrubber control............  Maintain the minimum sorbent
                                      injection rate at or above the
                                      operating levels established
                                      during the performance test
                                      according to Sec.   63.7530(c) and
                                      Table 7 to this subpart that
                                      demonstrated compliance with the
                                      applicable emission limit for
                                      hydrogen chloride.
3. Fuel analysis...................  Maintain the fuel type or fuel
                                      mixture such that the hydrogen
                                      chloride emission rate calculated
                                      according to Sec.   63.7530(d)(3)
                                      is less than the applicable
                                      emission limit for hydrogen
                                      chloride.
------------------------------------------------------------------------


 Table 5 to Subpart DDDDD of Part 63.--Performance Testing Requirements
     As stated in Sec.   63.7520, you must comply with the following
  requirements for performance test for existing, new or reconstructed
                            affected sources:
------------------------------------------------------------------------
  To conduct a performance
   test for the following        You must . . .          Using . . .
       pollutant . . .
------------------------------------------------------------------------
1. Particulate Matter.......  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASME PTC 19,
                                                     Part 10 (1981)
                                                     (IBR, see Sec.
                                                     63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 5 or 17
                               particulate matter    (positive pressure
                               emission              fabric filters must
                               concentration.        use Method 5D) in
                                                     appendix A to part
                                                     60 of this chapter.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb   methodology in
                               per MMBtu emission    appendix A to part
                               rates.                60 of this chapter.
2. Total selected metals....  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASME PTC 19,
                                                     Part 10 (1981)
                                                     (IBR, see Sec.
                                                     63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the total  Method 29 in
                               selected metals       appendix A to part
                               emission              60 of this chapter.
                               concentration.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb   methodology in
                               per MMBtu emission    appendix A to part
                               rates.                60 of this chapter.
3. Hydrogen chloride........  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASME PTC 19,
                                                     Part 10 (1981)
                                                     (IBR, see Sec.
                                                     63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 26 or 26A in
                               hydrogen chloride     appendix A to part
                               emission              60 of this chapter.
                               concentration.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb   methodology in
                               per MMBtu emission    appendix A to part
                               rates.                60 of this chapter.
4. Mercury..................  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASME PTC 19,
                                                     Part 10 (1981)
                                                     (IBR, see Sec.
                                                     62.14(i)).

[[Page 55273]]

 
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 29 in
                               mercury emission      appendix A to part
                               concentration.        60 of this chapter
                                                     or Method 101A in
                                                     appendix B to part
                                                     61 of this chapter
                                                     or ASTM Method
                                                     D6784-02 (IBR, see
                                                     Sec.   63.14(b)).
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb   methodology in
                               per MMBtu emission    appendix A to part
                               rates.                60 of this chapter.
5. Carbon Monoxide..........  a. Select the         Method 1 in appendix
                               sampling ports        A to part 60 of
                               location and the      this chapter.
                               number of traverse
                               points.
                              b. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASTM D6522-00
                                                     (IBR, see Sec.
                                                     63.14(b)), or ASME
                                                     PTC 19, Part 10
                                                     (1981) (IBR, see
                                                     Sec.   63.14(i)).
                              c. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              d. Measure the        Method 10, 10A, or
                               carbon monoxide       10B in appendix A
                               emission              to part 60 of this
                               concentration.        chapter, or ASTM
                                                     D6522-00 (IBR, see
                                                     Sec.   63.14(b))
                                                     when the fuel is
                                                     natural gas.
------------------------------------------------------------------------


    Table 6 to Subpart DDDDD of Part 63.--Fuel Analysis Requirements
     As stated in Sec.   63.7521, you must comply with the following
       requirements for fuel analysis testing for existing, new or
                     reconstructed affected sources:
------------------------------------------------------------------------
 To conduct a fuel analysis
for the following  pollutant     You must . . .          Using . . .
            . . .
------------------------------------------------------------------------
1. Mercury..................  a. Collect fuel       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234-00 \1\ (for
                                                     coal)(IBR, see Sec.
                                                       63.14(b)) or ASTM
                                                     D6323-98 (2003)(for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            SW-846-3050B (for
                               composited fuel       solid samples) or
                               samples.              SW-846-3020A (for
                                                     liquid samples) or
                                                     ASTM D2013-01 (for
                                                     coal) (IBR, see
                                                     Sec.   63.14(b)) or
                                                     ASTM D5198-92
                                                     (2003) (for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              d. Determine heat     ASTM D5865-03a (for
                               content of the fuel   coal)(IBR, see Sec.
                               type.                   63.14(b)) or ASTM
                                                     E711-87 (1996) (for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              e. Determine          ASTM D3173-02 (IBR,
                               moisture content of   see Sec.
                               the fuel type.        63.14(b)) or ASTM
                                                     E871-82 (1998)(IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              f. Measure mercury    ASTM D3684-01 (for
                               concentration in      coal)(IBR, see Sec.
                               fuel sample.            63.14(b)) or SW-
                                                     846-7471A (for
                                                     solid samples) or
                                                     SW-846 7470A (for
                                                     liquid samples).
                              g. Convert
                               concentrations into
                               units of pounds of
                               pollutant per MMBtu
                               of heat content.
2. Total selected metals....  a. Collect fuel       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234-00 \1\ (for
                                                     coal)(IBR, see Sec.
                                                       63.14(b)) or ASTM
                                                     D6323-98 (2003)
                                                     (for biomass)(IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            SW-846-3050B (for
                               composited fuel       solid samples) or
                               samples.              SW-846-3020A (for
                                                     liquid samples) or
                                                     ASTM D2013-01 (for
                                                     coal)(IBR, see Sec.
                                                       63.14(b)) or ASTM
                                                     D5198-92 (2003)(for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              d. Determine heat     ASTM D5865-03a (for
                               content of the fuel   coal)(IBR, see Sec.
                               type.                   63.14(b)) or ASTM
                                                     E 711-87 (for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              e. Determine          ASTM D3173-02 (IBR,
                               moisture content of   see Sec.
                               the fuel type.        63.14(b)) or ASTM
                                                     E871 (IBR, see Sec.
                                                       63.14(b)) or
                                                     equivalent.

[[Page 55274]]

 
                              f. Measure total      SW-846-6010B or ASTM
                               selected metals       D3683-94 (2000)
                               concentration in      (for coal) (IBR,
                               fuel sample.          see Sec.
                                                     63.14(b)) or ASTM
                                                     E885-88 (1996) (for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)).
                              g. Convert
                               concentrations into
                               units of pounds of
                               pollutant per MMBtu
                               of heat content.
3. Hydrogen chloride........  a. Collect fuel       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234 \1\ (for
                                                     coal)(IBR, see Sec.
                                                       63.14(b)) or ASTM
                                                     D6323-98 (2003)
                                                     (for biomass)(IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            SW-846-3050B (for
                               composited fuel       solid samples) or
                               samples.              SW-846-3020A (for
                                                     liquid samples) or
                                                     ASTM D2013-01 (for
                                                     coal)(IBR, see Sec.
                                                       63.14(b)) or ASTM
                                                     D5198-92 (2003)
                                                     (for biomass)(IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              d. Determine heat     ASTM D5865-03a (for
                               content of the fuel   coal)(IBR, see Sec.
                               type.                   63.14(b)) or ASTM
                                                     E711-87 (1996) (for
                                                     biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              e. Determine          ASTM D3173-02 (IBR,
                               moisture content of   see Sec.
                               the fuel type.        63.14(b)) or ASTM
                                                     E871-82 (1998)(IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              f. Measure chlorine   SW-846-9250 or ASTM
                               concentration in      E776-87 (1996) (for
                               fuel sample.          biomass)(IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              g. Convert
                               concentrations into
                               units of pounds of
                               pollutant per MMBtu
                               of heat content.
------------------------------------------------------------------------


                                           Table 7 to Subpart DDDDD of Part 63.--Establishing Operating Limits
                     As stated in Sec.   63.7520, you must comply with the following requirements for establishing operating limits:
--------------------------------------------------------------------------------------------------------------------------------------------------------
 If you have an applicable emission    And your operating limits                                                              According to the following
           limit for . . .                 are based on . . .             You must . . .                Using . . .                  requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Particulate matter, mercury, or    a. Wet scrubber operating    i. Establish a site-         (1) Data from the pressure   (a) You must collect
 total selected metals.                parameters.                  specific minimum pressure    drop and liquid flow rate    pressure drop and liquid
                                                                    drop and minimum flow rate   monitors and the             flow-rate data every 15
                                                                    operating limit according    particulate matter,          minutes during the entire
                                                                    to Sec.   63.7530(c).        mercury, or total selected   period of the performance
                                                                                                 metals performance test.     tests;
                                                                                                                             (b) Determine the average
                                                                                                                              pressure drop and liquid
                                                                                                                              flow-rate for each
                                                                                                                              individual test run in the
                                                                                                                              three-run performance test
                                                                                                                              by computing the average
                                                                                                                              of all the 15-minute
                                                                                                                              readings taken during each
                                                                                                                              test run.
                                      b. Electrostatic             i. Establish a site-         (1) Data from the pressure   (a) You must collect
                                       precipitator operating       specific minimum voltage     drop and liquid flow rate    voltage and secondary
                                       parameters (option only      and secondary current or     monitors and the             current or total power
                                       for units with additional    total power input            particulate matter,          input data every 15
                                       wet scrubber control).       according to Sec.            mercury, or total selected   minutes during the entire
                                                                    63.7530(c).                  metals performance test.     period of the performance
                                                                                                                              tests;
                                                                                                                             (b) Determine the average
                                                                                                                              voltage and secondary
                                                                                                                              current or total power
                                                                                                                              input for each individual
                                                                                                                              test run in the three-run
                                                                                                                              performance test by
                                                                                                                              computing the average of
                                                                                                                              all the 15-minute readings
                                                                                                                              taken during each test
                                                                                                                              run.

[[Page 55275]]

 
2. Hydrogen Chloride................  a. Wet scrubber operating    i. Establish a site-         (1) Data from the pH,        (a) You must collect pH,
                                       parameters.                  specific minimum pressure    pressure drop, and liquid    pressure drop, and liquid
                                                                    drop and minimum flow rate   flow-rate monitors and the   flow-rate data every 15
                                                                    operating limit according    hydrogen chloride            minutes during the entire
                                                                    to Sec.   63.7530(c).        performance test.            period of the performance
                                                                                                                              tests;
                                                                                                                             (b) Determine the average
                                                                                                                              pH, pressure drop, and
                                                                                                                              liquid flow-rate for each
                                                                                                                              individual test run in the
                                                                                                                              three-run performance test
                                                                                                                              by computing the average
                                                                                                                              of all the 15-minute
                                                                                                                              readings taken during each
                                                                                                                              test run.
                                      b. Dry scrubber operating    i. Establish a site-         (1) Data from the sorbent    (a) You must collect
                                       parameters.                  specific minimum sorbent     injection rate monitors      sorbent injection rate
                                                                    injection rate operating     and hydrogen chloride        data every 15 minutes
                                                                    limit according to Sec.      performance test.            during the entire period
                                                                    63.7530(c).                                               of the performance tests;
                                                                                                                             (b) Determine the average
                                                                                                                              sorbent injection rate for
                                                                                                                              each individual test run
                                                                                                                              in the three-run
                                                                                                                              performance test by
                                                                                                                              computing the average of
                                                                                                                              all the 15-minute readings
                                                                                                                              taken during each test
                                                                                                                              run.
--------------------------------------------------------------------------------------------------------------------------------------------------------


     Table 8 to Subpart DDDDD of Part 63.--Demonstrating Continuous
                               Compliance
  As stated in Sec.   63.7540, you must show continuous compliance with
     the emission limitations for affected sources according to the
                               following:
------------------------------------------------------------------------
   If you must meet the following
 operating limits or work practice     You must demonstrate continuous
          standards . . .                    compliance by . . .
------------------------------------------------------------------------
1. Opacity.........................  a. Collecting the opacity
                                      monitoring system data according
                                      to Sec.  Sec.   63.7525(b) and
                                      63.7535; and
                                     b. Reducing the opacity monitoring
                                      data to 6-minute averages; and
                                     c. Maintaining opacity to less than
                                      or equal to 20 percent (6-minute
                                      average) except for one 6-minute
                                      period per hour of not more than
                                      27 percent for existing sources;
                                      or maintaining opacity to less
                                      than or equal to 10 percent (1-
                                      hour block average) for new
                                      sources.
2. Fabric Filter Bag Leak Detection  Installing and operating a bag leak
 Operation.                           detection system according to Sec.
                                        63.7525 and operating the fabric
                                      filter such that the requirements
                                      in Sec.   63.7540(a)(9) are met.
3. Wet Scrubber Pressure Drop and    a. Collecting the pressure drop and
 Liquid Flow-rate.                    liquid flow rate monitoring system
                                      data according to Sec.  Sec.
                                      63.7525 and 63.7535; and
                                     b. Reducing the data to 3-hour
                                      block averages; and
                                     c. Maintaining the 3-hour average
                                      pressure drop and liquid flow-rate
                                      at or above the operating limits
                                      established during the performance
                                      test according to Sec.
                                      63.7530(c).
4. Wet Scrubber pH.................  a. Collecting the pH monitoring
                                      system data according to Sec.
                                      Sec.   63.7525 and 63.7535; and
                                     b. Reducing the data to 3-hour
                                      block averages; and
                                     c. Maintaining the 3-hour average
                                      pH at or above the operating limit
                                      established during the performance
                                      test according to Sec.
                                      63.7530(c).
5. Dry Scrubber Sorbent or Carbon    a. Collecting the sorbent or carbon
 Injection Rate.                      injection rate monitoring system
                                      data for the dry scrubber
                                      according to Sec.  Sec.   63.7525
                                      and 63.7535; and
                                     b. Reducing the data to 3-hour
                                      block averages; and
                                     c. Maintaining the 3-hour average
                                      sorbent or carbon injection rate
                                      at or above the operating limit
                                      established during the performance
                                      test according to Sec.  Sec.
                                      63.7530(c).
6. Electrostatic Precipitator        a. Collecting the secondary current
 Secondary Current and Voltage or     and voltage or total power input
 Total Power Input.                   monitoring system data for the
                                      electrostatic precipitator
                                      according to Sec.  Sec.   63.7525
                                      and 63.7535; and
                                     b. Reducing the data to 3-hour
                                      block averages; and

[[Page 55276]]

 
                                     c. Maintaining the 3-hour average
                                      secondary current and voltage or
                                      total power input at or above the
                                      operating limits established
                                      during the performance test
                                      according to Sec.  Sec.
                                      63.7530(c).
7. Fuel Pollutant Content..........  a. Only burning the fuel types and
                                      fuel mixtures used to demonstrate
                                      compliance with the applicable
                                      emission limit according to Sec.
                                      63.7530(c) or (d) as applicable;
                                      and
                                     b. Keeping monthly records of fuel
                                      use according to Sec.
                                      63.7540(a).
------------------------------------------------------------------------


      Table 9 to Subpart DDDDD of Part 63.--Reporting Requirements
     As stated in Sec.   63.7550, you must comply with the following
                        requirements for reports:
------------------------------------------------------------------------
                                 The report must     You must submit the
    You must submit a(n)          contain . . .         report . . .
------------------------------------------------------------------------
1. Compliance report........  a. Information        Semiannually
                               required in Sec.      according to the
                               63.7550(c)(1)         requirements in
                               through (11); and     Sec.   63.7550(b).
                              b. If there are no
                               deviations from any
                               emission limitation
                               (emission limit and
                               operating limit)
                               that applies to you
                               and there are no
                               deviations from the
                               requirements for
                               work practice
                               standards in Table
                               8 to this subpart
                               that apply to you,
                               a statement that
                               there were no
                               deviations from the
                               emission
                               limitations and
                               work practice
                               standards during
                               the reporting
                               period. If there
                               were no periods
                               during which the
                               CMSs, including
                               continuous
                               emissions
                               monitoring system,
                               continuous opacity
                               monitoring system,
                               and operating
                               parameter
                               monitoring systems,
                               were out-of-control
                               as specified in
                               Sec.   63.8(c)(7),
                               a statement that
                               there were no
                               periods during
                               which the CMSs were
                               out-of-control
                               during the
                               reporting period;
                               and
                              c. If you have a
                               deviation from any
                               emission limitation
                               (emission limit and
                               operating limit) or
                               work practice
                               standard during the
                               reporting period,
                               the report must
                               contain the
                               information in Sec.
                                 63.7550(d). If
                               there were periods
                               during which the
                               CMSs, including
                               continuous
                               emissions
                               monitoring system,
                               continuous opacity
                               monitoring system,
                               and operating
                               parameter
                               monitoring systems,
                               were out-of-
                               control, as
                               specified in Sec.
                               63.8(c)(7), the
                               report must contain
                               the information in
                               Sec.   63.7550(e);
                               and
                              d. If you had a
                               startup, shutdown,
                               or malfunction
                               during the
                               reporting period
                               and you took
                               actions consistent
                               with your startup,
                               shutdown, and
                               malfunction plan,
                               the compliance
                               report must include
                               the information in
                               Sec.
                               63.10(d)(5)(i)
2. An immediate startup,      a. Actions taken for  i. By fax or
 shutdown, and malfunction     the event; and        telephone within 2
 report if you had a                                 working days after
 startup, shutdown, or                               starting actions
 malfunction during the                              inconsistent with
 reporting period that is                            the plan; and
 not consistent with your
 startup, shutdown, and
 malfunction plan, and the
 source exceeds any
 applicable emission
 limitation in the relevant
 emission standard.
                              b. The information    ii. By letter within
                               in Sec.               7 working days
                               63.10(d)(5)(ii)       after the end of
                                                     the event unless
                                                     you have made
                                                     alternative
                                                     arrangements with
                                                     the permitting
                                                     authority.
------------------------------------------------------------------------


[[Page 55277]]


           Table 10 to Subpart DDDDD of Part 63.--Applicability of General Provisions to Subpart DDDDD
 As stated in Sec.   63.7565, you must comply with the applicable General Provisions according to the following:
----------------------------------------------------------------------------------------------------------------
              Citation                         Subject                Brief description           Applicable
----------------------------------------------------------------------------------------------------------------
Sec.   63.1........................  Applicability.............  Initial Applicability       Yes.
                                                                  Determination;
                                                                  Applicability After
                                                                  Standard Established;
                                                                  Permit Requirements;
                                                                  Extensions, Notifications.
Sec.   63.2........................  Definitions...............  Definitions for part 63     Yes.
                                                                  standards.
Sec.   63.3........................  Units and Abbreviations...  Units and abbreviations     Yes.
                                                                  for part 63 standards.
Sec.   63.4........................  Prohibited Activities.....  Prohibited Activities;      Yes.
                                                                  Compliance date;
                                                                  Circumvention,
                                                                  Severability.
Sec.   63.5........................  Construction/               Applicability;              Yes.
                                      Reconstruction.             applications; approvals.
Sec.   63.6(a).....................  Applicability.............  GP apply unless compliance  Yes.
                                                                  extension; and GP apply
                                                                  to area sources that
                                                                  become major.
Sec.   63.6(b)(1)-(4)..............  Compliance Dates for New    Standards apply at          Yes.
                                      and Reconstructed sources.  effective date; 3 years
                                                                  after effective date;
                                                                  upon startup; 10 years
                                                                  after construction or
                                                                  reconstruction commences
                                                                  for 112(f).
Sec.   63.6(b)(5)..................  Notification..............  Must notify if commenced    Yes.
                                                                  construction or
                                                                  reconstruction after
                                                                  proposal.
Sec.   63.6(b)(6)..................  [Reserved].
Sec.   63.6(b)(7)..................  Compliance Dates for New    Area sources that become    Yes.
                                      and Reconstructed Area      major must comply with
                                      Sources That Become Major.  major source standards
                                                                  immediately upon becoming
                                                                  major, regardless of
                                                                  whether required to
                                                                  comply when they were an
                                                                  area source.
Sec.   63.6(c)(1)-(2)..............  Compliance Dates for        Comply according to date    Yes.
                                      Existing Sources.           in subpart, which must be
                                                                  no later than 3 years
                                                                  after effective date; and
                                                                  for 112(f) standards,
                                                                  comply within 90 days of
                                                                  effective date unless
                                                                  compliance extension.
Sec.   63.6(c)(3)-(4)..............  [Reserved].
Sec.   63.6(c)(5)..................  Compliance Dates for        Area sources that become    Yes.
                                      Existing Area Sources       major must comply with
                                      That Become Major.          major source standards by
                                                                  date indicated in subpart
                                                                  or by equivalent time
                                                                  period (for example, 3
                                                                  years).
Sec.   63.6(d).....................  [Reserved].
Sec.   63.6(e)(1)-(2)..............  Operation & Maintenance...  Operate to minimize         Yes.
                                                                  emissions at all times;
                                                                  and Correct malfunctions
                                                                  as soon as practicable;
                                                                  and Operation and
                                                                  maintenance requirements
                                                                  independently
                                                                  enforceable; information
                                                                  Administrator will use to
                                                                  determine if operation
                                                                  and maintenance
                                                                  requirements were met.
Sec.   63.6(e)(3)..................  Startup, Shutdown, and      Requirement for SSM and     Yes.
                                      Malfunction Plan (SSMP).    startup, shutdown,
                                                                  malfunction plan; and
                                                                  content of SSMP.
Sec.   63.6(f)(1)..................  Compliance Except During    Comply with emission        Yes.
                                      SSM.                        standards at all times
                                                                  except during SSM.
Sec.   63.6(f)(2)-(3)..............  Methods for Determining     Compliance based on         Yes.
                                      Compliance.                 performance test,
                                                                  operation and maintenance
                                                                  plans, records,
                                                                  inspection.
Sec.   63.6(g)(1)-(3)..............  Alternative Standard......  Procedures for getting an   Yes.
                                                                  alternative standard.
Sec.   63.6(h)(1)..................  Compliance with Opacity/VE  Comply with opacity/VE      Yes.
                                      Standards.                  emission limitations at
                                                                  all times except during
                                                                  SSM.
Sec.   63.6(h)(2)(i)...............  Determining Compliance      If standard does not state  No.
                                      with Opacity/Visible        test method, use Method 9
                                      Emission (VE) Standards.    for opacity and Method 22
                                                                  for VE.
Sec.   63.6(h)(2)(ii)..............  [Reserved].
Sec.   63.6(h)(2)(iii).............  Using Previous Tests to     Criteria for when previous  Yes.
                                      Demonstrate Compliance      opacity/VE testing can be
                                      with Opacity/VE Standards   used to show compliance
                                                                  with this subpart.
Sec.   63.6(h)(3)..................  [Reserved].
Sec.   63.6(h)(4)..................  Notification of Opacity/VE  Notify Administrator of     No.
                                      Observation Date.           anticipated date of
                                                                  observation.
Sec.   63.6(h)(5)(i),(iii)-(v).....  Conducting Opacity/VE       Dates and Schedule for      No.
                                      Observations.               conducting opacity/VE
                                                                  observations.

[[Page 55278]]

 
Sec.   63.6(h)(5)(ii)..............  Opacity Test Duration and   Must have at least 3 hours  No.
                                      Averaging Times.            of observation with
                                                                  thirty, 6-minute averages.
Sec.   63.6(h)(6)..................  Records of Conditions       Keep records available and  No.
                                      During Opacity/VE           allow Administrator to
                                      observations.               inspect.
Sec.   63.6(h)(7)(i)...............  Report continuous opacity   Submit continuous opacity   Yes.
                                      monitoring system           monitoring system data
                                      Monitoring Data from        with other performance
                                      Performance Test.           test data.
Sec.   63.6(h)(7)(ii)..............  Using continuous opacity    Can submit continuous       No.
                                      monitoring system instead   opacity monitoring system
                                      of Method 9.                data instead of Method 9
                                                                  results even if subpart
                                                                  requires Method 9, but
                                                                  must notify Administrator
                                                                  before performance test.
Sec.   63.6(h)(7)(iii).............  Averaging time for          To determine compliance,    Yes.
                                      continuous opacity          must reduce continuous
                                      monitoring system during    opacity monitoring system
                                      performance test.           data to 6-minute averages.
Sec.   63.6(h)(7)(iv)..............  Continuous opacity          Demonstrate that            Yes.
                                      monitoring system           continuous opacity
                                      requirements.               monitoring system
                                                                  performance evaluations
                                                                  are conducted according
                                                                  to Sec.  Sec.   63.8(e),
                                                                  continuous opacity
                                                                  monitoring systems are
                                                                  properly maintained and
                                                                  operated according to
                                                                  Sec.   63.8(c) and data
                                                                  quality as Sec.   63.8(d).
Sec.   63.6(h)(7)(v)...............  Determining Compliance      Continuous opacity          Yes.
                                      with Opacity/VE Standards.  monitoring system is
                                                                  probative but not
                                                                  conclusive evidence of
                                                                  compliance with opacity
                                                                  standard, even if Method
                                                                  9 observation shows
                                                                  otherwise. Requirements
                                                                  for continuous opacity
                                                                  monitoring system to be
                                                                  probative evidence-proper
                                                                  maintenance, meeting PS
                                                                  1, and data have not been
                                                                  altered.
Sec.   63.6(h)(8)..................  Determining Compliance      Administrator will use all  Yes.
                                      with Opacity/VE Standards.  continuous opacity
                                                                  monitoring system, Method
                                                                  9, and Method 22 results,
                                                                  as well as information
                                                                  about operation and
                                                                  maintenance to determine
                                                                  compliance.
Sec.   63.6(h)(9)..................  Adjusted Opacity Standard.  Procedures for              Yes.
                                                                  Administrator to adjust
                                                                  an opacity standard.
Sec.   63.6(i)(1)-(14).............  Compliance Extension......  Procedures and criteria     Yes.
                                                                  for Administrator to
                                                                  grant compliance
                                                                  extension.
Sec.   63.6(j).....................  Presidential Compliance     President may exempt        Yes.
                                      Exemption.                  source category from
                                                                  requirement to comply
                                                                  with rule.
Sec.   63.7(a)(1)..................  Performance Test Dates....  Dates for Conducting        Yes.
                                                                  Initial Performance
                                                                  Testing and Other
                                                                  Compliance Demonstrations.
Sec.   63.7(a)(2)..................  Performance Test Dates....  New source with initial     Yes.
                                                                  startup date before
                                                                  effective date has 180
                                                                  days after effective date
                                                                  to demonstrate compliance
Sec.   63.7(a)(2)(ii-viii).........  [Reserved].
Sec.   63.7(a)(2)(ix)..............  Performance Test Dates....  1. New source that          Yes.
                                                                  commenced construction
                                                                  between proposal and
                                                                  promulgation dates, when
                                                                  promulgated standard is
                                                                  more stringent than
                                                                  proposed standard, has
                                                                  180 days after effective
                                                                  date or 180 days after
                                                                  startup of source,
                                                                  whichever is later, to
                                                                  demonstrate compliance;
                                                                  and.
                                                                 2. If source initially      No.
                                                                  demonstrates compliance
                                                                  with less stringent
                                                                  proposed standard, it has
                                                                  3 years and 180 days
                                                                  after the effective date
                                                                  of the standard or 180
                                                                  days after startup of
                                                                  source, whichever is
                                                                  later, to demonstrate
                                                                  compliance with
                                                                  promulgated standard.
Sec.   63.7(a)(3)..................  Section 114 Authority.....  Administrator may require   Yes.
                                                                  a performance test under
                                                                  CAA Section 114 at any
                                                                  time.

[[Page 55279]]

 
Sec.   63.7(b)(1)..................  Notification of             Must notify Administrator   No.
                                      Performance Test.           60 days before the test.
Sec.   63.7(b)(2)..................  Notification of             If rescheduling a           Yes.
                                      Rescheduling.               performance test is
                                                                  necessary, must notify
                                                                  Administrator 5 days
                                                                  before scheduled date of
                                                                  rescheduled date.
Sec.   63.7(c).....................  Quality Assurance/Test      Requirement to submit site- Yes.
                                      Plan.                       specific test plan 60
                                                                  days before the test or
                                                                  on date Administrator
                                                                  agrees with: test plan
                                                                  approval procedures; and
                                                                  performance audit
                                                                  requirements; and
                                                                  internal and external QA
                                                                  procedures for testing.
Sec.   63.7(d).....................  Testing Facilities........  Requirements for testing    Yes.
                                                                  facilities.
Sec.   63.7(e)(1)..................  Conditions for Conducting   1. Performance tests must   No.
                                      Performance Tests.          be conducted under
                                                                  representative
                                                                  conditions; and
                                                                 2. Cannot conduct           Yes.
                                                                  performance tests during
                                                                  SSM; and
                                                                 3. Not a deviation to       Yes.
                                                                  exceed standard during
                                                                  SSM; and
                                                                 4. Upon request of          Yes.
                                                                  Administrator, make
                                                                  available records
                                                                  necessary to determine
                                                                  conditions of performance
                                                                  tests.
Sec.   63.7(e)(2)..................  Conditions for Conducting   Must conduct according to   Yes.
                                      Performance Tests.          rule and EPA test methods
                                                                  unless Administrator
                                                                  approves alternative.
Sec.   63.7(e)(3)..................  Test Run Duration.........  Must have three separate    Yes.
                                                                  test runs; and Compliance
                                                                  is based on arithmetic
                                                                  mean of three runs; and
                                                                  conditions when data from
                                                                  an additional test run
                                                                  can be used.
Sec.   63.7(e)(4)..................  Interaction with other      Nothing in Sec.             Yes.
                                      sections of the Act.        63.7(e)(1) through (4)
                                                                  can abrogate the
                                                                  Administrator's authority
                                                                  to require testing under
                                                                  Section 114 of the Act.
Sec.   63.7(f).....................  Alternative Test Method...  Procedures by which         Yes.
                                                                  Administrator can grant
                                                                  approval to use an
                                                                  alternative test method.
Sec.   63.7(g).....................  Performance Test Data       Must include raw data in    Yes.
                                      Analysis.                   performance test report;
                                                                  and must submit
                                                                  performance test data 60
                                                                  days after end of test
                                                                  with the Notification of
                                                                  Compliance Status; and
                                                                  keep data for 5 years.
Sec.   63.7(h).....................  Waiver of Tests...........  Procedures for              Yes.
                                                                  Administrator to waive
                                                                  performance test.
Sec.   63.8(a)(1)..................  Applicability of            Subject to all monitoring   Yes.
                                      Monitoring Requirements.    requirements in standard.
Sec.   63.8(a)(2)..................  Performance Specifications  Performance Specifications  Yes.
                                                                  in appendix B of part 60
                                                                  apply.
Sec.   63.8(a)(3)..................  [Reserved].
Sec.   63.8(a)(4)..................  Monitoring with Flares....  Unless your rule says       No.
                                                                  otherwise, the
                                                                  requirements for flares
                                                                  in Sec.   63.11 apply.
Sec.  63.8(b)(1)(i)-(ii)...........  Monitoring................  Must conduct monitoring     Yes.
                                                                  according to standard
                                                                  unless Administrator
                                                                  approves alternative.
Sec.   63.8(b)(1)(iii).............  Monitoring................  Flares not subject to this  No.
                                                                  section unless otherwise
                                                                  specified in relevant
                                                                  standard.
Sec.   63.8(b)(2)-(3)..............  Multiple Effluents and      Specific requirements for   Yes.
                                      Multiple Monitoring         installing monitoring
                                      Systems.                    systems; and must install
                                                                  on each effluent before
                                                                  it is combined and before
                                                                  it is released to the
                                                                  atmosphere unless
                                                                  Administrator approves
                                                                  otherwise; and if more
                                                                  than one monitoring
                                                                  system on an emission
                                                                  point, must report all
                                                                  monitoring system
                                                                  results, unless one
                                                                  monitoring system is a
                                                                  backup.
Sec.   63.8(c)(1)..................  Monitoring System           Maintain monitoring system  Yes.
                                      Operation and Maintenance.  in a manner consistent
                                                                  with good air pollution
                                                                  control practices.

[[Page 55280]]

 
Sec.   63.8(c)(1)(i)...............  Routine and Predictable     Maintain and operate CMS    Yes.
                                      SSM.                        according to Sec.
                                                                  63.6(e)(1).
Sec.   63.8(c)(1)(ii)..............  SSM not in SSMP...........  Must keep necessary parts   Yes.
                                                                  available for routine
                                                                  repairs of CMSs.
Sec.   63.8(c)(1)(iii).............  Compliance with Operation   Must develop and implement  Yes.
                                      and Maintenance             an SSMP for CMSs.
                                      Requirements.
Sec.   63.8(c)(2)-(3)..............  Monitoring System           Must install to get         Yes.
                                      Installation.               representative emission
                                                                  and parameter
                                                                  measurements; and must
                                                                  verify operational status
                                                                  before or at performance
                                                                  test.
Sec.   63.8(c)(4)..................  Continuous Monitoring       CMSs must be operating      No.
                                      System (CMS) Requirements.  except during breakdown,
                                                                  out-of-control, repair,
                                                                  maintenance, and high-
                                                                  level calibration drifts.
Sec.   63.8(c)(4)(i)...............  Continuous Monitoring       Continuous opacity          Yes.
                                      System (CMS) Requirements.  monitoring system must
                                                                  have a minimum of one
                                                                  cycle of sampling and
                                                                  analysis for each
                                                                  successive 10-second
                                                                  period and one cycle of
                                                                  data recording for each
                                                                  successive 6-minute
                                                                  period.
Sec.   63.8(c)(4)(ii)..............  Continuous Monitoring       Continuous emissions        No.
                                      System (CMS) Requirements.  monitoring system must
                                                                  have a minimum of one
                                                                  cycle of operation for
                                                                  each successive 15-minute
                                                                  period.
Sec.   63.8(c)(5)..................  Continuous Opacity          Must do daily zero and      Yes.
                                      Monitoring system (COMS)    high level calibrations.
                                      Requirements.
Sec.   63.8(c)(6)..................  Continuous Monitoring       Must do daily zero and      No.
                                      System (CMS) Requirements.  high level calibrations.
Sec.   63.8(c)(7)-(8)..............  Continuous Monitoring       Out-of-control periods,     Yes.
                                      Systems Requirements.       including reporting.
Sec.   63.8(d).....................  Continuous Monitoring       Requirements for            Yes.
                                      Systems Quality Control.    continuous monitoring
                                                                  systems quality control,
                                                                  including calibration,
                                                                  etc.; and must keep
                                                                  quality control plan on
                                                                  record for the life of
                                                                  the affected source. Keep
                                                                  old versions for 5 years
                                                                  after revisions.
Sec.   63.8(e).....................  Continuous monitoring       Notification, performance   Yes.
                                      systems Performance         evaluation test plan,
                                      Evaluation.                 reports.
Sec.   63.8(f)(1)-(5)..............  Alternative Monitoring      Procedures for              Yes.
                                      Method.                     Administrator to approve
                                                                  alternative monitoring.
Sec.   63.8(f)(6)..................  Alternative to Relative     Procedures for              No.
                                      Accuracy Test.              Administrator to approve
                                                                  alternative relative
                                                                  accuracy tests for
                                                                  continuous emissions
                                                                  monitoring system.
Sec.   63.8(g)(1)-(4)..............  Data Reduction............  Continuous opacity          Yes.
                                                                  monitoring system 6-
                                                                  minute averages
                                                                  calculated over at least
                                                                  36 evenly spaced data
                                                                  points; and continuous
                                                                  emissions monitoring
                                                                  system 1-hour averages
                                                                  computed over at least 4
                                                                  equally spaced data
                                                                  points.
Sec.   63.8(g)(5)..................  Data Reduction............  Data that cannot be used    No.
                                                                  in computing averages for
                                                                  continuous emissions
                                                                  monitoring system and
                                                                  continuous opacity
                                                                  monitoring system.
Sec.   63.9(a).....................  Notification Requirements.  Applicability and State     Yes.
                                                                  Delegation.
Sec.   63.9(b)(1)-(5)..............  Initial Notifications.....  Submit notification 120     Yes.
                                                                  days after effective
                                                                  date; and Notification of
                                                                  intent to construct/
                                                                  reconstruct; and
                                                                  Notification of
                                                                  commencement of construct/
                                                                  reconstruct; Notification
                                                                  of startup; and Contents
                                                                  of each.
Sec.   63.9(c).....................  Request for Compliance      Can request if cannot       Yes.
                                      Extension.                  comply by date or if
                                                                  installed BACT/LAER.
Sec.   63.9(d).....................  Notification of Special     For sources that commence   Yes.
                                      Compliance Requirements     construction between
                                      for New Source.             proposal and promulgation
                                                                  and want to comply 3
                                                                  years after effective
                                                                  date.
Sec.   63.9(e).....................  Notification of             Notify Administrator 60     No.
                                      Performance Test.           days prior.

[[Page 55281]]

 
Sec.   63.9(f).....................  Notification of VE/Opacity  Notify Administrator 30     No.
                                      Test.                       days prior.
Sec.   63.9(g).....................  Additional Notifications    Notification of             Yes.
                                      When Using Continuous       performance evaluation;
                                      Monitoring Systems.         and notification using
                                                                  continuous opacity
                                                                  monitoring system data;
                                                                  and notification that
                                                                  exceeded criterion for
                                                                  relative accuracy.
Sec.   63.9(h)(1)-(6)..............  Notification of Compliance  Contents; and due 60 days   Yes.
                                      Status.                     after end of performance
                                                                  test or other compliance
                                                                  demonstration, and when
                                                                  to submit to Federal vs.
                                                                  State authority.
Sec.   63.9(i).....................  Adjustment of Submittal     Procedures for              Yes.
                                      Deadlines.                  Administrator to approve
                                                                  change in when
                                                                  notifications must be
                                                                  submitted.
Sec.   63.9(j).....................  Change in Previous          Must submit within 15 days  Yes.
                                      Information.                after the change.
Sec.   63.10(a)....................  Recordkeeping/Reporting...  Applies to all, unless      Yes.
                                                                  compliance extension; and
                                                                  when to submit to Federal
                                                                  vs. State authority; and
                                                                  procedures for owners of
                                                                  more than 1 source.
Sec.   63.10(b)(1).................  Recordkeeping/Reporting...  General Requirements; and   Yes.
                                                                  keep all records readily
                                                                  available and keep for 5
                                                                  years.
Sec.   63.10(b)(2)(i)-(v)..........  Records related to          Occurrence of each of       Yes.
                                      Startup, Shutdown, and      operation (process,
                                      Malfunction.                equipment); and
                                                                  occurrence of each
                                                                  malfunction of air
                                                                  pollution equipment; and
                                                                  maintenance of air
                                                                  pollution control
                                                                  equipment; and actions
                                                                  during startup, shutdown,
                                                                  and malfunction.
Sec.   63.10(b)(2)(vi) and (x-xi)..  Continuous monitoring       Malfunctions, inoperative,  Yes.
                                      systems Records.            out-of-control; and
                                                                  calibration checks; and
                                                                  adjustments, maintenance.
Sec.   63.10(b)(2)(vii)-(ix).......  Records...................  Measurements to             Yes.
                                                                  demonstrate compliance
                                                                  with emission
                                                                  limitations; and
                                                                  performance test,
                                                                  performance evaluation,
                                                                  and visible emission
                                                                  observation results; and
                                                                  measurements to determine
                                                                  conditions of performance
                                                                  tests and performance
                                                                  evaluations.
Sec.   63.10(b)(2)(xii)............  Records...................  Records when under waiver.  Yes.
Sec.   63.10(b)(2)(xiii)...........  Records...................  Records when using          No.
                                                                  alternative to relative
                                                                  accuracy test.
Sec.   63.10(b)(2)(xiv)............  Records...................  All documentation           Yes.
                                                                  supporting Initial
                                                                  Notification and
                                                                  Notification of
                                                                  Compliance Status.
Sec.   63.10(b)(3).................  Records...................  Applicability               Yes.
                                                                  Determinations.
Sec.   63.10(c)(1),(5)-(8),(10)-     Records...................  Additional Records for      Yes.
 (15).                                                            continuous monitoring
                                                                  systems.
Sec.   63.10(c)(7)-(8).............  Records...................  Records of excess           No.
                                                                  emissions and parameter
                                                                  monitoring exceedances
                                                                  for continuous monitoring
                                                                  systems.
Sec.   63.10(d)(1).................  General Reporting           Requirement to report.....  Yes.
                                      Requirements.
Sec.   63.10(d)(2).................  Report of Performance Test  When to submit to Federal   Yes.
                                      Results.                    or State authority.
Sec.   63.10(d)(3).................  Reporting Opacity or VE     What to report and when...  Yes.
                                      Observations.
Sec.   63.10(d)(4).................  Progress Reports..........  Must submit progress        Yes.
                                                                  reports on schedule if
                                                                  under compliance
                                                                  extension.
Sec.   63.10(d)(5).................  Startup, Shutdown, and      Contents and submission...  Yes.
                                      Malfunction Reports.
Sec.   63.10(e)(1)(2)..............  Additional continuous       Must report results for     Yes.
                                      monitoring systems          each CEM on a unit; and
                                      Reports.                    written copy of
                                                                  performance evaluation;
                                                                  and 3 copies of
                                                                  continuous opacity
                                                                  monitoring system
                                                                  performance evaluation.
Sec.   63.10(e)(3).................  Reports...................  Excess Emission Reports...  No.
Sec.   63.10(e)(3)(i-iii)..........  Reports...................  Schedule for reporting      No.
                                                                  excess emissions and
                                                                  parameter monitor
                                                                  exceedance (now defined
                                                                  as deviations).

[[Page 55282]]

 
Sec.   63.10(e)(3)(iv-v)...........  Excess Emissions Reports..  Requirement to revert to    No.
                                                                  quarterly submission if
                                                                  there is an excess
                                                                  emissions and parameter
                                                                  monitor exceedance (now
                                                                  defined as deviations);
                                                                  and provision to request
                                                                  semiannual reporting
                                                                  after compliance for one
                                                                  year; and submit report
                                                                  by 30th day following end
                                                                  of quarter or calendar
                                                                  half; and if there has
                                                                  not been an exceedance or
                                                                  excess emission (now
                                                                  defined as deviations),
                                                                  report contents is a
                                                                  statement that there have
                                                                  been no deviations.
Sec.   63.10(e)(3)(iv-v)...........  Excess Emissions Reports..  Must submit report          No.
                                                                  containing all of the
                                                                  information in Sec.
                                                                  63.10(c)(5-13), Sec.
                                                                  63.8(c)(7-8).
Sec.   63.10(e)(3)(vi-viii)........  Excess Emissions Report     Requirements for reporting  No.
                                      and Summary Report.         excess emissions for
                                                                  continuous monitoring
                                                                  systems (now called
                                                                  deviations); Requires all
                                                                  of the information in
                                                                  Sec.   63.10(c)(5-13),
                                                                  Sec.   63.8(c)(7-8).
Sec.   63.10(e)(4).................  Reporting continuous        Must submit continuous      Yes.
                                      opacity monitoring system   opacity monitoring system
                                      data.                       data with performance
                                                                  test data.
Sec.   63.10(f)....................  Waiver for Recordkeeping/   Procedures for              Yes.
                                      Reporting.                  Administrator to waive.
Sec.   63.11.......................  Flares....................  Requirements for flares...  No.
Sec.   63.12.......................  Delegation................  State authority to enforce  Yes.
                                                                  standards.
Sec.   63.13.......................  Addresses.................  Addresses where reports,    Yes.
                                                                  notifications, and
                                                                  requests are sent.
Sec.   63.14.......................  Incorporation by Reference  Test methods incorporated   Yes.
                                                                  by reference.
Sec.   63.15.......................  Availability of             Public and confidential     Yes.
                                      Information.                Information.
----------------------------------------------------------------------------------------------------------------

Appendix A to Subpart DDDDD--Methodology and Criteria for Demonstrating 
Eligibility for the Health-Based Compliance Alternatives Specified for 
the Large Solid Fuel Subcategory

1. Purpose/Introduction

    This appendix provides the methodology and criteria for 
demonstrating that your affected source is eligible for the 
compliance alternative for the HCl emission limit and/or the total 
selected metals (TSM) emission limit. This appendix specifies 
emissions testing methods that you must use to determine HCl, 
chlorine, and manganese emissions from the affected units and what 
parts of the affected source facility must be included in the 
eligibility demonstration. You must demonstrate that your affected 
source is eligible for the health-based compliance alternatives 
using either a look-up table analysis (based on the look-up tables 
included in this appendix) or a site-specific compliance 
demonstration performed according to the criteria specified in this 
appendix. This appendix also specifies how and when you file any 
eligibility demonstrations for your affected source and how to show 
that your affected source remains eligible for the health-based 
compliance alternatives in the future.

2. Who Is Eligible To Demonstrate That They Qualify for the Health-
Based Compliance Alternatives?

    Each new, reconstructed, or existing affected source may 
demonstrate that they are eligible for the health-based compliance 
alternatives. Section 63.7490 of subpart DDDDD defines the affected 
source and explains which affected sources are new, existing, or 
reconstructed.

3. What Parts of My Facility Have To Be Included in the Health-Based 
Eligibility Demonstration?

    If you are attempting to determine your eligibility for the 
compliance alternative for HCl, you must include every emission 
point subject to subpart DDDDD that emits either HCl or 
Cl2 in the eligibility demonstration.
    If you are attempting to determine your eligibility for the 
compliance alternative for TSM, you must include every emission 
point subject to subpart DDDDD that emits manganese in the 
eligibility demonstration.

4. How Do I Determine HAP Emissions From My Affected Source?

    (a) You must conduct HAP emissions tests or fuel analysis for 
every emission point covered under subpart DDDDD within the affected 
source facility according to the requirements in paragraphs (b) 
through (f) of this section and the methods specified in Table 1 of 
this appendix.
    (1) If you are attempting to determine your eligibility for the 
compliance alternative for HCl, you must test the subpart DDDDD 
units at your facility for both HCl and Cl2. When 
conducting fuel analysis, you must assume any chlorine detected will 
be emitted as Cl2.
    (2) If you are attempting to determine your eligibility for the 
compliance alternative for TSM, you must test the subpart DDDDD 
units at your facility for manganese.
    (b) Periods when emissions tests must be conducted.
    (1) You must not conduct emissions tests during periods of 
startup, shutdown, or malfunction, as specified in Sec.  63.7(e)(1).
    (2) You must test under worst-case operating conditions as 
defined in this appendix. You must describe your worst-case 
operating conditions in your performance test report for the process 
and control systems (if applicable) and explain why the conditions 
are worst-case.
    (c) Number of test runs. You must conduct three separate test 
runs for each test required in this section, as specified in Sec.  
63.7(e)(3). Each test run must last at least 1 hour.
    (d) Sampling locations. Sampling sites must be located at the 
outlet of the control device and prior to any releases to the 
atmosphere.
    (e) Collection of monitoring data for HAP control devices. 
During the emissions test, you must collect operating parameter 
monitoring system data at least every 15 minutes during the entire 
emissions test and establish the site-specific operating 
requirements in Tables 3 or 4, as appropriate, of subpart DDDDD 
using data from the monitoring system and the procedures specified 
in Sec.  63.7530 of subpart DDDDD.

[[Page 55283]]

    (f) Nondetect data. You may treat emissions of an individual HAP 
as zero if all of the test runs result in a nondetect measurement 
and the condition in paragraph (f)(1) of this section is met for the 
manganese test method. Otherwise, nondetect data for individual HAP 
must be treated as one-half of the method detection limit.
    (1) For manganese measured using Method 29 in appendix A to 40 
CFR part 60, you analyze samples using atomic absorption 
spectroscopy (AAS).
    (g) You must determine the maximum hourly emission rate for each 
appropriate emission point according to Equation 1 of this appendix.
[GRAPHIC] [TIFF OMITTED] TR13SE04.010

Where:

Max Hourly Emissions = Maximum hourly emissions for hydrogen 
chloride, chlorine, or manganese, in units of pounds per hour.
Er = Emission rate (the 3-run average as determined according to 
Table 1 of this appendix or the pollutant concentration in the fuel 
samples analyzed according to Sec.  63.7521) for hydrogen chloride, 
chlorine, or manganese, in units of pounds per million Btu of heat 
input.
Hm = Maximum rated heat input capacity of appropriate emission 
point, in units of million Btu per hour.

5. What Are the Criteria for Determining If My Facility Is Eligible for 
the Health-Based Compliance Alternatives?

    (a) Determine the HAP emissions from each appropriate emission 
point within the affected source facility using the procedures 
specified in section 4 of this appendix.
    (b) Demonstrate that your facility is eligible for either of the 
health-based compliance alternatives using either the methods 
described in section 6 of this appendix (look-up table analysis) or 
section 7 of this appendix (site-specific compliance demonstration).
    (c) Your facility is eligible for the health-based compliance 
alternative for HCl if one of the following two statements is true:
    (1) The calculated HCl-equivalent emission rate is below the 
appropriate value in the look-up table;
    (2) Your site-specific compliance demonstration indicates that 
your maximum HI for HCl and C12 at a location where 
people live is less than or equal to 1.0;
    (d) Your facility is eligible for the health-based compliance 
alternative for TSM if one of the following two statements is true:
    (1) The manganese emission rate for all your subpart DDDDD 
sources is below the appropriate value in the look-up table;
    (2) Your site-specific compliance demonstration indicates that 
your maximum HQ for manganese at a location where people live is 
less than or equal to 1.0.

6. How Do I Conduct a Look-Up Table Analysis?

    You may use look-up tables to demonstrate that your facility is 
eligible for either the compliance alternative for the HCl emission 
limit or the compliance alternative for TSM emission limit.
    (a) HCl health-based compliance alternative. (1) To calculate 
the total toxicity-weighted HCl-equivalent emission rate for your 
facility, first calculate the total affected source emission rate of 
HCl by summing the maximum hourly HCl emission rates from all your 
subpart DDDDD sources. Then, similarly, calculate the total affected 
source emission rate for Cl2. Finally, calculate the 
toxicity-weighted emission rate (expressed in HCl equivalents) 
according to Equation 2 of this appendix.
[GRAPHIC] [TIFF OMITTED] TR13SE04.011

Where:

ERtw is the HCl-equivalent emission rate, lb/hr.
ERi is the emission rate of HAP i in lbs/hr
RfCi is the reference concentration of HAP i
RfCHCl is the reference concentration of HCl (RfCs for 
HCl and Cl2 can be found at http://www.epa.gov/ttn/atw/toxsource/summary.html).

    (2) The calculated HCl-equivalent emission rate will then be 
compared to the appropriate allowable emission rate in Table 2 of 
this appendix. To determine the correct value from the table, an 
average value for the appropriate subpart DDDDD emission points 
should be used for stack height and the minimum distance between any 
appropriate subpart DDDDD stack at the facility and the property 
boundary should be used for property boundary distance. Appropriate 
emission points and stacks are those that emit HCl and/or 
Cl2. If one or both of these values does not match the 
exact values in the lookup tables, then use the next lowest table 
value. (Note: If your average stack height is less than 5 meters, 
you must use the 5 meter row.) Your facility is eligible to comply 
with the health-based alternative HCl emission limit if your 
toxicity-weighted HCl equivalent emission rate, determined using the 
methods specified in this appendix, does not exceed the appropriate 
value in Table 2 of this appendix.
    (b) TSM Compliance Alternative. To calculate the total manganese 
emission rate for your affected source, sum the maximum hourly 
manganese emission rates for all your subpart DDDDD sources. The 
calculated manganese emission rate will then be compared to the 
allowable emission rate in the Table 3 of this appendix. To 
determine the correct value from the table, an average value for the 
appropriate subpart DDDDD emission points should be used for stack 
height and the minimum distance between any appropriate subpart 
DDDDD stack at the facility and the property boundary should be used 
for property boundary distance. Appropriate emission points and 
stacks are those that emit manganese. If one or both of these values 
does not match the exact values in the lookup tables, then use the 
next lowest table value. (Note: If your average stack height is less 
than 5 meters, you must use the 5 meter row.) Your facility may 
exclude manganese when demonstrating compliance with the TSM 
emission limit if your manganese emission rate, determined using the 
methods specified in this appendix, does not exceed the appropriate 
value specified in Table 3 of this appendix.

7. How Do I Conduct a Site-Specific Compliance Demonstration?

    If you fail to demonstrate that your facility is able to comply 
with one or both of the alternative health-based emission standards 
using the look-up table approach, you may choose to perform a site-
specific compliance demonstration for your facility. You may use any 
scientifically-accepted peer-reviewed risk assessment methodology 
for your site-specific compliance demonstration. An example of one 
approach for performing a site-specific compliance demonstration for 
air toxics can be found in the EPA's ``Air Toxics Risk Assessment 
Reference Library, Volume 2, Site-Specific Risk Assessment Technical 
Resource Document'', which may be obtained through the EPA's Air 
Toxics Web site at http://www.epa.gov/ttn/fera/risk_atoxic.html.
    (a) Your facility is eligible for the HCl alternative compliance 
option if your site-specific compliance demonstration shows that the 
maximum HI for HCl and Cl2 from your subpart DDDDD 
sources is less than or equal to 1.0.
    (b) Your facility is eligible for the TSM alternative compliance 
option if your site-specific compliance demonstration shows that the 
maximum HQ for manganese from your subpart DDDDD sources is less 
than or equal to 1.0.
    (c) At a minimum, your site-specific compliance demonstration 
must:
    (1) Estimate long-term inhalation exposures through the 
estimation of annual

[[Page 55284]]

or multi-year average ambient concentrations;
    (2) Estimate the inhalation exposure for the individual most 
exposed to the facility's emissions;
    (3) Use site-specific, quality-assured data wherever possible;
    (4) Use health-protective default assumptions wherever site-
specific data are not available, and;
    (5) Contain adequate documentation of the data and methods used 
for the assessment so that it is transparent and can be reproduced 
by an experienced risk assessor and emissions measurement expert.
    (d) Your site-specific compliance demonstration need not:
    (1) Assume any attenuation of exposure concentrations due to the 
penetration of outdoor pollutants into indoor exposure areas;
    (2) Assume any reaction or deposition of the emitted pollutants 
during transport from the emission point to the point of exposure.

8. What Must My Health-Based Eligibility Demonstration Contain?

    (a) Your health-based eligibility demonstration must contain, at 
a minimum, the information specified in paragraphs (a)(1) through 
(6) of this section.
    (1) Identification of each appropriate emission point at the 
affected source facility, including the maximum rated capacity of 
each appropriate emission point.
    (2) Stack parameters for each appropriate emission point 
including, but not limited to, the parameters listed in paragraphs 
(a)(2)(i) through (iv) below:
    (i) Emission release type.
    (ii) Stack height, stack area, stack gas temperature, and stack 
gas exit velocity.
    (iii) Plot plan showing all emission points, nearby residences, 
and fenceline.
    (iv) Identification of any control devices used to reduce 
emissions from each appropriate emission point.
    (3) Emission test reports for each pollutant and appropriate 
emission point which has been tested using the test methods 
specified in Table 1 of this appendix, including a description of 
the process parameters identified as being worst case. Fuel analyses 
for each fuel and emission point which has been conducted including 
collection and analytical methods used.
    (4) Identification of the RfC values used in your look-up table 
analysis or site-specific compliance demonstration.
    (5) Calculations used to determine the HCl-equivalent or 
manganese emission rates according to sections 6(a) or (b) of this 
appendix.
    (6) Identification of the controlling process factors 
(including, but not limited to, fuel type, heat input rate, type of 
control devices, process parameters reflecting the emissions rates 
used for your eligibility demonstration) that will become Federally 
enforceable permit conditions used to show that your facility 
remains eligible for the health-based compliance alternatives.
    (b) If you use the look-up table analysis in section 6 of this 
appendix to demonstrate that your facility is eligible for either 
health-based compliance alternative, your eligibility demonstration 
must contain, at a minimum, the information in paragraphs (a) and 
(b)(1) through (3) of this section.
    (1) Calculations used to determine the average stack height of 
the subpart DDDDD emission points that emit either manganese or HCl 
and Cl2.
    (2) Identification of the subpart DDDDD emission point, that 
emits either manganese or HCl and Cl2, with the minimum 
distance to the property boundary of the facility.
    (3) Comparison of the values in the look-up tables (Tables 2 and 
3 of this appendix) to your maximum HCl-equivalent or manganese 
emission rates.
    (c) If you use a site-specific compliance demonstration as 
described in section 7 of this appendix to demonstrate that your 
facility is eligible, your eligibility demonstration must contain, 
at a minimum, the information in paragraphs (a) and (c)(1) through 
(7) of this section:
    (1) Identification of the risk assessment methodology used.
    (2) Documentation of the fate and transport model used.
    (3) Documentation of the fate and transport model inputs, 
including the information described in paragraphs (a)(1) through (5) 
of this section converted to the dimensions required for the model 
and all of the following that apply: meteorological data; building, 
land use, and terrain data; receptor locations and population data; 
and other facility-specific parameters input into the model.
    (4) Documentation of the fate and transport model outputs.
    (5) Documentation of any exposure assessment and risk 
characterization calculations.
    (6) Comparison of the HQ HI to the limit of 1.0.

9. When Do I Have to Complete and Submit My Health-Based Eligibility 
Demonstration?

    (a) If you have an existing affected source, you must complete 
and submit your eligibility demonstration to your permitting 
authority, along with a signed certification that the demonstration 
is an accurate depiction of your facility, no later than the date 
one year prior to the compliance date of subpart DDDDD. A separate 
copy of the eligibility demonstration must be submitted to: U.S. 
EPA, Risk and Exposure Assessment Group, Emission Standards Division 
(C404-01), Attn: Group Leader, Research Triangle Park, North 
Carolina 27711, electronic mail address [email protected].
    (b) If you have a new or reconstructed affected source that 
starts up before the effective date of subpart DDDDD, or an affected 
source that is an area source that increases its emissions or its 
potential to emit such that it becomes a major source of HAP before 
the effective date of subpart DDDDD, then you must comply with the 
requirements of subpart DDDDD until your eligibility demonstration 
is completed and submitted to your permitting authority.
    (c) If you have a new or reconstructed affected source that 
starts up after the effective date of subpart DDDDD, or an affected 
source that is an area source that increases its emissions or its 
potential to emit such that it becomes a major source of HAP after 
the effective date for subpart DDDDD, then you must follow the 
schedule in paragraphs (c)(1) and (2) of this section.
    (1) You must complete and submit a preliminary eligibility 
demonstration based on the information (e.g., equipment types, 
estimated emission rates, etc.) used to obtain your title V permit. 
You must base your preliminary eligibility demonstration on the 
maximum emissions allowed under your title V permit. If the 
preliminary eligibility demonstration indicates that your affected 
source facility is eligible for either compliance alternative, then 
you may start up your new affected source and your new affected 
source will be considered in compliance with the alternative HCl 
standard and subject to the compliance requirements in this appendix 
or, in the case of manganese, your compliance demonstration with the 
TSM emission limit is based on 7 metals (excluding manganese).
    (2) You must conduct the emission tests or fuel analysis 
specified in section 4 of this appendix upon initial startup and use 
the results of these emissions tests to complete and submit your 
eligibility demonstration within 180 days following your initial 
startup date. To be eligible, you must meet the criteria in section 
11 of this appendix within 18 months following initial startup of 
your affected source.

10. When Do I Become Eligible for the Health-Based Compliance 
Alternatives?

    To be eligible for either health-based compliance alternative, 
the parameters that defined your affected source as eligible for the 
health-based compliance alternatives (including, but not limited to, 
fuel type, fuel mix (annual average), type of control devices, 
process parameters reflecting the emissions rates used for your 
eligibility demonstration) must be submitted for incorporation as 
Federally enforceable limits into your title V permit. If you do not 
meet these criteria, then your affected source is subject to the 
applicable emission limits, operating limits, and work practice 
standards in Subpart DDDDD.

11. How Do I Ensure That My Facility Remains Eligible for the Health-
Based Compliance Alternatives?

    (a) You must update your eligibility demonstration and resubmit 
it each time you have a process change, such that any of the 
parameters that defined your affected source changes in a way that 
could result in increased HAP emissions (including, but not limited 
to, fuel type, fuel mix (annual average), change in type of control 
device, changes in process parameters documented as worst-case 
conditions during the emissions testing used for your approved 
eligibility demonstration).
    (b) If you are updating your eligibility demonstration to 
account for an action in paragraph (a) of this section, then you 
must perform emission testing or fuel analysis according to section 
4 of this appendix for the subpart DDDDD emission points that may 
have increased HAP emissions beyond the levels reflected in your 
previously approved eligibility demonstration due to the process

[[Page 55285]]

change. You must submit your revised eligibility demonstration to 
the permitting authority prior to revising your permit to 
incorporate the process change. If your updated eligibility 
demonstration indicates that your affected source is no longer 
eligible for the health-based compliance alternatives, then you must 
comply with the applicable emission limits, operating limits, and 
compliance requirements in Subpart DDDDD prior to making the process 
change and revising your permit.

12. What Records Must I Keep?

    You must keep records of the information used in developing the 
eligibility demonstration for your affected source, including all of 
the information specified in section 8 of this appendix.

13. Definitions

    The definitions in Sec.  63.7575 of subpart DDDDD apply to this 
appendix. Additional definitions applicable for this appendix are as 
follows:
    Hazard Index (HI) means the sum of more than one hazard quotient 
for multiple substances and/or multiple exposure pathways.
    Hazard Quotient (HQ) means the ratio of the predicted media 
concentration of a pollutant to the media concentration at which no 
adverse effects are expected. For inhalation exposures, the HQ is 
calculated as the air concentration divided by the RfC.
    Look-up table analysis means a risk screening analysis based on 
comparing the HAP or HAP-equivalent emission rate from the affected 
source to the appropriate maximum allowable HAP or HAP-equivalent 
emission rates specified in Tables 2 and 3 of this appendix.
    Reference Concentration (RfC) means an estimate (with 
uncertainty spanning perhaps an order of magnitude) of a continuous 
inhalation exposure to the human population (including sensitive 
subgroups) that is likely to be without an appreciable risk of 
deleterious effects during a lifetime. It can be derived from 
various types of human or animal data, with uncertainty factors 
generally applied to reflect limitations of the data used.
    Worst-case operating conditions means operation of an affected 
unit during emissions testing under the conditions that result in 
the highest HAP emissions or that result in the emissions stream 
composition (including HAP and non-HAP) that is most challenging for 
the control device if a control device is used. For example, worst-
case conditions could include operation of an affected unit firing 
solid fuel likely to produce the most HAP.

      Table 1 to Appendix B of Subpart DDDDD--Emission Test Methods
------------------------------------------------------------------------
            For . . .               You must . . .        Using . . .
------------------------------------------------------------------------
(1) Each subpart DDDDD emission   Select sampling     Method 1 of 40 CFR
 point for which you choose to     ports' location     part 60, appendix
 use a compliance alternative.     and the number of   A.
                                   traverse points.
(2) Each subpart DDDDD emission   Determine velocity  Method 2, 2F, or
 point for which you choose to     and volumetric      2G in appendix A
 use a compliance alternative.     flow rate;.         to 40 CFR part
                                                       60.
(3) Each subpart DDDDD emission   Conduct gas         Method 3A or 3B in
 point for which you choose to     molecular weight    appendix A to 40
 use a compliance alternative.     analysis.           CFR part 60.
(4) Each subpart DDDDD emission   Measure moisture    Method 4 in
 point for which you choose to     content of the      appendix A to 40
 use a compliance alternative.     stack gas.          CFR part 60.
(5) Each subpart DDDDD emission   Measure the         Method 26 or 26A
 point for which you choose to     hydrogen chloride   in appendix A to
 use the HCl compliance            and chlorine        40 CFR part 60.
 alternative.                      emission
                                   concentrations.
(6) Each subpart DDDDD emission   Measure the         Method 29 in
 point for which you choose to     manganese           appendix A to 40
 use the TSM compliance            emission            CFR part 60.
 alternative.                      concentration.
(7) Each subpart DDDDD emission   Convert emissions   Method 19 F-factor
 point for which you choose to     concentration to    methodology in
 use a compliance alternative.     lb per MMBtu        appendix A to
                                   emission rates.     part 60 of this
                                                       chapter.
------------------------------------------------------------------------


[[Page 55286]]


                 Table 2 to Appendix A of Subpart DDDDD--Allowable Toxicity-Weighted Emission Rate Expressed in HCl Equivalents (lbs/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Distance to property boundary (m)
          Stack ht. (m)          -----------------------------------------------------------------------------------------------------------------------
                                      0        50        100       150       200       250       500      1000      1500      2000      3000      5000
--------------------------------------------------------------------------------------------------------------------------------------------------------
5...............................     114.9     114.9     114.9     114.9     114.9     114.9     144.3     287.3     373.0     373.0     373.0     373.0
10..............................     188.5     188.5     188.5     188.5     188.5     188.5     195.3     328.0     432.5     432.5     432.5     432.5
20..............................     386.1     386.1     386.1     386.1     386.1     386.1     386.1     425.4     580.0     602.7     602.7     602.7
30..............................     396.1     396.1     396.1     396.1     396.1     396.1     396.1     436.3     596.2     690.6     807.8     816.5
40..............................     408.1     408.1     408.1     408.1     408.1     408.1     408.1     448.2     613.3     715.5     832.2     966.0
50..............................     421.4     421.4     421.4     421.4     421.4     421.4     421.4     460.6     631.0     746.3     858.2    1002.8
60..............................     435.5     435.5     435.5     435.5     435.5     435.5     435.5     473.4     649.0     778.6     885.0    1043.4
70..............................     450.2     450.2     450.2     450.2     450.2     450.2     450.2     486.6     667.4     813.8     912.4    1087.4
80..............................     465.5     465.5     465.5     465.5     465.5     465.5     465.5     500.0     685.9     849.8     940.9    1134.8
100.............................     497.5     497.5     497.5     497.5     497.5     497.5     497.5     527.4     723.6     917.1    1001.2    1241.3
200.............................     677.3     677.3     677.3     677.3     677.3     677.3     677.3     682.3     919.8    1167.1    1390.4    1924.6
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table 3 to Appendix A of Subpart DDDDD--Allowable Manganese Emission Rate (lbs/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Distance to property boundary (m)
          Stack ht. (m)          -----------------------------------------------------------------------------------------------------------------------
                                      0        50        100       150       200       250       500      1000      1500      2000      3000      5000
--------------------------------------------------------------------------------------------------------------------------------------------------------
5...............................      0.29      0.29      0.29      0.29      0.29      0.29      0.36      0.72      0.93      0.93      0.93      0.94
10..............................      0.47      0.47      0.47      0.47      0.47      0.47      0.49      0.82      1.08      1.08      1.08      1.08
20..............................      0.97      0.97      0.97      0.97      0.97      0.97      0.97      1.06      1.45      1.51      1.51      1.51
30..............................      0.99      0.99      0.99      0.99      0.99      0.99      0.99      1.09      1.49      1.72      2.02      2.04
40..............................      1.02      1.02      1.02      1.02      1.02      1.02      1.02      1.12      1.53      1.79      2.08      2.42
50..............................      1.05      1.05      1.05      1.05      1.05      1.05      1.05      1.15      1.58      1.87      2.15      2.51
60..............................      1.09      1.09      1.09      1.09      1.09      1.09      1.09      1.18      1.62      1.95      2.21      2.61
70..............................      1.13      1.13      1.13      1.13      1.13      1.13      1.13      1.22      1.67      2.03      2.28      2.72
80..............................      1.16      1.16      1.16      1.16      1.16      1.16      1.16      1.25      1.71      2.12      2.35      2.84
100.............................      1.24      1.24      1.24      1.24      1.24      1.24      1.24      1.32      1.81      2.29      2.50      3.10
200.............................      1.69      1.69      1.69      1.69      1.69      1.69      1.69      1.71      2.30      2.92      3.48      4.81
--------------------------------------------------------------------------------------------------------------------------------------------------------

[FR Doc. 04-11221 Filed 9-10-04; 8:45 am]
BILLING CODE 6560-50-U