6560 50 P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [ OAR 2002 0058; FRL ]

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.

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 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, 2 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 EPA is also adding risk based alternative compliance options for the hydrogen chloride and total selected metals emission limits. This action is being taken in part to respond to comments submitted by the American Forest & Paper Association ( AF& PA), the American Furniture Manufactures Association ( AFMA), and in part upon the Administrator's own motion. This action is based on EPA's evaluation of the available information concerning the potential hazards from exposure to hydrogen chloride and manganese emitted by boilers and process heaters.

EFFECTIVE DATE: [ INSERT THE DATE 60 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]

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 3 Docket) in the EPA Docket Center, Room B 102, 1301 Constitution Avenue, NW, Washington, DC.

FOR FURTHER INFORMATION CONTACT: For information concerning applicability and rule determinations, contact your State or local representative or appropriate EPA Regional Office representative. For information concerning rule development, contact Jim Eddinger, Combustion Group,

Emission Standards Division ( C439 01), U. S. EPA, Research Triangle Park, North Carolina 27711, telephone number ( 919)

541 5426, fax number ( 919) 541 5450, electronic mail address eddinger. jim@ epa. gov.

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

Category NAICS Code SIC Code Examples of potentially regulated entities Any industry using a boiler or process heater as defined in this regulation 211 13 Extractors of crude petroleum and 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 4 316, 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 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 § 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 2003 0058 and Docket No. A 96 47. The official public docket consists of the 5 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) 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 6 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 [ INSERT THE DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER]. Only those objections to the 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 7 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 background information document ( BID) (" National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, Summary of Public Comments and Responses," December 2003, EPA 453/ R 03 )

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 8 requirements? G. What are the continuous compliance requirements? H. What are the notification, recordkeeping and reporting requirements? I. What are the risk based provisions and how do I demonstrate eligibility? III. What are the significant changes since proposal? B. Definition of Affected Source C. Sources Not Covered by the NESHAP D. Emission Limits E. Definitions Added and Revised F. Requirements for Sources in Subcategories Without Emission Limit or Work Practice Requirements G. CO Work Practice Emission Level and Requirements H. Fuel Analysis Option I. Emissions Averaging J. Opacity Limit K. Operating Limit Determination L. 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 quality 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? G. How will the risk based exemption reduce impacts? 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 9 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 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 10 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. Industry representatives, regulatory agencies, environmental groups,

and the general public were given the opportunity to comment on the proposed rule and to provide additional information during the public comment period.

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 11 1 Please note that boilers that burn small quantities of hazardous waste under the exemptions provided by 40 CFR 266.108 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 excluded from the final rule include: municipal waste combustors covered by the new source performance standards ( NSPS) in 40 CFR part 60, subparts AAAA, BBBB, or Cb); hospital/ medical/ infectious waste incinerators covered by the NSPS in 40 CFR part 60, subparts Ce or Ec; 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 EEE1; 12 are subject to today's final rule. commercial and industrial solid waste incinerators ( CISWI)

covered in 40 CFR part 60, subparts CCCC and DDDD; and recovery boilers or furnaces covered by 40 CFR part 63,

subpart MM.

Fossil fuel fired utility boilers are exempt from the final rule. Non fossil fuel fired utility boilers are covered by the final rule. A fossil fuel fired utility boiler is a fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A 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.

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 still 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 13 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 exempt from 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 14 lesser amounts of hydrogen fluoride, 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 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. We do not know the extent to which the adverse health effects described above occur in the populations surrounding these facilities. 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). Acute ( short term) exposure to acetaldehyde 15 results in effects including irritation of the eyes, skin,

and respiratory tract. In humans, symptoms of chronic ( long term) exposure to acetaldehyde resemble those of alcoholism. Long term inhalation exposure studies in animals reported damage to the nasal epithelium and mucous membranes, growth retardation, and increased kidney weight.

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.

Arsenic Acute ( short term) high level inhalation exposure to arsenic dust or fumes has resulted in gastrointestinal effects ( nausea, diarrhea, abdominal pain), and central and peripheral nervous system disorders. 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 of women working at or living near metal smelters and an increased risk of reproductive effects, such as spontaneous abortions. 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. 16 Benzene Acute ( short term) inhalation exposure of humans to benzene may cause drowsiness, dizziness, headaches, as well as eye, skin, and respiratory tract irritation, and, at high levels, unconsciousness. Chronic ( long term) inhalation exposure has caused various disorders in the blood,

including reduced numbers of red blood cells and aplastic anemia, in occupational settings. Reproductive effects have been reported for women exposed by inhalation to high levels and adverse effects on the developing fetus have been observed in animal tests. Increased incidence of leukemia ( cancer of the tissues that form white blood cells) has been observed in humans occupationally exposed to benzene. EPA has classified benzene as a Group A, known human carcinogen.

Cadmium The acute ( short term) effects of cadmium inhalation in humans consist mainly of effects on the lung, such as pulmonary irritation. 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 in animals, resulting in fetal malformations and other effects, but no conclusive evidence exists in humans. An association between cadmium exposure and an increased risk of lung cancer has been reported from human studies, but these studies are 17 inconclusive due to confounding factors. 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.

Chromium Chromium may be emitted 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 acute ( short term) and chronic ( long term) inhalation exposures. Shortness of breath,

coughing, and wheezing have been reported from acute exposure to chromium VI, while perforations and ulcerations of the septum, bronchitis, decreased pulmonary function,

pneumonia, and other respiratory effects have been noted from chronic exposure. 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 18 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 Both acute ( short term) and chronic ( long term)

exposure to formaldehyde irritates the eyes, nose, and throat, and may cause coughing, chest pains, and bronchitis.

Reproductive effects, such as menstrual disorders and pregnancy problems, have been reported in female workers exposed to 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. 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. Acute ( short term) inhalation exposure may cause eye, nose, and respiratory tract irritation and inflammation and pulmonary edema in humans. Chronic ( long term) occupational exposure to hydrochloric acid has been reported to cause gastritis, 19 bronchitis, and dermatitis in workers. Prolonged exposure to low 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 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 Acute ( short term) inhalation exposure to gaseous hydrogen fluoride can cause severe respiratory damage in humans, including severe irritation and pulmonary edema.

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 is a very toxic element, causing a variety of effects at low dose levels. Brain damage, kidney damage,

and gastrointestinal distress may occur from acute (

shortterm exposure to high levels of lead in humans. Chronic 20 ( long term) exposure to 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 lead exposure by the oral route. The EPA has classified lead as a Group B2, probable human carcinogen.

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.

Manganism, characterized by feelings of weakness and 21 lethargy, tremors, a mask like face, and psychological disturbances, may result from chronic exposure to higher levels. Impotence and loss of libido have been noted in male workers afflicted with manganism attributed to 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.

Acute ( short term) exposure to high levels of elemental mercury in humans results in CNS effects such as tremors,

mood changes, and slowed sensory and motor nerve function.

High inhalation exposures can also cause kidney damage and effects on the gastrointestinal tract and respiratory system. 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. 22 Acute exposure to inorganic mercury by the oral route may result in effects such as nausea, vomiting, and severe abdominal pain. The major effect from chronic exposure to inorganic mercury is kidney damage. 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 forestomach, thyroid, and renal 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. 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 23 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.

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 24 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. Any temporary boiler that replaces a temporary boiler and is 25 intended to perform the same or similar function will be included in the determination of the consecutive 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 located at a major source; or ( 2) each new or reconstructed industrial, commercial or institutional 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 26 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 that 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. 27 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 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 28 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 this preamble.

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. 29 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))

Sour ce Subcateg ory Particul ate Matter ( PM) or Total Select ed Metals Hydrog en Chlori de ( HCl) Mercu ry ( Hg) Carbon Monoxid e ( CO)( pp m New Boil er or Proc ess Heat er Solid Fuel, Large Unit 0.025 or 0.0003 0.02 0.000 003 400 (@ 7% oxy gen)

Solid Fuel, Small Unit 0.025 or 0.0003 0.02 0.000 003  30 Solid Fuel, Limited Use 0.025 or 0.0003 0.02 0.000 003 400 (@ 7% oxy gen)

Liquid Fuel, Large Unit 0.03  0.0005  400 (@ 3% oxy gen)

Liquid Fuel, Small Unit 0.03  0.0009

Liquid Fuel, Limited Use 0.03  0.0009  400 (@ 3% oxy gen)

Gaseous Fuel Large Unit     400 (@ 3% oxy gen)

Gaseous Fuel Small Unit

Gaseous Fuel Limited Use     400 (@ 3% oxy gen)

Exis ting Boil er or Proc ess Heat er Solid Fuel, Large Unit 0.07 or 0.002 0.09 0.000 009

Solid Fuel, Small Unit

Solid Fuel, Limited Use 0.21 or 0.002    31 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 alternative compliance options 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 solid fuel fired units using emissions averaging.

F. What are the testing and initial compliance requirements? 32 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 33 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).

E. For new sources 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 carbon monoxide ( 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 pound per million British thermal units ( Btu) 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.

( 1) For affected sources that choose to meet the emission limits based on fuel analysis, conduct the fuel analysis using method ASTM D5865 01ael or ASTM E711 87 to 34 determine heat content, ASTM D3684 01 ( for coal) or 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 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 35 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, the source may elect to operate the fabric filter such that an installed bag leak detection system alarm does not sound more than 5 percent of the operating time during any 6 month period. If you can demonstrate compliance with the PM, mercury, or metals limits but cannot demonstrate compliance with the opacity operating limit, then you can establish a site specific maximum opacity operating limit using data from a continuous opacity monitoring system and calculated from the average opacity for each individual test run.

( 2) For boilers and process heaters without wet or dry scrubbers that must comply with an HCl emission limit, you must determine the average hydrogen chloride content level in the input fuel( s) during the HCl performance test. This is your maximum hydrogen 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 36 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 37 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 38 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, fuel inlet operating limit when conducting performance tests.

( 9) For new boilers and process heaters in any of the large or limited use 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 daily 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 large or limited use subcategories and 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 alternative compliance option. You may demonstrate compliance by emissions averaging for existing solid fuel fired boilers in 39 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 40 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 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 41 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 flowrate 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 42 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 choose to 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 43 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 or limited use subcategories with heat input capacities greater or equal to 100 MMBtu/ hr, you must continuously monitor CO and maintain the average daily 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, 44 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 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 and limited use gaseous fuel fired subcategories,

existing large and limited used liquid fuel fired subcategories, new small gaseous fuel fired subcategory, or new small liquid fuel fired units 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 fired subcategories, 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: 45 ( 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 hydrogen chloride fuel input, as required in the final rule.

( 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 46 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 this subpart.

( 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 emissions average ( 6) Compliance reports semi annually.

I. What are the risk based alternative compliance options 47 and how do I demonstrate eligibility?

As an alternative to the requirement for each large solid fuel fired boilers to demonstrate compliance with the HCl emission limit in the final rule, you may demonstrate compliance with a risk based facility wide HCl equivalent allowable emission limit.

The procedures for demonstrating eligibility for HCl alternative compliance option are:

( 1) You must include every appropriate emission point within the facility that emits HCl and/ or chlorine.

( 2) You must conduct HCl and chlorine emissions tests for every appropriate emission point that emits HCl and/ or chlorine.

( 3) Determine the total maximum hourly mass HCl and chlorine emission rate for your facility by summing the maximum hourly mass HCl and chlorine emission rate ( calculated using the maximum rated capacities of the units) for each of the units.

( 4) Use the look up table in the final rule to determine if your facility is in compliance with risk based HCl emission limit.

( 5) Select the maximum allowable HCl emission rate from the look up table for you facility using the average stack height of your HCl/ chlorine emission points and the minimum distance between any HCl/ chlorine emission point at the 48 facility and the closest boundary of the nearest residential ( or residentially zoned) area should be used for fenceline distance.

( 6) Your facility is in compliance if your maximum HCl/ chlorine emission rate does not exceed the value specified in the look up table.

( 7) As an alternative to using the look up table, you may use methodology for conducting site specific risk assessment specified in Appendix A of the final rule.

( 8) Alternatively, you can choose to assess only the emission points covered by final rule. If you choose this option under the lookup table approach, you must multiply the appropriate value in the lookup table by 0.5 to arrive at your allowable HCl emission rate. Under the sitespecific risk assessment approach, you must compare the Hazard Index to the limit of 0.5.

In lieu of complying with the emission standard for total selected metals ( TSM) in the final based on the sum of emissions for the 8 selected metals, you may be eligible for complying with the TSM standard based on excluding manganese emissions from the summation for determining selected metals emissions for the affected source unit.

The procedures for demonstrating eligibility for the TSM alternative compliance option are:

( 1) You must include every appropriate emission point 49 within the facility that emits manganese in the eligibility demonstration.

( 2) You must conduct manganese emissions tests for every appropriate emission point that emits manganese.

( 3) Determine the total maximum hourly mass emission rate of manganese from your facility by summing the maximum hourly mass manganese emission rate ( calculated using the maximum rated heat input capacities) for each of the units.

( 4) Use the look up table in Appendix A of the final rule to determine if your facility is eligible for complying with the TSM limit based on the sum of emissions for 7 metals ( excluding manganese) for the affected source units.

( 5) Select the maximum allowable manganese emission rate from the look up table for you facility using the average stack height of your manganese emission points and the minimum distance between any manganese emission point at the facility and the closest boundary of the nearest residential ( or residentially zoned) area should be used for fenceline distance.

( 6) Your facility is eligible if your maximum manganese emission rate does not exceed the value specified in the look up table.

( 7) As an alternative to using look up table to determine if your facility is eligible for the TSM alternative compliance option, you may use methodology for 50 conducting site specific risk assessment specified in Appendix A of the final rule.

( 8) Alternatively, you can choose to assess only the emission points covered by subpart DDDDD. If you choose this option under the lookup table approach, you must multiply the appropriate value in the lookup table by 0.5 to arrive at your allowable manganese emission rate. Under the site specific risk assessment approach, you must compare the Hazard Index to the limit of 0.5.

If you elect to demonstrate eligibility for the riskbased provisions, you must submit a certified documentation supporting compliance with the procedures at least one 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 fenceline distances to each on site source of HCl/ Cl2 and/ or manganese emissions.

You must keep records of the information used in developing the eligibility demonstration for your affected source.

If you intend to change key parameters, including distance of stack to the fence line, that may result in lower allowable risk based emission limits, you must recalculate the limits under the provisions of this section, 51 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/ CL2 and/ or manganese emissions, you must recalculate the total maximum hourly mass emission rate of HCl/ CL2 and/ or manganese 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 § 63.7490 has been revised to be: ( 1) the collection of all existing industrial, commercial, or institutional boilers or process heaters 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 exemptions in the applicability section of the final NESHAP ( § 63.7490( c)) have been written to also include: blast furnace stoves, any boiler or process heater specifically listed as an affected source in another MACT 52 standard, temporary boilers, and blast furnace gas fuelfired 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 and 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. 53 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 this NESHAP.

E. Requirements for Sources in Subcategories Without Emission Limit or Work Practice Requirements 54 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, new small gaseous fuel subcategory and new small liquid fuel subcategory are only subject to the initial notification requirements in § 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 are not subject to any requirements in the final rule or of subpart A of this part.

F. CO Work Practice Emission Level 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 that 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 55 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 hydrogen chloride, mercury, or total selected metals 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 56 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.

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 and fuel analysis 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 H. Emissions Averaging We have included an option in the final rule to allow emissions averaging between existing large solid fuel fired boilers only. 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 option,

you must use equations provided in the final rule to demonstrate that particulate matter or total selected metals, hydrogen chloride, and mercury from all applicable units do not exceed the emission limits specified in the 57 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 final rule provides two options. 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).

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 testrun 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, 58 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 § 63.7510, we have also written the date by which you have to demonstrate compliance 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. 59 Response: We contend that sources in subcategories that do not have any emission limitations and work practices should not be 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. We do not believe the SSM plan to be necessary or required for these units because § 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, 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 60 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 facilities 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 to exempt temporary/ portable units from 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 61 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,

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 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. We do not feel there is justification for developing a lower size cut 62 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 exempted from the final rule.

Response: We have included an extensive list of sources that are exempt from the final rule. The final rule clarifies that boilers and process heaters that are included as part of the affected source in another NESHAP are exempt 63 from the industrial boilers NESHAP. However, we do not exempt boilers and process heaters that are used as control devices unless they are specifically considered part of another 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 this 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 industrial boilers NESHAP unless it is subject to another NESHAP. The final rule directly exempts some sources and provides a blanket exemption for sources that have been specifically listed as an affected source under another NESHAP. We specifically exempt comfort heaters from the final rule. However, this exemption 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 be exempt from this 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 this NESHAP. We recognize the unique properties of blast 64 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 exempt from this NESHAP units that receive 90 percent or more of their total heat input from blast furnace gas. In the final rule, we provide a generic exemption for sources that are specifically listed as an affected source in another standard under 40 CFR part 63 in addition to the list of specific exemptions. In addition,

research and development ( R& D) operations are not be subject to the rule. Excluding them is consistent with EPA statements in the advanced notice of proposed rulemaking to list R& D as a separate source category ( 62 FR 25877) that including R& D operations in a rule governing manufacturing operations would be problematic. Therefore, 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 or for heating at a research and development facility are still subject to the final rule. We believe that this should address the commenters' concern over overlapping applicability.

Comment: Several commenters suggested that EPA revise 65 the proposed definition of affected source to be consistent with the definition of affected source in the General Provisions. The definition in the rule 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 EPA did not receive any comments opposing the new definitions for affected source and new affected source for future MACT standards when they were proposed on March 23,

2001 ( 66 FR 16318). Accordingly, EPA adopted these definitions as promulgated on April 5, 2002 ( 67 FR 16582).

Therefore, the definition of existing affected source in the final rule is the collection of existing industrial,

commercial, or institutional boilers and process heaters located at a major source of HAP emissions.

B. Format Comment: Several commenters opposed using one or more 66 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, we feel 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 67 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 NESHAPs as a technique to reduce the performance testing costs and believe that the use of surrogates is appropriate in this NESHAP.

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,

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 68 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 a technology based standard, 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 continue to believe that we can use particulate matter as a surrogate for the purposes of this 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 69 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 70 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. We believe that 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 emission 71 reductions associated with the options could not be evaluated because no information was available that indicated a relationship between the GCP's 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. Many 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 72 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) allows EPA, on a case by case basis to grant an extension permitting an existing source up to one additional year to comply with standards if such additional period is necessary for the installation of controls. The EPA feels that 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.

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 emission reductions, control technology applicability or effectiveness, achievability of emission reductions, or health risks. The commenter argued that EPA cannot subcategorize to reduce cost because that 73 would change section 112 standards into a cost benefit program and that is not legally defensible. The commenter noted that the D. C. 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, 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 74 ( 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.

The EPA contends that 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. 75 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. 76 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 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 chose to develop 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 77 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 a information collection request ( ICR) conducted during the rulemaking, 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. 78 Based on review of the 1979 EPA document on boiler population and the information collection request ( 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 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 fuelfired units is no emission reductions. Other commenters contended that EPA has legal authority to set the MACT floor as " no emissions control" for particular HAP categories. A commenter said that EPA's proposed " no control" as the MACT floor for some subcategories is unlawful. The commenter noted that EPA has a clear statutory obligation to set emission standards for each listed HAP. One commenter argued that EPA's determination that " no control" is the MACT floor for some subcategories is unacceptable. The commenter specifically challenged EPA's determination of the MACT floor for organic pollutants. The commenter noted that the U. S. Court of Appeals for the D. C. Circuit had squarely held, in the National Lime case, that EPA was not allowed to 79 make a " no control" determination for a pollutant emitted by a listed category of sources.

Response: First, we believe the MACT floor methodology we use is consistent with D. C. Circuit's holding in the National Lime case. The D. C. Circuit held that by focusing only on technology EPA ignored the directive in section 112( d)( 2) to consider pollution reducing measures including process changes and substitution of materials.

We also believe that 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 National Lime, 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 reduction" is lawful because we determined that the best performing sources were not achieving emissions reduction 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 80 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 81 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 82 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 controls ( 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 were considered. This consideration included determining whether switching fuels would achieve lower HAP 83 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 fuelrelated HAP emissions.

On the other hand, organic HAP can be formed from incomplete combustion of the fuel. Good combustion practice 84 ( 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 85 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 86 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 the 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 87 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 were 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 reduction. Therefore, in these circumstances, EPA believes that it 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 88 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 89 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. The EPA's interpretation of CAA section 112( d) allows EPA to use information from similar sources to set the MACT floor when no information from the subcategory is available. Although the units in the small and 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 90 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%). 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 91 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. We believe that 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 92 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 gas and liquid fuel fired units is no control. Other commenters contended that EPA's proposed " no control" as the MACT some subcategories is unlawful. The 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 D. C. 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 93 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 feels that it 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 reduction in emissions that the Administrator,

taking into consideration the costs of achieving such 94 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%). 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 95 to develop variability factors for all 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.

We believe 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 was 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 96 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.