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January 13, 2003 Part II Environmental Protection Agency 40 CFR Part 63 National Emission Standards for Hazardous Air Pollutants for Industrial/ Commercial/ Institutional Boilers and Process Heaters; Proposed Rule VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1660 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [ OAR   2002   0058; FRL   7418   9]

RIN 2060   AG69 National Emission Standards for Hazardous Air Pollutants for Industrial/ Commercial/ Institutional Boilers and Process Heaters AGENCY: Environmental Protection Agency ( EPA). ACTION: Proposed rule.

SUMMARY: The EPA is proposing national emission standards for hazardous air pollutants ( NESHAP) for industrial/ commercial/ institutional boilers and process heaters. The EPA has identified industrial/ commercial/ institutional boilers and process heaters as major sources of hazardous air pollutants ( HAP) emissions. The proposed rule would 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 proposed rule would reduce HAP emissions by 58,000 tons per year, hydrogen chloride   a substance that is not considered to be a carcinogen   accounts for 42,000 tons per year ( 72 percent) of total HAP emissions reductions. The proposed rule would protect air quality and promote the public health by reducing emissions of some of the HAP listed in section 112( b)( 1) of the CAA. The HAP emitted by facilities in the boiler and process heater source category include arsenic, cadmium, chromium, hydrogen chloride ( HCl), hydrogen fluoride, lead, manganese, mercury, and nickel. 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. The adverse health effects associated with the exposure to these specific HAP are further described in this preamble. In general, these findings have only been shown with concentrations higher than those typically in the ambient air. DATES: Comments. Submit comments on or before March 14, 2003. Public Hearing. If anyone contacts EPA requesting to speak at a public hearing by February 3, 2003, a public hearing will be held on February 12, 2003. ADDRESSES: Comments. Comments may be submitted by mail ( in duplicate, if possible) to EPA Docket Center ( Air Docket), U. S. EPA West ( MD   6102T), Room B   108, 1200 Pennsylvania Avenue, NW, Washington, DC 20460, Attention Docket ID No. OAR   2002   0058. By hand delivery/ courier, comments may be submitted ( in duplicate, if possible) to EPA Docket Center, Room B   108, U. S. EPA West, 1301 Constitution Avenue, NW, Washington, DC 20460, Attention Docket ID No. OAR   2002   0058. Also, comments may be submitted electronically according to the detailed instructions as provided in the SUPPLEMENTARY INFORMATION section. Public Hearing. If a public hearing is held, it will be held at the new EPA facility complex in Research Triangle Park, North Carolina, or an alternate site nearby. Docket. Docket ID No. OAR   2002   0058 contains supporting information used in developing the proposed rule. The docket is located at the U. S. EPA, 1301 Constitution Avenue, NW, Washington, DC 20460 in room B108, and may be inspected from 8: 30 a. m. to 4: 30 p. m., Monday through Friday, excluding legal holidays.

FOR FURTHER INFORMATION 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, e mail: eddinger. jim@ epa. gov.

SUPPLEMENTARY INFORMATION: Regulated Entities. The promulgation of the proposed rule would affect the following North American Industrial Classification System ( NAICS) and Standard Industrial Classification ( SIC) codes.

Category NAICS code SIC code Examples of potentially regulated entities Any industry using a boiler or process heater as defined in the proposed rule. 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. 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 proposed 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. How Can I Get Copies of This Document and Other Related Information?

Docket. The EPA has established an official public docket for this action under Docket ID No. OAR   2002   0058. The official public docket consists of the documents specifically referenced in this action, any public comments VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1661 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules received, and other information related to this action. 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 Air and Radiation Docket in the EPA Docket Center, ( EPA/ DC) EPA West, Room B108, 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 http:// www. epa. gov/ edocket/ to submit or 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. Certain types of information will not be placed in the EPA Dockets. Information claimed as CBI and other information whose disclosure is restricted by statute, which is not included in the official public docket, will not be available for public viewing in EPA's electronic public docket. The EPA's policy is that copyrighted material will not be placed in EPA's electronic public docket but will be available only in printed paper form in the official public docket. To the extent feasible, publicly available docket materials will be made available in EPA's electronic public docket. When a document is selected from the index list in EPA Dockets, the system will identify whether the document is available for viewing in EPA's electronic public docket. Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials through the docket facility identified above. The EPA intends to work towards providing electronic access to all of the publicly available docket materials through EPA's electronic public docket. For public commenters, it is important to note that EPA's policy is that public comments, whether submitted electronically or on paper, will be made available for public viewing in EPA's electronic public docket as EPA receives them and without change, unless the comment contains copyrighted material, CBI, or other information whose disclosure is restricted by statute. When EPA identifies a comment containing copyrighted material, EPA will provide a reference to that material in the version of the comment that is placed in EPA's electronic public docket. The entire printed comment, including the copyrighted material, will be available in the public docket. Public comments submitted on computer disks that are mailed or delivered to the docket will be transferred to EPA's electronic public docket. Public comments that are mailed or delivered to the Docket will be scanned and placed in EPA's electronic public docket. Where practical, physical objects will be photographed, and the photograph will be placed in EPA's electronic public docket along with a brief description written by the docket staff. For additional information about EPA's electronic public docket, visit EPA Dockets online or see 67 FR 38102, May 31, 2002. You may submit comments electronically, by mail, or through hand delivery/ courier. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your comment. Please ensure that your comments are submitted within the specified comment period. Comments received after the close of the comment period will be marked `` late.'' The EPA is not required to consider these late comments. However, late comments may be considered if time permits. Electronically. If you submit an electronic comment as prescribed below, EPA recommends that you include your name, mailing address, and an e mail address or other contact information in the body of your comment. Also include this contact information on the outside of any disk or CD ROM you submit, and in any cover letter accompanying the disk or CD ROM. This ensures that you can be identified as the submitter of the comment and allows EPA to contact you in case EPA cannot read your comment due to technical difficulties or needs further information on the substance of your comment. The EPA's policy is that EPA will not edit your comment, and any identifying or contact information provided in the body of a comment will be included as part of the comment that is placed in the official public docket and made available in EPA's electronic public docket. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Your use of EPA's electronic public docket to submit comments to EPA electronically is EPA's preferred method for receiving comments. Go directly to EPA Dockets at http:// www. epa. gov/ edocket, and follow the online instructions for submitting comments. To access EPA's electronic public docket from the EPA Internet Home Page, select `` Information Sources,'' `` Dockets,'' and `` EPA Dockets.'' Once in the system, select `` search,'' and then key in Docket ID No. OAR   2002   0058. The system is an anonymous access system, which means EPA will not know your identity, e mail address, or other contact information unless you provide it in the body of your comment. Comments may be sent by electronic mail ( e mail) to a and r docket@ epa. gov, Attention Docket ID No. OAR   2002   0058. In contrast to EPA's electronic public docket, EPA's e mail system is not an anonymous access system. If you send an e mail comment directly to the Docket without going through EPA's electronic public docket, EPA's e mail system automatically captures your email address. E mail addresses that are automatically captured by EPA's e mail system are included as part of the comment that is placed in the official public docket and made available in EPA's electronic public docket. You may submit comments on a disk or CD ROM that you mail to the mailing address identified below. These electronic submissions will be accepted in WordPerfect or ASCII file format. Avoid the use of special characters and any form of encryption. By Mail. Send your comments ( in duplicate if possible) to: Air and Radiation Docket and Information Center, U. S. EPA, Mailcode: 6102T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR   2002   0058. The EPA requests a separate copy also be sent to the contact person listed above ( see FOR FURTHER INFORMATION CONTACT). By Hand Delivery or Courier. Deliver your comments to: EPA Docket Center, Room B108, 1301 Constitution Ave., NW., Washington, DC, Attention Docket ID No. OAR   2002   0058. Such deliveries are only accepted during the Docket's VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1662 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules normal hours of operation as identified above. Do not submit information that you consider to be CBI electronically through EPA's electronic public docket or by e mail. Send or deliver information identified as CBI only to the following address: Mr. Jim Eddinger, c/ o OAQPS Document Control Officer ( Room C404   2), U. S. EPA, Research Triangle Park, 27711, Attention Docket ID No. OAR   2002   0058. You may claim information that you submit to EPA as CBI by marking any part or all of that information as CBI ( if you submit CBI on disk or CD ROM, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is CBI). Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. In addition to one complete version of the comment that includes any information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket and EPA's electronic public docket. If you submit the copy that does not contain CBI on disk or CD ROM, mark the outside of the disk or CD ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and EPA's electronic public docket without prior notice. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section. You may find the following suggestions helpful for preparing your comments: 1. Explain your views as clearly as possible. 2. Describe any assumptions that you used. 3. Provide any technical information and/ or data you used that support your views. 4. If you estimate potential burden or costs, explain how you arrived at your estimate. 5. Provide specific examples to illustrate your concerns. 6. Offer alternatives. 7. Make sure to submit your comments by the comment period deadline identified. 8. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your response. It would also be helpful if you provided the name, date, and Federal Register citation related to your comments. Public Hearing. Persons interested in presenting oral testimony or inquiring as to whether a hearing is to be held should contact Ms. Kelly Hayes, Combustion Group, Emission Standards Division ( C439   01), U. S. EPA, Research Triangle Park, North Carolina 27711, telephone ( 919) 541   5578 at least 2 days in advance of the public hearing. Persons interested in attending the public hearing must also call Ms. Kelly Hayes to verify the time, date, and location of the hearing. The public hearing will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. If a public hearing is requested and held, EPA will ask clarifying questions during the oral presentation but will not respond to the presentations or comments. Written statements and supporting information will be considered with equivalent weight as any oral statement and supporting information presented at a public hearing, if held. Outline. The information presented in this preamble is organized as follows:

I. Background Information A. What criteria are used in the development of NESHAP? B. What is the regulatory development background of the source categories in the proposed rule? C. What is the statutory authority for the proposed rule? D. What is the relationship between the proposed rule and other combustion rules? E. What are the health effects of pollutants emitted from industrial/ commercial/ institutional boilers and process heaters? II. Summary of the Proposed Rule A. What source categories and subcategories are affected by the proposed rule? B. What pollutants are emitted? C. What is the affected source? D. Does the proposed rule apply to me? E. What emission limitations and work practice standards must I meet? F. What are the testing and initial compliance requirements? G. What are the continuous compliance requirements? H. What are the notification, recordkeeping and reporting requirements? III. Rationale of the Proposed Rule A. How did EPA determine which pollution sources would be regulated under the proposed rule? B. How did EPA select the format for the proposed rule? C. How did EPA determine the proposed emission limitations for existing units? D. How did EPA determine the MACT floor for existing units? E. How did EPA consider beyond the floor for existing units? F. Should EPA consider different subcategories for solid fuel boilers and process heaters? G. How did EPA determine the proposed emission limitations for new units? H. How did EPA determine the MACT floor for new units? I. How did EPA consider beyond the floor for new units? J. How did EPA determine testing and monitoring requirements for the proposed rule? K. How did EPA determine compliance times for the proposed rule? L. How did EPA determine the required records and reports for the proposed rule? M. How does the proposed rule affect permits? N. What alternative provisions are being considered? IV. Impacts of the Proposed Rule A. What are the air impacts? B. What are the water and solid waste impacts? C. What are the energy impacts? D. What are the control costs? E. Can we achieve the goals of the proposed rule in a less costly manner? F. What are the economic impacts? G. What are the social costs and benefits of the proposed rule? V. Public Participation and Requests for Comment VI. Administrative Requirements A. Executive Order 12866, Regulatory Planning and Review B. Executive Order 13132, Federalism C. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments D. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks E. Unfunded Mandates Reform Act of 1995 F. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 ( SBREFA), 5 U. S. C. 601 et seq. G. Paperwork Reduction Act H. National Technology Transfer and Advancement Act I. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. Background Information A. What Criteria Are Used in the Development of NESHAP? Section 112 of the CAA requires EPA to promulgate regulations for the control of HAP emissions from each source category listed under section 112( c) of the CAA. The statute requires the regulations to reflect the maximum degree of reductions in emissions of HAP that is achievable taking into consideration the cost of achieving emissions reductions, any nonair quality health and environmental impacts, and energy requirements. This level of control is commonly referred to as MACT. The MACT based regulation can be based on the emissions reductions achievable through application of measures, processes, methods, systems, or techniques VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1663 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules including, but not limited to: ( 1) Reducing the volume of, or eliminating emissions of, such pollutants through process changes, substitutions of materials, or other modifications; ( 2) enclosing systems or processes to eliminate emissions; ( 3) collecting, capturing, or treating such pollutants when released from a process, stack, storage or fugitive emission point; ( 4) design, equipment, work practices, or operational standards as provided in subsection 112( h) of the CAA; or ( 5) a combination of the above. For new sources, MACT based standards cannot be less stringent than the emission control achieved in practice by the best controlled similar source. The MACT based standards for existing sources can be less stringent than standards for new sources, but they cannot be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources for categories and subcategories with 30 or more sources, or the best performing 5 sources for categories or subcategories with fewer than 30 sources. In essence, these MACT based standards would ensure that all major sources of toxic air emissions achieve the level of control already being achieved by the better controlled and lower emitting sources in each category. This approach provides assurance to citizens that each major source of toxic air pollution will be required to effectively control its emissions. A major source of HAP emissions is any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit any single HAP at a rate of 10 tons or more per year or any combination of HAP at a rate of 25 tons or more a year. At the same time, this approach provides a level economic playing field, ensuring that facilities that employ cleaner processes and good emission controls are not disadvantaged relative to competitors with poorer controls.

B. What Is the Regulatory Development Background of the Source Categories in the Proposed Rule? In September 1996, EPA chartered the Industrial Combustion Coordinated Rulemaking ( ICCR) advisory committee under the Federal Advisory Committee Act ( FACA). The committee's objective was to develop recommendations for regulations for several combustion source categories under sections 112 and 129 of the CAA. The ICCR advisory committee, known as the Coordinating Committee, formed Source Work Groups for the various combustion types covered under the ICCR. One of the work groups was formed to research issues related to boilers; another was formed to research issues related to process heaters. The Boiler and Process Heater Work Groups submitted recommendations, information, and data analysis results to the Coordinating Committee, which in turn considered them and submitted recommendations and information to EPA. The Committee's recommendations were considered by EPA in developing the proposed rule for boilers and process heaters. The Committee's 2 year charter expired in September 1998. Following the expiration of the ICCR FACA charter, EPA decided to combine boilers with units in the process heater source category covering indirect fired units, and to regulate both under the proposed NESHAP. This was done because indirect fired process heaters and boilers are similar devices, burn similar fuel, have similar emission characteristics, and emissions from each can be controlled using similar control devices or techniques.

C. What Is the Statutory Authority for the Proposed Rule?

Section 112 of the CAA requires that EPA promulgate regulations requiring the control of HAP emissions from major sources and certain area sources. The control of HAP is achieved through promulgation of emission standards under sections 112( d) and ( f) of the CAA and, in appropriate circumstances, work practice standards under section 112( h) of the CAA. An initial list of categories of major and area sources of HAP selected for regulation in accordance with section 112( c) of the CAA was published in the Federal Register on July 16, 1992 ( 57 FR 31576). Industrial boilers, commercial and institutional boilers, and process heaters are three of the listed 174 categories of sources. The listing was based on the Administrator's determination that they may reasonably be anticipated to emit several of the 188 listed HAP in quantities sufficient to designate them as major sources.

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

The proposed 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 today's proposed rule any units that are already or will be subject to regulation under another MACT standard. The commercial and industrial solid waste incinerators ( CISWI) standards ( 40 CFR 60, subparts CCCC and DDDD) regulate commercial and industrial nonhazardous solid waste incinerators. Sources subject to the CISWI rules are exempt from the requirements of the proposed rule. The utility HAP study Report to Congress provides information used to determine whether fossil fuel fired utility boilers should be regulated in a future MACT standard. A fossil fuelfired utility boiler is a fossil fuel fired combustion unit with a heat input greater than 25 megawatts that serves a generator producing electricity for sale. Fossil fuel fired utility boilers are exempt from the proposed rule. Nonfossil fuel fired utility boilers are covered by the proposed rule. The EPA's Office of Solid Waste is in the process of developing MACT based standards for hazardous waste boilers. Boilers burning hazardous waste are not included in the proposed rule. In 1986, EPA had codified new source performance standards ( 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 proposed rule because the proposed rule regulates sources of hazardous air pollutants while the NSPS does not. However, in developing the proposed rule for industrial/ commercial/ 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 proposed 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 proposed rule refining kettles subject to the secondary lead MACT rule ( 40 CFR 63, subpart X). This is one combustion unit meeting the definition of a process heater, that we are specifically aware of, that is covered by another MACT standard. Therefore, we are requesting comments on other process heaters that are already or will be subject to regulation under another MACT standard.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1664 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules E. What Are the Health Effects of Pollutants Emitted From Industrial/ Commercial/ Institutional Boilers and Process Heaters?

Today's proposed 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 hydrogen chloride emissions represent the predominant HAP emitted by industrial boilers, accounting for 59 percent of the total HAP emissions. Industrial boilers and process heaters also emit lesser amounts of hydrogen fluoride, accounting for about 5 percent of total HAP emissions, and metals ( arsenic, cadmium, chromium, mercury, manganese, nickel, and lead), accounting for about 4 percent of total HAP emissions. 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 two of the HAP as human carcinogens and three 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, today's proposed rule would reduce emissions and subsequent exposures.

1. 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.

2. Cadmium The acute ( short term) effects of cadmium inhalation in humans consist mainly of effects on the lung, such as pulmonary irritation. Chronic ( longterm 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 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.

3. 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 ( longterm 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 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. 4. 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, 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.

5. 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.

6. 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 ( short term) exposure to high levels of lead in humans. Chronic ( longterm 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 VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1665 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules exposure by the oral route. The EPA has classified lead as a Group B2, probable human carcinogen.

7. 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. 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 lethargy, tremors, a masklike 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.

8. 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 ( longterm 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. 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.

9. 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 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 Proposed Rule A. What Source Categories and Subcategories Are Affected by the Proposed Rule?

The proposed rule affects industrial boilers, institutional and commercial boilers, and process heaters. In the proposed rule process heaters are defined as units in which the combustion gases do not directly come into contact with process gases in the combustion chamber ( e. g., indirect fired). 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. Combustion units are not subject to the proposed rule simply by virtue of having a waste heat boiler. A waste heat boiler ( or heat recovery steam generator) is a device that recovers normally unused energy and converts it to usable heat. 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 today's proposed rule. A hot water heater is a closed vessel in which water is heated by combustion of gaseous 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.

B. What Pollutants Are Emitted? Boilers and process heaters emit PM, volatile organic compounds, and hazardous air pollutants, depending on the material burned. Solid and liquid fuel fired units emit metals, halogenated compounds and organic compounds. Gas fuel fired units emit mostly organic compounds.

C. What Is the Affected Source? The affected source is each individual industrial, commercial, or institutional boiler or process heater located at a major facility. The affected source does not include units that are municipal waste combustors ( 40 CFR part 60, subparts AAAA, BBBB, Eb or Cb), medical waste incinerators ( 40 CFR part 60, subpart Ce and Ec), fossil fuel fired electric utility steam generating units, commercial and industrial solid waste incineration units ( 40 CFR part 60, subparts CCCC or DDDD), recovery boilers or furnaces ( 40 CFR part 63, subpart MM), ethylene cracking furnaces ( 40 CRF part 63, subpart YY), or hazardous waste combustion units required to have a permit under section 3005 of the Solid Waste Disposal Act or are subject to 40 CFR part 63, subpart EEE.

D. Does the Proposed Rule Apply to Me? The proposed rule applies to you if you own or operate a boiler or process heater at a major source meeting the requirements discussed previously in this preamble. A major source of HAP emissions is any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit any single HAP at a rate of 10 tons or more per year or any combination of HAP at a rate of 25 tons or more a year.

E. What Emission Limitations and Work Practice Standards Must I Meet? 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 VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1666 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules watertube boilers and process heaters with heat input capacities greater than 10 million British thermal units per hour ( MMBtu/ hr). Small units are any firetube boilers or any boiler and process heater with heat input capacities less than or equal to 10 MMBtu/ hr. Limited use units are those large units with capacity utilizations less than or equal to 10 percent as required in a federally enforceable permit. If your new or existing boiler or process heater is permitted to burn a solid fuel ( either as a primary fuel or a backup fuel), or any combination of solid fuel with liquid or gaseous fuel, the unit is in one of the solid subcategories. If your new or existing boiler or process heater burns a liquid fuel, or a liquid fuel in combination with a gaseous fuel, the unit is in one of the liquid subcategories. If your new or existing boiler or process heater burns a gaseous fuel only, the unit is in the gas subcategory.

TABLE 1.   EMISSION LIMITS AND WORK PRACTICE STANDARDS FOR BOILERS AND PROCESS HEATERS [ Pounds per million British thermal units]

Source Subcategory Particulate matter ( PM) or Total selected metals Hydrogen chloride ( HCl) Mercury ( Hg) Carbon Monoxide ( CO)( ppm@ 3% oxygen)

New Boiler, or Process Heater. Solid Fuel, Large Unit 0.026 or 0.0001 0.02 0.000003 400 Solid Fuel, Small Unit 0.026 or 0.0001 0.02 0.000003 ..................................... Solid Fuel, Limited Use. 0.026 or 0.0001 0.02 0.000003 400 Liquid Fuel, Large Unit. 0.03 ........ ...................... 0.0005 ...................... 400 Liquid Fuel, Small Unit 0.03 ........ 0.0009 ...................... ...................... Liquid Fuel, Limited Use. 0.03 ........ ...................... 0.0009 ...................... 400 Gaseous Fuel Large Unit. ...................... ........ ...................... ...................... ...................... 400 Gaseous Fuel Small Unit. ...................... ........ ...................... ......................

Gaseous Fuel Limited Use. ...................... ........ ...................... ...................... ...................... 400 Existing Boiler or Process Heater. Solid Fuel, Large Unit 0.07 or 0.001 0.09 0.000007 .....................................

Solid Fuel, Small Unit ...................... ........ ...................... ...................... ...................... ..................................... Solid Fuel, Limited Used. 0.2 or 0.001 ...................... ...................... .....................................

Liquid Fuel, Large Unit. ...................... ........ ...................... ...................... ...................... .....................................

Liquid Fuel, Small Unit ...................... ........ ...................... ...................... ...................... ..................................... Liquid Fuel, Limited Use. ...................... ........ ...................... ...................... ...................... .....................................

Gaseous Fuel ............ ...................... ........ ...................... ...................... ...................... .....................................

For solid fuel fired boilers or process heaters, we are proposing to allow sources to choose one of two emission limit options: ( 1) Existing and new affected sources may choose to limit PM emissions to the level listed in Table 1 of this preamble or ( 2) existing and new affected sources may choose to limit total selected metals emissions to the level listed in Table 1 of this preamble. If you do not use an add on control or use an add on control other than a wet scrubber, you must maintain opacity level to less than or equal to the level established during the compliance test for mercury and PM or total selected metals, and maintain the fuel chlorine content to less than or equal to the operating level established during the HCl compliance test. If you use a wet scrubber, you must maintain the minimum pH, pressure drop and liquid flow rate above the operating levels established during the performance tests. If you use a dry scrubber, you must maintain opacity level and the minimum sorbent injection rate established during the performance test. If you use an electrostatic precipitator ( ESP) in combination with a wet scrubber and cannot monitor the opacity, you must maintain the average secondary current and voltage or total power input established during the performance test. There is an alternative compliance procedure and operating limit for meeting the total selected metals emission limit option or the mercury emission limit option. If you have no control or do not want to take credit of metals reductions with your existing control device, and can show that total metals in the fuel would be less than the metals emission level, then you can monitor the metals fuel analysis to meet the metals emissions limitations. Similarly, if you do not have an emission control device or you otherwise would rather comply by limiting the mercury input at your facility, and can show that mercury in the fuel would be less than the mercury emission level, then you can monitor the mercury fuel analysis to meet the mercury emission limitations. If your unit is a new source in the large or limited use subcategories, it must meet a carbon monoxide ( CO) emission limit of 400 parts per million corrected to 3 percent oxygen. If your new or existing source is controlled with a fabric filter, then you must install a bag leak detection system such that the bag detection system alarm does not sound more than 5 percent of the operating time during a 6 month period.

F. What Are the Testing and Initial Compliance Requirements?

As the owner or operator of a new or existing boiler or process heater, you must conduct performance tests to demonstrate compliance with any applicable emission limits. The applicable emission limits and,

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1667 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules therefore, the required performance tests are different depending on the subcategory classification of the unit. Existing units in the small solid fuel subcategory and in any of the liquid or gaseous fuel subcategories do not have applicable emission limits and, therefore, are not required to conduct stack tests. Other units are required to conduct the following compliance tests 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 then conduct initial and annual stack tests to determine compliance with the total selected metals emission limit using EPA Method 29 in appendix A to part 60 of this chapter. ( 3) Conduct initial and annual stack tests to determine compliance with the mercury emission limits using EPA method 29 in appendix A to part 60 of this chapter ( for boilers with rated heat input capacities of less than 250 MMBtu per hour) or the draft ASTM Z65907, `` Standard Method for Both Speciated and Elemental Mercury Determination,'' ( for boilers with rated heat input capacities of greater than 250 MMBtu per hour). ( 4) Conduct initial and annual stack tests to determine compliance with the HCl emission limits using EPA Method 26 in appendix A to part 60 of this chapter ( for boilers without wet scrubbers) or EPA Method 26A in appendix A to part 60 of this chapter ( for boilers with wet scrubbers). ( 5) 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. ( 6) For new units in any of the liquid fuel subcategories that do not burn residual oil, instead of conducting an initial 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. 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 1 hour test run over the 3 hour performance test. The minimum or maximum of the three average values ( depending on the parameter measured) for each applicable parameter is established as a 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 the following units: ( 1) For boilers and process heaters without wet scrubbers that must comply with the mercury emission limit and either a PM emission limit or a total selected metals emission limit, you must measure opacity during the performance test and calculate the 6 minute averages. The maximum 1 hour average measured establishes your sitespecific opacity operating limit. Or, if the unit is controlled with a fabric filter, instead of setting an opacity operating limit, the fabric filter must be operated such that the required 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 measure the average chlorine content level in the input fuel( s) during the HCl performance test. This is your maximum chlorine input operating limit. If you plan to burn a new fuel, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must recalculate the maximum chlorine input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating the chlorine input exceeds the average chlorine content level established during the initial test then you must conduct a new performance test to demonstrate compliance with the HCl emission limit. ( 3) For boilers and process heaters with wet scrubbers that must comply with a mercury, PM and/ or an HCl emission limit, you must measure pressure drop and liquid flow rate of the scrubber during the performance test, and calculate the average value for each test run. The minimum test run average establishes your site specific pressure drop and liquid flow rate operating levels. If different average parameter levels are measured during the mercury, PM ( or metals) and HCl tests, the highest of the average values becomes 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 a PM or mercury emission limit, you must measure opacity during the PM performance test as described above. If you must also comply with an HCl emission limit, you must measure the sorbent injection rate during the performance test for HCl, and calculate the average for each test run. The minimum test run average established during the performance test is your sitespecific 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 emission limit and/ or an HCl emission limit, you must measure the pH, pressure drop, and liquid flow rate of the wet scrubber during the performance test and calculate the average value for each test run. The minimum test run average establishes your site specific pH, pressure drop, and liquid flow rate 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 ESP in combination with wet scrubbers that must comply with a mercury, PM 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 current of the ESP collection plates 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 flow rate operating limit for the wet scrubber and the minimum voltage and current operating limits for the ESP plates. ( 7) For boilers that choose to comply with the alternative total selected metals emission limit instead of PM and have either no add on controls or add on controls for which you do not want to take credit for any emission reduction of metals, you must measure the total selected metals content of the inlet fuel that was burned during the total selected metals performance test. This value is your maximum fuel inlet metals content operating limit. If you plan to burn a new fuel, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1668 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules recalculate the maximum metals input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating the metals input exceeds the average metals content level established during the initial test then you must conduct a new performance test to demonstrate compliance with the alternate total selected metals emission limit. ( 8) For boilers that choose to demonstrate compliance with the mercury emission limit on the basis of fuel analysis and have no add on controls or add on controls for which you do not want to take credit for any emission reduction of mercury, you must measure the mercury content of the inlet fuel that was burned during the mercury performance test. This value is your maximum fuel inlet mercury operating limit. If you plan to burn a new fuel, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must recalculate the maximum mercury input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating the mercury input exceeds the average mercury content level established during the initial test then you must conduct a new performance test to demonstrate compliance with the mercury emission limit. ( 9) For new boilers and process heaters in any of the large or limited use subcategories, you must monitor CO during the performance tests for PM ( or metals) and/ or HCl to demonstrate that average CO emissions are at or below an exhaust concentration of 400 parts per million ( ppm) by volume on a dry basis corrected to 3 percent oxygen.

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 following performance tests: ( 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 3 hour block average at or below your site specific opacity operating limit. Or, if the unit is controlled with a fabric filter, instead of continuous monitoring opacity, the fabric filter must 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 daily records of fuel use that demonstrate that you have burned no new fuels such that you have maintained the fuel chlorine content level at or below your site specific maximum chlorine input operating limit. If you plan to burn a new fuel, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must recalculate the maximum chlorine input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating the chlorine input exceeds the average chlorine 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 and/ or an HCl emission limit, you must monitor pressure drop and liquid flow rate of the scrubber and maintain the 3 hour block averages at or above the operating limits established during the performance test. You must monitor the pH of the scrubber and maintain the 3 hour block average at or above the operating limit established during the performance test to demonstrate continuous compliance with the HCl emission limits. ( 4) For boilers and process heaters with dry scrubbers that must comply with a PM or mercury emission limit, you must monitor and maintain opacity levels as described above to demonstrate continuous compliance with the PM emission limits. If you must also comply with an HCl emission limit, you must continuously monitor the sorbent injection rate and maintain it at or above the operating limits established during the HCl performance test. ( 5) For boilers and process heaters with fabric filters in combination with wet scrubbers, you must monitor the pH, pressure drop, and liquid flow rate of the wet scrubber and maintain the levels at or above the operating limits established during the HCl performance test. You must also maintain the operation of the fabric filter such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during any 6 month period. ( 6) For boilers and process heaters with ESP in combination with wet scrubbers that must comply with a mercury, PM and/ or an HCl emission limit, you must monitor the pH, pressure drop, and liquid flow rate of the wet scrubber and maintain the 3 hour block averages at or above the operating limits established during the HCl performance test and you must monitor the voltage and current of the ESP collection plates 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 that choose to comply with the alternative total selected metals limit instead of PM emission limit based on fuel analysis rather than on performance testing, you must maintain daily fuel records that demonstrate that you burned no new fuels or fuels from a new supplier 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, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must recalculate the maximum metals input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating 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 that choose to comply with the mercury emission limit based on fuel analysis rather than on performance testing, you must maintain daily fuel records that demonstrate that you burned no new fuels or fuels from a new supplier such that the total selected mercury content of the inlet fuel was maintained at or below your maximum fuel inlet metals content operating limit set during the mercury performance test. If you plan to burn a new fuel, a fuel from a new mixture, or a fuel from a new supplier than what was burned during the initial performance test, then you must recalculate the maximum mercury input anticipated from the new fuels based on supplier data or own fuel analysis. If the results of recalculating 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 new boilers and process heaters in any of the large or limited use subcategories, you must continuously monitor CO and maintain the average CO emissions at or below 400 ppm by VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1669 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules volume on a dry basis corrected to 3 percent oxygen to demonstrate compliance with the work practice standards. 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. If a control device other than the ones specified in this section is used to comply with the proposed rule, you must establish site specific operating limits and establish appropriate continuous monitoring requirements, as approved by the Administrator.

H. What Are the Notification, Recordkeeping and Reporting Requirements?

You must keep the following records: ( 1) All reports and notifications submitted to comply with the proposed rule. ( 2) Continuous monitoring data as required in the proposed rule. ( 3) Each instance in which you did not meet each emission limit and each operating limit, including periods of startup, shutdown, and malfunction ( i. e., deviations from the proposed rule). ( 4) Daily hours of operation by each source. ( 5) Total fuel use by each affected source electing to comply with an emission limit based on fuel analysis for each 30 day period along with a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel. ( 6) Calculations and supporting information of chlorine fuel input, as required in the proposed rule. ( 7) Calculations and supporting information of total selected metals and mercury fuel input, as required in the proposed rule, if applicable. ( 8) A signed statement, as required in the proposed rule, indicating you burned no new fuels, no fuels from a new supplier, or no new fuel mixture or the recalculation of chlorine input to demonstrate that the new fuel, new mixture, new source still meets chlorine fuel input levels. ( 9) A signed statement, as required in the proposed rule, indicating you burned no new fuels, no fuels from a new supplier, or no new fuel mixture or the recalculation of total selected metals fuel input to demonstrate that the new fuel, new fuel mixture, or fuel from a new source still meets the total selected metals fuel input levels. ( 10) A signed statement, as required in the proposed rule, indicating you burned no new fuels, no fuels from a new supplier, or no new fuel mixture or the recalculation of mercury fuel input to demonstrate that the new fuel, new fuel mixture, or fuel from a new source still meets the mercury fuel input levels. ( 11) 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 proposed rule. ( 12) A copy of any Federally enforceable permit that limits the annual capacity factor of the source to less than or equal to 10 percent. ( 13) A copy of your site specific startup, shutdown, and malfunction plan. ( 14) A copy of your site specific monitoring plan developed for the proposed rule, 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 60 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) Compliance reports semi annually.

III. Rationale of the Proposed Rule A. How Did EPA Determine Which Pollution Sources Would Be Regulated Under the Proposed Rule?

The proposed 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 today's proposed rule any units that are already or will be subject to regulation under another MACT standard. A list of combustion units excluded from the proposed rule is discussed previously in this preamble. The CAA specifically requires that fossil fuel fired steam generating units of more than 25 megawatts that produce electricity for sale ( i. e., utility boilers) be reviewed separately by EPA. Consequently, the proposed rule does not regulate fossil fuel fired utility boilers greater than 25 megawatts, but does regulate fossil fuelfired units less than 25 megawatts and all nonfossil fuel fired utility boilers. The proposed rule also does not regulate emissions from combustion units with waste heat boilers, unless such units would otherwise be subject to the emission limitations in today's proposed rule. For example, emissions from any commercial or industrial solid waste incinerator ( CISWI) or other incinerator unit that has a waste heat boiler will be covered by regulations promulgated under section 129 of the CAA. During the ICCR FACA, the scope of the process heater source category was limited to regulate only indirect fired units. Direct fired units are covered in other MACT standards or rulemakings pertaining to industrial process operations. For example, lime kilns are covered by the Pulp and Paper NESHAP ( 40 CFR part 63, subpart S). Indirectfired process heaters are similar to boilers in fuel use, emissions, and applicable controls, and, therefore, it is appropriate for EPA to combine this category of units with industrial, commercial and institutional boilers for purposes of developing emission standards. Also during the ICCR FACA process, EPA received comments from stakeholders regarding the potential for the proposed rule to regulate small hot water heaters located at major source facilities. Many industrial facilities have office buildings located onsite which use hot water heaters. Such hot water heaters, by their design and operation, could be considered boilers. However, since hot water heaters generally are small and use natural gas as fuel, their emissions are negligible compared to the emissions from the industrial operations that make such facilities major sources, and compared to boilers that are used for industrial, commercial, or institutional purposes. Moreover, such hot water heaters are more appropriately described as residentialtype boilers, not industrial, commercial or institutional boilers. Consequently, we are including a definition of hot water heaters that includes fuel, size, pressure and temperature limitations that we believe are appropriate to VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1670 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules distinguish between residential type units and industrial, commercial or institutional units. Therefore, the proposed rule regulates industrial, commercial, and institutional boilers and process heaters located at major source facilities but excludes residential type hot water heaters. The Clean Air Act allows EPA to divide source categories into subcategories when differences between given types of units lead to corresponding differences in the nature of emissions and the technical feasibility of applying emission control techniques. The design, operating, and emissions information that EPA has reviewed indicates the need to subcategorize boilers and process heaters based on the physical state of the fuel burned, i. e., solid, liquid, or gas. Data indicate that there are significant design and operational differences between units that burn solid, liquid and gaseous fuels. Boiler systems are designed for specific fuel types and will encounter problems if a fuel with characteristics other than those originally specified is fired. While many boilers in the population database are indicated to cofire liquids or gases with solid fuels, in actuality most of these commonly use fuel oil or natural gas as a startup fuel only. Other co fired units are specifically designed to fire combinations of solids, liquids, and gases. Changes to the fuel type ( solid, liquid, or gas) would require extensive changes to the fuel handling and feeding system ( e. g., a stoker using wood as fuel would need to be redesigned to handle fuel oil or gaseous fuel). Additionally, the burners and combustion chamber would need to be redesigned and modified to handle different fuel types and account for increases or decreases in the fuel volume and shape. In some cases, the changes may reduce the capacity and efficiency of the boiler or process heater. An additional effect of these changes would be extensive retrofit costs. Emissions from boilers and process heaters burning solids, liquids, and gaseous fuels will also differ. Boilers and process heaters emit a number of different types of HAP emissions. In general, their formation is dependent upon the composition of the fuel. The combustion quality and temperature may also play an important role. The fuel dependent HAP emissions from boilers and process heaters are metals, including mercury, and acid gases. These fuel dependent HAP emissions generally can be controlled by either changing the fuel property before combustion or by removing the HAP from the flue gas after combustion. Organic HAP, on the other hand, are formed from incomplete combustion and are much less influenced by the characteristics of the fuel being burned. The degree of combustion may be greatly influenced by three general factors: time, turbulence, and temperature. These factors are a function of the design of the boiler or process heater which is dependent in part on the type of fuel being burned. Solid fuel fired units will emit larger amounts of PM and metals depending on the solid fuel burned. Liquid and gaseous fuel fired units generally emit larger amounts of organic HAP. Because these different types of units have different emission characteristics which may influence the feasibility of effectiveness of emission control, they should be regulated separately ( i. e., subcategorized). Thus, these categories appropriately identify distinctly different types of units subject to regulation. Accordingly, EPA decided to subcategorize boilers and process heaters into solid, liquid and gaseous fuel subcategories in order to account for these differences in emissions and applicable controls. The solid fuel subcategory includes boilers and process heaters burning any amount of solid fuel ( including units burning a combination of solid fuel and liquid or gaseous fuel). The gaseous fuel subcategory includes units only burning gaseous fuel. The liquid fuel subcategory includes all remaining boilers and process heaters. Small boilers and process heaters were also identified as a subcategory. These small units typically are package units having capacities less than 10 MMBtu/ hr heat input or use a combustor design ( i. e., firetube or cast iron) which is not common in large units. Large boilers generally are fielderected using the watertube combustor design with capacities above 10 MMBtu/ hr. As discussed above, 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 vast majority of these small units use natural gas as fuel. Additionally, most existing State and Federal regulations for boilers and process heaters do not regulate units with a heat input capacity of less than 10 MMBtu/ hr, due to their low emissions. Consequently, we decided to further subcategorize boilers and process heaters within each fuel category by creating subcategories for large units ( watertube boilers and process heaters greater than 10 MMBtu/ hr capacity) and small units ( all firetube boilers and boilers and process heaters of any other type with less than or equal to 10 MMBtu/ hr capacity). 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. Back up or emergency units only operate if another boiler that is the regular source of energy or steam is not operating ( for example due to a shutdown for maintenance and repair). Peaking units operate only during peak energy use periods, typically in the summer months. 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. While these are potential sources of emissions, and it is appropriate for EPA to address them in the proposal, the Agency believes that their use and operation are different compared to typical industrial, commercial, and institutional boilers. Consequently, we decided that such limited use units should have their own subcategory. Therefore, the proposed rule has subcategories for boilers and process heaters having a capacity utilization of less than 10 percent. In summary, we have identified nine subcategories of boilers and process heaters located at major sources: ( 1) Large solid fuel fired boilers and process heaters ( sizes greater than 10 MMBtu/ hr), ( 2) large liquid fuel fired boilers and process heaters ( sizes greater than 10 MMBtu/ hr), ( 3) large gaseous fuel fired boilers and process heaters ( sizes greater than 10 MMBtu/ hr), ( 4) small solid fuel fired boilers and process heaters ( firetubes or any unit less than or equal to 10 MMBtu/ hr), ( 5) small liquid fuel fired boilers and process heaters ( sizes less than or equal to 10 MMBtu/ hr), ( 6) small gaseous fuelfired boilers and process heaters ( sizes less than or equal to 10 MMBtu/ hr), ( 7) limited use solid fuel fired boilers and process heaters ( large units with capacity utilization less than or equal to 10 percent), ( 8) limited use liquid fuelfired boilers and process heaters ( large units with capacity utilization less than or equal to 10 percent), and ( 9) limited use gaseous fuel fired boilers and process heaters ( large units with capacity utilization less than or equal to 10 percent).

B. How Did EPA Select the Format for the Proposed Rule? The proposed rule includes emission limits for PM, selected metallic HAP,

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1671 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules mercury, and HCl for six of the nine subcategories. The selection of emission limitations as the format for the proposed rule provides flexibility for the regulated community by allowing a regulated source to choose any control technology or technique to meet the emission limits, rather than requiring each unit to use a prescribed method that may not be appropriate in each case. This is particularly relevant for boilers and process heaters, because they can burn many different types of fuels with greatly varying emission profiles and owners need flexibility to use the control devices that are best for their particular emission characteristics. The EPA selected an outlet emission rate format because outlet data are available for boilers and process heaters that use the control techniques that provide the greatest reduction in HAP emissions. The individual limits reflect the achievable performance of boilers and process heaters using the appropriate controls for each type of emissions. The EPA is proposing numerical emission rate limits as a mass of pollutant emitted per heat energy input to the boiler or process heater. The most typical units for the limits are pounds of pollutant emitted per million Btu of heat input. The mass per heat input units are consistent with other Federal and many State boiler regulations and allows easy comparison between such requirements. Additionally, the proposed rule contains an option to monitor inlet chlorine, mercury, and metals content in the fuel to meet outlet emission rate limits. This option can only be done on a mass basis. The EPA considered percent reduction and outlet concentration as alternative formats for the pollutants regulated. However, an outlet concentration limit could not be accurately correlated to the chlorine content in the inlet fuel. An outlet concentration limit would also not be consistent with the format of other regulations. Affected units would already be complying with a mass per heat input limit, so EPA did not believe that a concentration limit would provide any additional benefits or flexibility. Additionally, data were insufficient to determine percent reductions that control devices achieve. Furthermore, a percent reduction requirement would limit the flexibility of the regulated community by requiring the use of a control device. Therefore, neither alternative was selected as the format for the proposed rule. The EPA requests comments on the appropriateness of percent reduction requirements and outlet concentration limit requirements, and any data upon which those requirements could be based. Boilers and process heaters can emit a wide variety of compounds, depending on the fuel burned. The boiler emissions test database lists over 100 possible HAP. Because of the large number of HAP potentially present and the disparity in the quantity and quality of the emissions information available, EPA grouped the HAP into four common categories: mercury, nonmercury 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. For example, non mercury metallic HAP can be controlled with PM controls. The EPA chose to look at mercury separately from other metallic HAP due to its different chemical characteristics and applicable controls. Next, EPA identified compounds that could be used as surrogates for all the compounds in each pollutant category. For the non mercury metallic HAP, EPA 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 that includes some amount and combination of metallic HAP. The use of PM as a surrogate will also eliminate the cost of performance testing to comply with numerous standards for individual metals. However, the Agency is 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. Therefore, the Agency is also proposing an alternative metals emission limit. A source may choose to comply with the alternative metals emissions limit instead of the PM limit to meet the proposed rule. The metals emission limit is for the sum of emissions of eight selected metals: arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium. The eight represent the most common and the largest emitted metallic HAP from boilers and process heaters. For inorganic HAP, EPA chose to use HCl as a surrogate. The emissions test information available to EPA 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, EPA 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 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. In addition to meeting emission limits, today's proposal would also require sources to establish control device operating parameter limits and continuously monitor control device operating parameters. Each source would establish site specific values for the relevant parameters during performance tests, and use the parameter values to demonstrate compliance with the emission limits. We selected different operating parameters for each type of potential control device. The parameters were selected because they are good indicators of proper control device operation and performance, are consistent with other standards, and are feasible to monitor. The operating limits reasonably assure that the control devices continue to operate in a manner that will achieve the same level of control as during the performance test.

C. How Did EPA Determine the Proposed Emission Limitations for Existing Units? All standards established pursuant to section 112( d)( 2) of the CAA must reflect MACT, the maximum degree of reduction in emissions of air pollutants that the Administrator, taking into consideration the cost of achieving such VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1672 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules emissions reductions, and any nonair quality health and environmental impacts and energy requirements, determined is achievable for each category. For existing sources, MACT cannot be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources for categories and subcategories with 30 or more sources. This requirement constitutes the MACT floor for existing boilers and process heaters. However, EPA may not consider costs or other impacts in determining the MACT floor. The EPA must consider cost, nonair quality health and environmental impacts, and energy requirements in connection with any standards that are more stringent than the MACT floor ( beyond the floor controls).

D. How Did EPA Determine the MACT Floor for Existing Units? 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. Using such an approach, EPA might calculate the MACT floor for a category of sources by ranking the emission test results from units within the category from lowest to highest, and then taking the numerical average of the test results from the best performing ( lowest emitting) 12 percent of sources. However, after review of the available HAP emission test data, we determined that it was inappropriate to use this MACT floor approach to establish emission limits for boilers and process heaters. The main problem with using only the HAP emissions data is that, based on the test data alone, uncontrolled units ( or units with low efficiency add on controls) were frequently identified as being among the best performing 12 percent of sources in a subcategory, while many units with high efficiency controls were not. However, these uncontrolled or poorly controlled units are not truly among the best controlled units in the category. Rather, the emissions from these units are relatively low because of particular characteristics of the fuel that they burn, that cannot reasonably be replicated by other units in the category or subcategory. In fact, we expect just this kind of variability in emission rates given the variety of fuel types included within each subcategory of boilers and process heaters. 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. Some fuels even have pollutant concentration levels below the detection limit of the applicable analytical test method. 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 be unachievable for many existing units, even those that employ the most effective available emission control technology. For example, an uncontrolled boiler burning wood may have lower emissions of mercury than a well controlled boiler burning coal. In fact, coal burning boilers may never be able to achieve the mercury HAP level of the wood fired unit, no matter what add on controls are used. In this instance, establishing a MACT standard based on emission data alone would force the coal units to switch to different fuels to achieve the MACT limits. As discussed later in this section, fuel switching is not an appropriate or available control option for identifying the MACT floors for boilers and process heaters. Another problem with using only emissions data is that there is no HAP emissions information available to the Agency for some of the subcategories. This is consistent with the fact that units in these source categories have not historically been required to test for HAP emissions. We also considered using HAP emission limits contained in State regulations and permits as a surrogate for actual emission data in order to identify the emissions levels from the best performing units in the category for purposes of establishing MACT standards. However, we found no State regulations or State permits that specifically limit HAP emissions from these sources. Consequently, we concluded that the most appropriate approach for determining MACT floors for boilers and process heaters was 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 considered first whether fuel switching would be an appropriate control option for sources in each subcategory. We considered the feasibility of fuel switching to other fuels used in the subcategory and to fuels from other subcategories. This consideration included determining whether switching fuels would achieve lower HAP emissions. A second consideration was whether fuel switching could be technically achieved by boilers and process heaters in the subcategory considering the existing design of boilers and process heaters. We also considered the availability of various types of fuel. After considering these factors, we determined that fuel switching was not an appropriate control technology for purposes of determining the MACT floor level of control for any subcategory. This decision was based on the overall effect of fuel switching on HAP emissions, technical and design considerations discussed previously in this preamble, and concerns about fuel availability. Based on the data available in the emissions database, we determined that while fuel switching from solid fuels to gaseous or liquid fuels would decrease PM and some metals emissions, emissions of some organic HAP would increase, resulting in uncertain benefits. This determination is discussed in the memorandum `` Development of Fuel Switching Costs and Emission Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants'' located in the docket. We believe that it is inappropriate in a MACT rulemaking to consider as MACT a control option that potentially will decrease emissions of one HAP while increasing emissions of another HAP. In order to adopt such a strategy, EPA would need to assess the relative risk associated with each HAP emitted, and determine whether requiring the control in question would result in overall lower risk. Such an analysis is not appropriate at this stage in the regulatory process. A similar determination was made when considering fuel switching to cleaner fuels within a subcategory. For example, the term `` clean coal'' refers to coal that is lower in sulfur content and not necessarily lower in HAP content. Data gathered by EPA also indicates that within specific coal types HAP content can vary significantly. Switching to a low sulfur coal may actually increase emissions of some HAP. Therefore, it is not appropriate for EPA to include fuel switching to a low sulfur coal as part of the MACT standards for boilers and process heaters. Fuel switching from coal to biomass would result in similar VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1673 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules impacts on HAP emissions. While this would reduce metallic HAP emissions, it would likely increase emissions of organics based on information in the emissions database. Another factor considered was the availability of alternative fuel types. Natural gas pipelines are not available in all regions of the U. S., and natural gas is simply not available as a fuel for many industrial, commercial, and institutional boilers and process heaters. Moreover, even where pipelines provide access to natural gas, supplies of natural gas may not be adequate. For example, it is common practice in cities during winter months ( or periods of peak demand) to prioritize natural gas usage for residential areas before industrial usage. Requiring EPA regulated combustion units to switch to natural gas would place an even greater strain on natural gas resources. Consequently, even where pipelines exist, some units would not be able to run at normal or full capacity during these times if shortages were to occur. Therefore, under any circumstances, there would be some units that could not comply with a requirement to switch to natural gas. Similar problems for fuel switching to biomass could arise. Existing sources burning biomass generally are combusting a recovered material from the manufacturing or agriculture process. Industrial, commercial, and institutional facilities that are not associated with the wood products industry or agriculture may not have access to a sufficient supply of biomass materials to replace their fossil fuel. As discussed previously in this preamble, there is a significant concern that switching fuels would be infeasible for sources designed and operated to burn specific fuel types. Changes in the type of fuel burned by a boiler or process heater ( solid, liquid, or gas) may require extensive changes to the fuel handling and feeding system ( e. g., a stoker using wood as fuel would need to be redesigned to handle fuel oil or gaseous fuel). Additionally, burners and combustion chamber designs are generally not capable of handling different fuel types, and generally cannot accommodate increases or decreases in the fuel volume and shape. Design changes to allow different fuel use, in some cases, may reduce the capacity and efficiency of the boiler or process heater. Reduced efficiency may result in less complete combustion and, thus, an increase in organic HAP emissions. For the reasons discussed above, we decided that fuel switching to cleaner solid fuels or to liquid or gaseous fuels is not an appropriate criteria for identifying the MACT floor level of control for units in the boilers and process heaters category. 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 primarily dependent upon the composition of the fuel. Fuel dependent HAP are metals, including mercury, and acid gases. Fuel dependent HAP are typically controlled by removing them from the flue gas after combustion. Therefore, they are not affected by the operation of the boiler or process heater. Consequently, process changes would be ineffective in reducing these fuel related HAP emissions. On the other hand, organic HAP can be formed from incomplete combustion of the fuel. Combustion is defined as the rapid chemical combination of oxygen with the combustible elements of a fuel. The objective of good combustion is to release all the energy in the fuel while minimizing losses from combustion imperfections and excess air. The combination of the fuel with the oxygen requires temperature ( high enough to ignite the fuel constituents), mixing or turbulence ( to provide intimate oxygenfuel contact), and sufficient time ( to complete the process), sometimes referred to the three Ts of combustion. Good combustion practice ( GCP), in terms of boilers and process heaters, could be defined as the system design and work practices expected to minimize organic HAP emissions. The GCP control strategy could include a number of combustion conditions and work practices which are applied collectively to achieve this goal. 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. Therefore, we considered whether existing CO monitoring requirements and emission limits might be used to establish good combustion practice standards for boilers and process heaters. ( As discussed previously in this preamble, CO is also a surrogate for organic HAP emissions in the proposed rule.) The population databases did not contain information regarding whether existing units monitored CO emissions. Therefore, we reviewed State regulations applicable to boilers and process heaters, and then for each subcategory we matched the applicability of State CO monitoring requirements or emission limits with information on the locations and characteristics of the boilers and process heaters in the population database. Ultimately, we found that very few units ( less than 6 percent) in any subcategory were subject to CO monitoring requirements or 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. Consequently, EPA was unable to identify any uniform requirements or set of work practices that would meaningfully reflect the use of good combustion practices, or that could be meaningfully implemented across any subcategory of boilers and process heaters. Therefore, EPA is not establishing combustion practice requirements 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 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. We request comment, and emissions information, regarding whether there are any uniform GCP practices that would be appropriate for minimizing organic HAP emissions from any subcategory of VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1674 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules industrial, commercial, and institutional boilers and process heaters. As a result of the preceding evaluation of the feasibility of establishing emission limits based on control techniques such as fuel switching and good combustion practices, we concluded that add on control technology should be the primary factor for purposes of identifying the best controlled units within each subcategory of boilers and process heaters. In order to determine the MACT floor based primarily on addon control technologies, we first examined the population database of existing sources. Units not meeting the definition of an industrial, commercial, or institutional boiler or process heater, and units located at area sources were removed from the database. The remaining units were divided first into three subcategories based on fuel state: gaseous fuel fired, liquid fuel fired, and solid fuel fired units. Each of these three subcategories was then further divided into subcategories based on capacity: ( 1) Large units ( watertube boilers and process heaters with heat inputs greater than 10 MMBtu/ hr); ( 2) small units ( firetube boilers and any boiler and process heater with a maximum rated heat input capacity of 10 MMBtu/ hr or less); and ( 3) limited use units with capacity utilization less than 10 percent. We identified the types of air pollution control techniques currently used by existing boilers and process heaters in each subcategory. We ranked those controls according to their effectiveness in removing the different categories of pollutants; including metallic HAP and PM, inorganic HAP such as acid gases, mercury, and organic HAP. The EPA ranked these existing control technologies by incorporating recommendations made by the ICCR, and by reviewing emissions test data, previous EPA studies, and other literature, as well as by using engineering judgement. Based upon the emissions reduction potential of existing air pollution control techniques, we listed all the boilers and process heaters in the population database in order of decreasing control device effectiveness within each subcategory for each pollutant type. Then we identified the top 12 percent of units within each category based on this ranking, and determined what kind of emission control technology, or combination of technologies, the units in the top 12 percent employed. Finally, we looked at the emissions test data from boilers and process heaters that used the same control technology, or technologies, as the units in the top 12 percent to estimate the average emissions limitation achieved by these units. The last part in the process described above, involving the calculation of numerical emission limits, was a twostep analysis. The first step involved calculating a numerical average of an appropriate subset of the emission test data from units using the same technology, or technologies, as the units in the top 12 percent. Based on the initial ranking, we determined what proportion of the units using a particular technology were among the top 12 percent of units in the subcategory. Then we looked at a corresponding proportion of the emission test data from units using that type of control technology, and produced an overall average measured performance level. For example, in the large solid fuel subcategory, approximately 14 percent of units used the best performing control technology for PM/ metallic HAP ( baghouses). In order to rank the units using the best technology for which we had emission test data, we generated unit by unit measured performance levels by averaging the multiple tests from each individual unit ( if multiple tests were available). Then we looked at the best 12/ 14 of the units for which we generated such individual averages, and averaged the unit by unit averages from all of these units. This resulted in an overall average measured emissions performance level for units representative of the top 12 percent of units in the subcategory. The second step in this part of the process involved generating and applying an appropriate variability factor to account for unavoidable variations in emissions due primarily to uncontrollable differences in fuel characteristics and ordinary operational variability. First, we identified all the units for which we had emission test data using the same technology, or technologies, as units in the top 12 percent. Then, for each such unit with multiple emission tests, we calculated the variability in the measured emissions from that unit by dividing the highest three run test result by the lowest three run test result. Finally, we calculated the overall variability in the measured emissions from these units by averaging all the individual unit variability factors, and we applied this overall variability factor to the overall average measured emissions performance level ( as described above) to derive a emission limit representative of the average emission limitation achieved by the top 12 percent of units. This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by units in the top 12 percent, considering ordinary operational variability. Both the analysis of the measured emissions from units representative of the top 12 percent, and the variability analysis, are 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. Using such an approach, including a variability factor, is reasonable because the estimated performance of the best controlled units must account for variability in the performance of the units over time and under different operational conditions. Absent comprehensive emission data, there is no reason to believe that any individual unit could consistently achieve the emission performance demonstrated by a limited set of emission tests. Because, each emission test is but a snapshot of actual and ongoing performance, taken at one moment in time, evaluating the snapshots collectively is the best way to estimate the unavoidable variation in emissions expected to occur and recur over time at similarly controlled units in the category ( or subcategory). As a result, the most reasonable methodology for determining the variability among the best controlled units is to evaluate the overall variability in the performance of the particular control technology that those units use, by examining the variability among the emission test results ( the performance snapshots) for all similarly controlled units ( excluding any emission values from tests that did not represent a proper functioning system). Accordingly, we have used the available emissions data to reasonably estimate the variability of the top performing units in each subcategory. The EPA's review of emissions data indicates that some boilers and process heaters within each subcategory may be able to meet the floor emission levels without using the air pollution control technology that is used by the top 12 percent of units in the subcategory. This is to be expected given the variety of fuel types, fuel input rates, and boiler designs included within each subcategory and the resulting variability in emission rates. Thus, for instance, boilers or process heaters within the large unit solid fuel subcategory that burn lower percentages of solid fuels may be able to achieve the emission levels for the large unit solid fuel subcategory without the need for additional control devices. Furthermore, solid fuels, especially coal, are very heterogeneous and can VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1675 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules 1 The speciation of mercury in the flue gas is believed to affect the amount of mercury captured by control devices. Mercury can be present in both vapor form ( as insoluble elemental mercury and as soluble oxidized mercury ( such as, mercury chloride)) and in particulate form. The capture of elemental mercury is reportedly more difficult than the capture of oxidized mercury or mercury in particulate form. vary in composition by location. Coal analysis data obtained from the electric utility industry in another rulemaking contained information on the mercury, chlorine, and ash content of various coals. A preliminary review of this data indicate that the composition can vary greatly from location to location, and also within a particular location. Based on the range of variation of mercury, chlorine, and ash content in coal, it is possible for a unit with a lower performing control system to have emission levels lower than a unit considered to be included in the best performing 12 percent of the units. This situation is reflected in the emissions information used to set the MACT floor emission limits. In some instances there are boilers with ESP or other controls that achieve similar, or lower, outlet emission levels of nonmercury metallic HAP, PM, or mercury than fabric filters. In most cases, this is due to concentrations entering these other control devices being lower, even though the percent reduction achieved is lower than fabric filters. Additionally, the design of some control devices may have a substantial effect on their emissions reductions capability. For example, fabric filters are largely insensitive to the physical characteristics of the inlet gas stream. Thus, their design does not vary widely, and emissions reductions are expected to be similar ( e. g. 99 percent reduction of PM). However, ESP design can vary significantly. Some ESP are two fields, others may have three or four. The more fields the larger the emissions reductions for PM. Similarly, other devices can be designed to achieve higher emissions reductions. This level of detail was not available for the information used to develop the MACT floor emission limits. Consequently, since fuel substitution has been determined not to be an appropriate MACT floor control technology, EPA still considers the fabric filter to be the best performing control for non mercury metallic HAP, PM, and mercury and only emissions information for fabric filters was used to develop emission limits. For existing unit subcategories where less than 12 percent of units in the subcategory use any type of control technology, we could not use the same approach to identify the average level of control achieved by the top 12 percent. Therefore, we looked to see if we could estimate the central tendency of the best controlled units by looking at the median unit of the top 12 percent ( the unit at the 94th percentile). Under such circumstances, if the median unit of the top 12 percent is using some control technology, we might use the measured emission performance of that individual unit as the basis for estimating an appropriate average level of control of the top 12 percent. For subcategories where even the median unit is using no control technology, the average control of the top 12 percent of units is no emissions reductions. A detailed discussion of the MACT floor methodology is presented in the memorandum `` MACT Floor Analysis for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants'' in the docket.

1. Existing Solid Fuel Boilers and Process Heaters a. Large Units   Heat Inputs Greater than 10 MMBtu/ hr. The most effective control technologies identified for removing non mercury metallic HAP and PM are fabric filters. About 14 percent of solid fuel fired boilers and process heaters use fabric filters. Because greater than 12 percent of units in the category use this technology, and because there are no options reasonably available for reducing HAP emissions other than add on control, we consider sources with fabric filters to be the best controlled sources in this subcategory for purposes of metallic HAP and PM emissions. Thus, it is appropriate to use the measured performance of sources with fabric filters as the basis for establishing the MACT floor for nonmercury metallic HAP and PM for existing boilers and process heaters in this subcategory. As described earlier, a PM level is set as a surrogate for non mercury metallic HAP. The MACT floor emission level based on PM test data from the solid fuel units with fabric filters representing the top 12 percent, and incorporating operational variability ( using results from multiple tests on best performing units), is 0.07 lb PM/ MMBtu. We are also providing an alternative metals limit of 0.001 lb metals/ MMBtu which can be used to show compliance in cases where metal HAP emissions are low in proportion to PM emissions. This is because, according to the emissions database, some biomass units have low metals content but high PM emissions. The emission level for metals was selected from metals test data associated with PM emission tests from fabric filters that met the MACT floor PM emission level. The most effective control technologies identified for removing inorganic HAP that are acid gases, such as HCl, are wet scrubbers and packed bed scrubbers. These technologies are used by about 13 percent of the boilers and process heaters in the large solid fuel subcategory. About 12 percent of solid fuel fired boilers and process heaters use wet or dry scrubbers, and approximately 1 percent use packed bed scrubbers. Because greater than 12 percent of units in the category use this technology, and because there are no options reasonably available for reducing HAP emission other than addon control, we consider sources with wet or dry scrubbers and packed bed scrubbers to be the best controlled sources in this subcategory for purposes of inorganic HAP emissions. Thus, it is appropriate to use the measured performance of sources with wet or dry scrubbers and packed bed scrubbers as the basis for establishing the MACT floor for inorganic HAP for existing boilers and process heaters in this subcategory. The MACT floor emission level based on HCl emissions test data from units using wet or dry scrubbers and packed bed scrubbers representing the top 12 percent, and incorporating operational variability, is 0.09 lb HCl/ MMBtu. Based on test information on utility boilers, we have concluded that fabric filters are the most effective technology for controlling mercury emissions. As discussed previously, approximately 14 percent of sources in the subcategory use fabric filters. The MACT floor emission level for mercury, based on the measured performance of units with fabric filters representing the top 12 percent, and incorporating operational variability, is 0.000007 lb mercury/ MMBtu. Although EPA used information from utility boilers to conclude that fabric filters are the most effective control technology for controlling mercury emissions, this same information suggests that different fuel characteristics ( e. g. mercury and chlorine content of the fuel burned) can lead to both different outlet mercury ( Hg) concentrations and different control efficiencies for equivalent control devices. 1 We have emissions test results for mercury emissions from seven industrial boilers and process heaters equipped with fabric filters. The Agency has information about the general type of fuel being burned during VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1676 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules the emission tests, such as coal, wood, or some mixture of fuel types. However, we have no detailed information about the specific characteristics ( such as mercury or chlorine content) of the fuel being burned during those emissions tests. Nonetheless, we believe that the use of variability factors adequately accounts for potential variations in fuel mercury and chloride content. However, because we have very limited data on actual emissions from industrial boilers and process heaters, the Agency is soliciting comment on whether the variability analysis in the current proposal adequately addresses the impact that fuel characteristics ( such as mercury and chlorine content) can have on mercury emissions from a source equipped with fabric filters. As discussed earlier, the Agency is not currently considering fuel switching as a control option in setting the MACT floor. Therefore, the Agency requests specific information regarding both the mercury and chlorine content characteristics of the fuel used in, and the mercury emissions from, industrial boilers and process heaters equipped with well designed and operated fabric filters. Comments on this issue should include specific data regarding both the characteristics of the fuel burned ( including mercury and chlorine content along with any other pertinent characteristics) and current mercury emissions of these industrial boilers and process heaters. For organic HAP, we attempted to determine the level of control being achieved by the top 12 percent of units within the subcategory, however, less than 6 percent of the units in this subcategory use any type of organic HAP control ( by limiting CO emissions). Thus, while a small proportion of units in the subcategory monitor and control their CO emissions ( and, therefore, limit emissions of organic HAP), the majority of units in the subcategory ( and in the top 12 percent) do not control these emissions. Because so few units control emissions of organic HAP, we could not calculate an average limitation achieved by the top 12 percent as we did for metallic HAP/ PM, inorganic HAP/ HCl, and mercury. We looked then at whether the median unit of the top 12 percent might provide some indication of the central tendency of the top 12 percent. However, because fewer than 6 percent of units are controlled, the median unit reflects no emissions reductions for organic HAP. Therefore, we concluded that the MACT floor for existing sources in this subcategory is no emissions reductions for organic HAP. Consequently, EPA determined that, in general, the combination of fabric filter and wet scrubber control technologies forms the basis for the MACT floor level of control for existing large solid fuel boilers or process heaters. We recognize that some boilers and process heaters that use technologies other than those used as the basis of the MACT floor can achieve the MACT floor emission levels. For example, emission test data show that many boilers with well designed and operated ESP can meet the MACT floor emission levels for non mercury metallic HAP and PM, even though the floor emission level for these pollutants is based on units using a fabric filters ( however, we would not expect that all units using ESP would be able to meet the emission limits in the proposed rule). b. Small Units   Heat Inputs Less than or Equal to 10 MMBtu/ hr. For each pollutant group ( non mercury metallic HAP and PM, mercury, inorganic HAP/ HCl, and organic HAP), less than 6 percent of the units in this subcategory used control techniques that limit emissions. Because so few units in the subcategory control emissions of HAP, we could not calculate an average limitation achieved by the top 12 percent for any HAP grouping. We looked then at whether the median unit of the top 12 percent might provide some indication of the central tendency of the top 12 percent for any HAP grouping. However, because fewer than 6 percent of units in each HAP grouping used controls or limited emissions, the median unit for each HAP grouping reflects no emissions reduction. Therefore, we determined that the MACT floor emission level for existing units for each of the pollutant categories in this subcategory is no emissions reductions. c. Limited Use Units   Capacity Utilizations Less than or Equal to 10 Percent. The most effective control technologies identified for removing non mercury metallic HAP and PM are ESP and fabric filters. Less than 2 percent of limited use solid fuel fired boilers and process heaters use fabric filters, and 14 percent use ESP. Therefore, we used the measured performance of units using ESP and fabric filters as the basis for the MACT floor for non mercury metallic HAP and PM. We established a PM level as a surrogate for non mercury metallic HAP control, reflecting the emission test data from units using ESP and fabric filters that were representative of the top 12 percent of units in the subcategory. The emissions test database did not contain test data for limited use boilers and process heaters. In order to develop emission levels for this subcategory, we decided to use information from units in the large solid fuel subcategory. We considered this to be an appropriate methodology because although the units in this subcategory 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 ( HCl and non mercury metals) are expected to be related more to the type of fuel burned and the type of control used, than to unit operation. Consequently, we determined that emissions information from the large solid fuel subcategory could be used to establish MACT floor levels for this subcategory because the fuels and controls are similar. The MACT floor emission level based on this test data, considering operational variability, is 0.02 lb PM/ MMBtu. We are also providing an alternative metals limit of 0.001 lb metals/ MMBtu which can be used to show compliance in cases where metal HAP emissions are low in proportion to PM emissions. The emissions database indicates that some biomass units have low metals content but high PM emissions. The emission level for metals was selected from metals test data associated with PM emission tests from fabric filters that met the MACT floor PM emission level. Similar control technology analyses were done for the boilers and process heaters in this subcategory for the other pollutant groups of interest, including inorganic HAP, organic HAP and mercury. For each of these pollutant groups, less than 6 percent of the units in this subcategory used control techniques that limit emissions. Because so few units in the subcategory control emissions of these HAP, we could not calculate an average limitation achieved by the top 12 percent for inorganic HAP, organic HAP and mercury. We looked then at whether the median unit of the top 12 percent might provide some indication of the central tendency of the top 12 percent for any of these HAP groupings. However, because fewer than 6 percent of units in each HAP grouping used controls or limited emissions, the median unit for each HAP grouping reflects no emission reductions. Therefore, we concluded that the MACT floor for inorganic HAP, organic HAP and mercury in this subcategory is no emissions reductions. Consequently, we determined that ESP and fabric filters, which achieve non mercury metallic HAP and PM control, form the basis for the MACT floor level of control for VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1677 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules existing solid fuel boilers and process heaters in this subcategory.

2. Existing Liquid Fuel Boilers and Process Heaters Emission data for liquid subcategories were inadequate to identify the best performing sources for reasons described previously in this preamble. We also found no State regulations or permits which specifically limit HAP emissions from these sources. Therefore, we examined control technology information to identify a MACT floor. We found that less than 6 percent of the units in each of the liquid subcategories used control techniques that would reduce non mercury metallic HAP and PM, mercury, organic HAP, or acid gases, ( such as HCl). Therefore, we concluded, for each subcategory of liquid fueled boilers and process heaters, that the MACT floor is no emission reductions for non mercury metallic HAP, mercury, inorganic HAP, and organic HAP.