[Federal Register: January 13, 2003 (Volume 68, Number 8)]
[Proposed Rules]
[Page 1659-1763]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr13ja03-31]
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Part II
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for
Industrial/Commercial/Institutional Boilers and Process Heaters;
Proposed Rule
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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.
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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.
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Examples of potentially
Category NAICS code SIC code regulated entities
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Any industry using a boiler or 211............................... 13 Extractors of crude
process heater as defined in the petroleum and natural
proposed rule. gas.
321............................... 24 Manufacturers of lumber
and wood products.
322............................... 26 Pulp and paper mills.
325............................... 28 Chemical manufacturers.
324............................... 29 Petroleum refineries,
and manufacturers of
coal products.
316, 326, 339..................... 30 Manufacturers of rubber
and miscellaneous
plastic products.
331............................... 33 Steel works, blast
furnaces.
332............................... 34 Electroplating, plating,
polishing, anodizing,
and coloring.
336............................... 37 Manufacturers of motor
vehicle parts and
accessories.
221............................... 49 Electric, gas, and
sanitary services.
622............................... 80 Health services.
611............................... 82 Educational services.
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This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists examples of the types of entities EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed could also be affected. To determine whether your
facility, company, business, organization, etc., is regulated by this
action, you should examine the applicability criteria in Sec. 63.7485
of the 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
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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 e-mail 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
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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
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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 fuel-fired 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.
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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 (long-term) inhalation or oral exposure to cadmium leads to a
build-up of cadmium in the kidneys that can cause kidney disease.
Cadmium has been shown to be a developmental toxicant in animals,
resulting in fetal malformations and other effects, but no conclusive
evidence exists in humans. An association between cadmium exposure and
an increased risk of lung cancer has been reported from human studies,
but these studies are 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 (long-term) inhalation exposures. Shortness of breath,
coughing, and wheezing have been reported from acute exposure to
chromium VI, while perforations and ulcerations of the septum,
bronchitis, decreased pulmonary function, pneumonia, and other
respiratory effects have been noted from chronic exposure. Limited
human studies suggest that chromium VI inhalation exposure may be
associated with complications during pregnancy and childbirth, while
animal studies have not reported reproductive effects from inhalation
exposure to chromium VI. Human and animal studies have clearly
established that inhaled chromium VI is a carcinogen, resulting in an
increased risk of lung cancer. The EPA has classified chromium VI as a
Group A, human carcinogen.
Chromium III is less toxic than chromium VI. The respiratory tract
is also the major target organ for 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 (long-term) exposure to lead in humans results in
effects on the blood, central nervous system (CNS), blood pressure, and
kidneys. Children are particularly sensitive to the chronic effects of
lead, with slowed cognitive development, reduced growth and other
effects reported. Reproductive effects, such as decreased sperm count
in men and spontaneous abortions in women, have been associated with
lead exposure. The developing fetus is at particular risk from maternal
lead exposure, with low birth weight and slowed postnatal
neurobehavioral development noted. Human studies are inconclusive
regarding lead exposure and cancer, while animal studies have reported
an increase in kidney cancer from lead
[[Page 1665]]
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 mask-like face, and
psychological disturbances, may result from chronic exposure to higher
levels. Impotence and loss of libido have been noted in male workers
afflicted with manganism attributed to inhalation exposures. The EPA
has classified manganese in Group D, not classifiable as to
carcinogenicity in humans.
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 (long-term) exposure to elemental mercury
in humans also affects the CNS, with effects such as increased
excitability, irritability, excessive shyness, and tremors. The EPA has
not classified elemental mercury with respect to cancer.
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
[[Page 1666]]
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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Hydrogen
Source Subcategory Particulate or selected chloride Mercury (Hg) Carbon Monoxide
matter (PM) metals (HCl) (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,
[[Page 1667]]
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 site-specific 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 site-specific minimum sorbent
injection rate operating limit.
(5) For boilers and process heaters with fabric filters in
combination with wet scrubbers that must comply with a mercury emission
limit, PM 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
[[Page 1668]]
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
[[Page 1669]]
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
fuel-fired 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).
Indirect-fired 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 residential-type 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
[[Page 1670]]
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 co-fire 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 field-erected 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 fuel-fired
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 fuel-fired 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,
[[Page 1671]]
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, non-mercury metallic HAP, inorganic HAP, and organic HAP. In
general, the pollutants within each group have similar characteristics
and can be controlled with the same techniques. 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
[[Page 1672]]
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
[[Page 1673]]
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 oxygen-fuel 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
[[Page 1674]]
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 add-on 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 two-step 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
[[Page 1675]]
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 non-mercury 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 non-mercury 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 add-on 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
[[Page 1676]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 1677]]
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.
3. Existing Gaseous Fuel Boilers and Process Heaters
Emission data for gas subcategories were inadequate to identify the
best performing sources for reasons described in section III.D of this
preamble. We also found no State regulations or permits that
specifically limit HAP emissions from these sources. Therefore, we
examined control technology information to identify a MACT floor. We
found that no existing units in the gaseous fuel-fired subcategories
were using control technologies that achieve consistently lower
emission rates than uncontrolled sources for any of the pollutant
groups of interest. Therefore, we are unable to identify the best
performing 12 percent of units in the subcategories. Consequently, EPA
determined that no existing source MACT floor based on control
technologies could be identified for gaseous fuel-fired units.
Therefore, we concluded the MACT floor for existing sources in this
subcategory is no emissions reductions for non-mercury metallic HAP,
mercury, inorganic HAP, and organic HAP.
E. How Did EPA Consider Beyond-the-Floor Options for Existing Units?
Once the MACT floor determinations were done for each subcategory,
EPA considered various regulatory options more stringent than the MACT
floor level of control (i.e., technologies or other work practices that
could result in lower emissions) for the different subcategories.
Maintaining and monitoring CO levels was identified as a possible
control for organic HAP. In addition to looking at whether CO limits
should be a part of the MACT floor, we looked at this option as a
beyond-the-floor option. However, information was not available to
estimate the HAP emissions reductions that would be associated with CO
monitoring and emission limits. This option would also require a high
cost to install and operate CO monitors. Given the cost and the
uncertain emissions reductions that might be achieved, we chose to not
require CO monitoring and emission limits as MACT.
The following sections discuss the beyond-the-floor options
analyzed to control emissions of metallic HAP, mercury, and inorganic
HAP. Based on the analysis in these sections, EPA decided to not go
beyond the MACT floor level of control for the proposed rule for any of
the subcategories of existing sources. A detailed description of the
beyond-the-floor consideration is in the memorandum ``Methodology for
Estimating Cost and Emissions Impacts for Industrial, Commercial,
Institutional Boilers and Process Heaters National Emission Standards
for Hazardous Air Pollutants'' in the docket.
1. Existing Solid Fuel Units
a. Large Units--Heat Inputs Greater than 10 MMBtu/hr. Besides fuel
switching, we identified a better designed and operated fabric filter
(the MACT floor for new units) as a control technology that could
achieve greater emissions reductions of metallic HAP and PM emissions
than the MACT floor level of control. Consequently, EPA analyzed the
emissions reductions and additional cost of adopting an emission limit
representative of the performance of a unit with a better designed and
operated fabric filter. The additional annualized cost to comply with
this emission limit was estimated to be approximately 500 million
dollars with an additional emission reduction of approximately 100 tons
of metallic HAP. The results indicated that while additional emissions
reductions would be realized, the costs would be too high to consider
it a feasible beyond-the-floor option. Nonair quality health,
environmental impacts, and energy effects were not significant factors,
because there would be little difference in the nonair quality health
and environmental impacts of replacing existing fabric filters with
improved performance fabric filters. Therefore, we did not select these
controls as MACT. Fuel switching was not considered a feasible beyond-
the-floor option for the same reasons described previously in this
preamble.
We identified packed bed scrubbers as a control technology that
could achieve greater emissions reductions of inorganic HAP, like HCl,
than the MACT floor level of control. Consequently, EPA analyzed the
emissions reductions and additional cost of adopting an emission limit
representative of the performance of a unit with a packed bed scrubber.
The additional annualized cost to comply with this emission limit
(using a packed bed scrubber) was estimated to be approximately 900
million dollars with an additional emission reduction of approximately
20,000 tons of HCl. The results indicated that while additional
emissions reductions would be realized, the costs would be too high to
consider it a feasible beyond-the-floor option. Nonair quality health,
environmental impacts, and energy effects were not significant factors,
because there would be little difference in the nonair quality health
and environmental impacts between packed bed scrubbers and the
technology that is likely to be used to meet the MACT floor level of
control. Therefore, we did not select these controls as MACT.
In reviewing potential regulatory options for existing sources, EPA
identified one existing industrial boiler that was using a technology,
carbon injection, used in other industries to achieve greater control
of mercury emissions than the MACT floor level of control. However,
emission data indicated that this unit was not achieving mercury
emission reduction. The EPA does not have information that would show
carbon injection is effective for reducing mercury emissions from
industrial, commercial, and institutional boilers and process heaters.
Therefore, carbon injection was not evaluated as a regulatory options.
However, EPA requests comments on whether carbon injection should
be considered as a beyond-the-floor option and whether existing
industrial, commercial, or institutional boilers and process heaters
could use carbon injection technology, or other control techniques to
consistently achieve mercury emission levels that are lower than levels
from similar sources with the MACT floor level of control. Comments
should include information on emissions, current demonstrated
applications, and costs, including retrofit costs. The EPA is aware
that research continues on ways to improve mercury capture by PM
controls, sorbent injection, and the development of novel techniques.
The EPA requests comment and information on the effectiveness of such
control
[[Page 1678]]
technologies in reducing mercury emissions.
b. Small Units--Heat Inputs Less than or Equal to 10 MMBtu/hr. The
MACT floor for this subcategory is no emission reductions. To control
non-mercury metallic HAP and mercury, we analyzed the beyond-the-floor
option of a fabric filter which was identified, generally, as the most
effective control device for non-mercury metallic HAP and mercury. To
control inorganic HAP such as HCl, we analyzed the beyond-the-floor
option of a wet scrubber since it was identified as the least cost
option.
The total annualized cost of complying with the fabric filter
option was estimated to be 10 million dollars, with an estimated
emission reduction of 1.9 tons per year of non-mercury metallic HAP and
0.003 tons of mercury. The annualized cost of complying with the wet
scrubber option was estimated to be 11 million dollars, with an
emission reduction of 48 tons per year of HCl. The results of this
analysis indicated that while additional emissions reductions could be
realized, the costs would be too high to consider them feasible
options. Therefore, we did not select these controls as MACT. Nonair
quality health, environmental impacts, and energy effects were not
significant factors.
c. Limited Use Units--Capacity Utilizations Less than or Equal to
10 Percent. The MACT floor level for this subcategory for non-mercury
metallic HAP control is 0.2 lb PM/MMBtu (this level of control can
generally be achieved by using an ESP or fabric filter). Although
fabric filters were identified as being more effective, many ESP can
achieve similar levels. Any additional emission reduction from using a
fabric filter would be minimal and costly considering retrofit costs
for existing units that already have ESP. Therefore, a beyond-the-floor
option for metallic HAP was not analyzed in detail. However, a beyond-
the-floor option based on the level of performance of a fabric filter
was analyzed for mercury control. The total annualized costs of the
fabric filter option was estimated to be an additional 21 million
dollars, with an estimated emission reduction of 0.04 tons of mercury.
The MACT floor for inorganic HAP in this subcategory was no
emission reductions. For beyond-the-floor control of inorganic HAP, we
analyzed the level of performance generally achievable by a wet
scrubber since it was identified as the least cost option. The total
annualized costs of the wet scrubber option was estimated to be 49
million dollars, with an estimated emission reduction of 463 tons per
year of HCl.
The results of the beyond-the-floor analyses indicated that while
additional emissions reductions could be realized, the costs would be
too high to consider them feasible options. Therefore, we did not
select these controls as MACT. Nonair quality health, environmental
impacts, and energy effects were not significant factors.
2. Existing Liquid Fuel Units
The MACT floor for each liquid fuel subcategory is no emission
reductions. For beyond-the-floor options for the liquid subcategory,
EPA identified several PM controls (e.g., fabric filters, ESP, and
venturi scrubbers) that would reduce non-mercury metallic HAP
emissions. For the beyond-the-floor analysis, we analyzed the cost and
emission reduction of applying a high efficiency PM control device,
such as a fabric filter, since these would be more likely to be
installed for units firing liquid fuel. We identified wet scrubbers as
a technology beyond-the-floor option for reduction of inorganic HAP,
such as HCl. We identified fabric filters as a beyond-the-floor
technology option for reduction of mercury. Consequently, EPA analyzed
the emissions reductions and additional cost of applying high
efficiency PM controls and wet scrubbers on liquid fuel-fired units.
The additional total annualized cost of a high efficiency PM control
device (such as a fabric filter) was estimated to be 460 million
dollars, with an additional estimated emission reduction of 1,500 tons
per year for non-mercury metallic HAP and 3 tons per year for mercury.
The annualized cost of a wet scrubbers was estimated to be an
additional 480 million dollars, with an additional HCl reduction of 30
tons per year. The results indicated that while additional emissions
reductions would be realized, the costs would be too high to consider
them feasible options. Nonair quality health, environmental impacts,
and energy effects were not significant factors. Therefore, EPA chose
to not select these controls as MACT for existing liquid units.
3. Existing Gas-Fired Units
The MACT floor for each gaseous fuel subcategory is no emission
reductions. The great majority, if not all, of the emissions from gas-
fired units are organic HAP. As discussed previously in this preamble,
CO monitoring and emission limits were considered as a beyond-the-floor
option, but were not selected as MACT given the costs and uncertain HAP
reductions achieved. Therefore, no beyond-the-floor control technique
was analyzed for organic HAP, and MACT is no emission reduction of non-
mercury metallic HAP, mercury, inorganic HAP, and organic HAP.
4. Fuel Switching as a Beyond-the-Floor Option
For the solid fuel and liquid fuel subcategories, fuel switching to
natural gas is a regulatory option more stringent than the MACT floor
level of control that would reduce mercury, metallic HAP, and inorganic
HAP emissions. We determined that fuel switching was not an appropriate
beyond-the-floor option for the reasons discussed previously in this
preamble. For example, natural gas supplies are not available in some
areas, and supplies to industrial customers can be limited during
periods when natural gas demand exceeds supply. Furthermore, in some
cases, organic HAP would be increased by fuel switching. Additionally,
the estimated emissions reductions that would be achieved if solid and
liquid fuel units switched to natural gas were compared with the
estimated cost of converting existing solid fuel and liquid fuel units
to fire natural gas. The annualized cost of fuel switching was
estimated to be $12 billion. The additional emission reduction
associated with fuel switching was estimated to be 1,500 tons per year
for metallic HAP, 11 tons per year for mercury, and 13,000 tons per
year for inorganic HAP. Additional detail on the calculation procedures
is provided in the memorandum ``Development of Fuel Switching Costs and
Emissions Reductions for Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for Hazardous
Air Pollutants'' in the docket.
F. Should EPA Consider Different Subcategories for Solid Fuel Boilers
and Process Heaters?
The boilers and process heaters source category is tremendously
heterogeneous. The EPA has attempted to identify subcategories that
provide the most reasonable basis for grouping and estimating the
performance of generally similar units using the available data. We
believe that the subcategories we selected are appropriate, given the
variety and combination of fuels that sources in the category burn and
the fact that any individual unit may use a different combination of
fuels over time.
However, among the solid fuel units, the available emission test
data could suggest that units burning only wood might perform
sufficiently similar to each other, and sufficiently differently
[[Page 1679]]
from other (fossil fuel burning) solid fuel units, to warrant
additional subcategorization. Nonetheless, we believe, for purposes of
today's proposal, that it is appropriate to treat wood burning and non-
wood burning solid fuel units as a single category. We believe, given
the available data, that this approach most reasonably accounts for
variations in emissions that can occur as a result of different fuels
and/or fuel combinations, and changes in fuel use over time, and that
it provides a reasonable basis for establishing an appropriate
standard.
However, if we were to create a separate subcategory for wood
burning units, we would establish MACT in a manner consistent with the
approach taken for other solid fuel units. We would identify the types
of emission control used by the best controlled source (and the top 12
percent of units in the subcategory), and we would estimate the
performance of the best controlled units by looking at representative
emission test data and applying an appropriate variability factor. A
preliminary review of the wood burning units in the database suggests
that the MACT floors for such units would probably be related to the
performance of ESP and/or scrubbers.
The EPA requests comments on whether additional or different
subcategories should be considered. Comments should include detailed
information regarding why a new or different subcategory is appropriate
(based on the available data or adequate data submitted with the
comment), how EPA should define any additional/different subcategories,
how EPA should account for varied or changing fuel mixtures, and how
EPA should use the available data to determine the MACT floor for any
new or different categories.
G. How Did EPA Determine the Proposed Emission Limitations for New
Units?
All standards established pursuant to section 112 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 emissions reductions, and any nonair quality health
and environmental impacts and energy requirements, determines is
achievable for each category. The CAA specifies that MACT for new
boilers and process heaters shall not be less stringent than the
emission control that is achieved in practice by the best-controlled
similar source--this minimum level of stringency is the MACT floor for
new units. 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).
H. How Did EPA Determine the MACT Floor for New Units?
Similar to the MACT floor process used for existing units, we
considered several approaches to identifying MACT floors for new
industrial, commercial, and institutional boilers and process heaters.
First, we considered using only the emission test data from boilers and
process heaters to set the MACT floor. However, as discussed previously
in this preamble, we determined that it was inappropriate in the
proposed rulemaking to develop MACT floor emission limits based on HAP
emissions test information alone.
We then considered using HAP emission limits contained in State
regulations and permits as a surrogate to actual emission data in order
to identify the emissions levels from the best performing units in the
category for purposes of establishing MACT standards. However, we found
no State regulations or State permits which specifically limit HAP
emissions from these sources.
Consequently, we concluded that the most appropriate approach for
identifying the top performing units in each subcategory of boilers and
process heaters is to look at the control technologies used by the
units within each subcategory. Information was available on the add-on
control technologies employed by the population of boilers identified
by the EPA. We considered several possible control options (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 both fuel switching to other fuels used in the
subcategory and to fuels from other subcategories. This consideration
included determining whether switching fuels would achieve lower HAP
emissions. A second consideration was whether fuel switching could be
technically achieved by boilers and process heaters in the subcategory
based on design considerations. We also considered the availability of
various types of fuel.
As discussed previously in this preamble, 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. Additional
discussion of fuel switching is presented previously in this preamble
and 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.
Based on the data available in the emissions database, we
determined that while fuel switching would decrease some HAP, emissions
of some organic HAP would increase, resulting in uncertain benefits. 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. A detailed discussion of
the consideration of fuel switching is discussed previously in this
preamble.
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 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 oxygen-fuel contact), and sufficient time (to complete
the process), sometimes referred to the three Ts of combustion. Good
combustion practice, 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
[[Page 1680]]
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.
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 new units. However, we have considered the
appropriateness of such requirements in the context of evaluating
possible above 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 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 requirements as a part of the MACT floor for new sources in
this category should not reduce the incentive for owners and operators
to run their boilers and process heaters at top efficiency.
Nonetheless, we consider monitoring and maintaining CO emission
levels to be associated with minimizing emissions of organic HAP.
Carbon monoxide is generally an indicator of incomplete combustion
because CO will burn to carbon dioxide if adequate oxygen is available.
Therefore, controlling CO emissions can be a mechanism for ensuring
combustion efficiency and may be viewed as a kind of GCP. As discussed
previously in this preamble, CO is considered a surrogate for organic
HAP emissions in the proposed rule.
To determine if CO monitoring would be the basis of the new source
MACT floor for organic emissions control, we examined available
information. The population databases did not contain information on
existing units monitoring CO emissions. We reviewed State regulations
applicable to boilers and process heaters that required the use of CO
monitoring to maintain a specific CO limit. We then matched the
applicability of each of the State regulations with information on the
locations and characteristics of the boilers and process heaters in the
population database for each subcategory to determine if each
subcategory would have at least one unit that would be required to meet
the CO requirements. The analysis of the State regulations indicated
that at least one of the boilers and process heaters in the large and
limited use subcategories for solid fuel, liquid fuel, and gaseous fuel
were required to monitor CO emissions and meet a CO limit of 400 parts
per million. Therefore, the new source MACT floor level of control
includes a CO work practice standard of 400 parts per million for large
and limited use units, reflecting the MACT floor level of control for
emissions of organic HAP.
We concluded for new units that, except for CO monitoring for
organic HAP, add-on control technology is the only factor that
significantly controls emissions. To determine the MACT floor for new
sources, EPA reviewed the population database of existing major
sources. Data for units not meeting the definition of an industrial,
commercial, or institutional boiler or process heater were removed from
the database. Also, boilers and process heaters that would not be
covered by the proposed rule, including units located at area source
facilities, were not included in the analyses. As with the existing
source analysis, the remaining units in the population database were
first divided into three subcategories: gaseous fuel-fired units,
liquid fuel-fired units, and solid fuel-fired units. They were further
divided into normal use units (units with greater than 10 percent
capacity utilization) and limited use units (units with less than or
equal to 10 percent capacity utilization) based on hours of operation
and additional descriptions provided in the population database. Units
were further divided into large units (greater than 10 MMBtu/hr heat
input) and small units (less than or equal to 10 MMBtu/hr heat input).
Based upon the emission reduction potential of existing air
pollution control devices, EPA listed all the boilers and process
heaters in the population database in order of decreasing control
device effectiveness for each subcategory and each type of pollutant.
Once the ranking of all existing boilers and process heaters was
completed for each subcategory and type of pollutant, EPA identified,
for each grouping, the control technology used by the best controlled
unit. Then, for each pollutant type in each subcategory, we used the
available emission test data from units using the best control
technology to identify the single unit with the best average measured
performance. We then calculated an emission limit, based on the
measured performance of this single unit, by applying an appropriate
variability factor to account for unavoidable variations in emissions
due to uncontrollable variations in fuel characteristics.
The approach that we use to calculate the MACT floors for new
sources is somewhat different from the approach that we use to
calculate the MACT floors for existing sources. While the MACT floors
for existing units are intended to reflect the average performance
achieved by a representative group of sources, the MACT floors for new
units are meant to reflect the emission control that is achieved in
practice by the best controlled source. Thus, for existing units, we
are concerned about estimating the central tendency of a set of
multiple units, while for new units, we are concerned about estimating
the level of control that is representative of that achieved by a
single best controlled source. As with the analysis for existing
sources the new unit analysis must account for variability. To
accomplish this for new sources, for the fuel dependent HAP emissions,
we attempt to determine what the best controlled source can achieve in
light of the inherent and unavoidable variations in the HAP content of
the fuel that such unit might potentially use. For non-fuel dependent
HAP emissions, on the other hand, we look at the inherent variability
of the control technology used by sources in the category. These
approaches, respectively, represent the most reasonable way to estimate
performance for purposes of establishing MACT floors for new units,
given the data available.
Thus, for new units, after identifying the best control technology
for each pollutant group within each subcategory (based on the control
technology rankings), EPA examined the emissions
[[Page 1681]]
data available for boilers and process heaters controlled by these
technologies to determine achievable emission levels for PM (as a
surrogate for non-mercury metallic HAP), total selected non-mercury
metallic HAP, mercury, HCl (as a surrogate for inorganic HAP), and CO
(as a surrogate for organic HAP). First, we identified the units using
the best control technology for which we had emissions data. We then
averaged the emission data for any unit with multiple test results, and
rank these units based on the unit by unit average measured emissions
performance. Then, we identified the unit with the best average
measured emissions performance. Finally, to estimate the emission
control achievable by this unit, we applied a variability factor to the
average measured emissions performance of the best unit. For fuel
dependent HAP emissions (mercury and HCl), we calculated the
variability factor by looking at data on HAP variability in coal from
an analysis of coal properties obtained through a utility-related
information collection request. We derived the fuel dependent
variability factor by dividing the highest observed HAP concentration
by the lowest observed HAP concentration from the utility coal
analysis. There is no reason to expect that utilities use significantly
different coal than is available to industrial boilers and process
heaters, and coal is the solid fuel that is routinely used in such
units that has generally the greatest degree of HAP variability. Once
we calculated the fuel dependent variability factors, we applied these
factors to the average measured emissions performance of the unit with
the best data to derive the MACT floor level of control. This approach
reasonably estimates the best source's level of control, adjusted for
unavoidable variation in fuel characteristics which have a direct
impact on emissions.
For non-fuel dependent HAP emissions (PM/metallic HAP), we
calculated the appropriate variability factor in the same general
manner as we did for existing units. We calculated a variability factor
for each unit using the same control technology as the unit with the
best emissions data, and then calculated the overall variability in the
measured emissions from units using this technology by averaging all
the individual unit variability factors. Finally, we applied this
overall variability factor to the average measured emissions
performance of the unit with the best emissions data.
For new unit subcategories where no units in the subcategory
employed any type of control technology, we could not identify data to
represent the level of control of the best controlled similar unit.
Accordingly, the MACT floor level of control for such subcategories is
no emissions reductions.
A detailed description of the MACT floor determination is in the
memorandum ``MACT Floor Analysis for Industrial, Commercial, and
Institutional Boilers and Process Heaters National Emission Standards
for Hazardous Air Pollutants'' in the docket.
1. New Solid Fuel-Fired Units
a. Large Units--Heat Inputs Greater than 10 MMBtu/hr. The most
effective control technology identified for removing non-mercury
metallic HAP and PM is fabric filters. Therefore, because there are no
options reasonably available for reducing non-mercury metallic HAP
emissions other than add-on control, we consider a source with a fabric
filter to be the best controlled similar unit in this subcategory for
purposes of non-mercury metallic HAP and PM emissions. Thus, it is
appropriate to use the measured performance of the best controlled
source with a fabric filter as the basis for establishing the MACT
floor for non-mercury metallic HAP and PM for new 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 unit with a fabric filter representing the
best controlled similar unit, and incorporating operational
variability, is 0.026 lb PM/MMBtu. We are also providing an alternative
metals limit of 0.0001 lb metals/MMBtu which can be used to show
compliance in cases where metals 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 including acid gases, such as HCl, are wet or dry
scrubbers. Wet scrubbers is a generic term that is most often used to
describe venturi scrubbers, but can include packed bed scrubbers,
impingement scrubbers, etc. One percent of boilers and process heaters
in this subcategory reported using a packed bed scrubber. Emission test
data from other industries suggests that packed bed scrubbers achieve
consistently lower emission levels than other types of wet scrubbers.
Because there are no options reasonably available for reducing HCl
emissions other than add-on control, we consider a source with a packed
bed scrubber to be the best controlled similar source in this
subcategory for purpose of HCl emissions. The MACT floor emission level
based on HCl test data from the solid fuel unit with a wet scrubber
representing the best controlled similar unit, and incorporating
operational variability, is 0.02 lb HCl/MMBtu.
For mercury control, one technology, carbon injection, that has
demonstrated mercury reductions in other source categories (i.e.,
municipal waste combustors), was identified as being used on one
existing industrial boiler. However, test data on this carbon injection
system indicated that this unit was not achieving mercury emissions
reductions. Therefore, we did not consider carbon injection to be a
MACT floor control technology for industrial, commercial, and
institutional boilers and process heaters. Data from electric utility
boilers indicate that fabric filters are the most effective technology
for controlling mercury emissions. Therefore, we consider a source with
a fabric filter to be the best controlled similar source in this
subcategory for purpose of mercury emissions. The MACT floor emission
level based on mercury test data from the solid fuel unit with a fabric
filter representing the best controlled similar unit, and incorporating
operational variability, is 0.000003 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 different outlet Hg concentrations and
different control efficiencies for equivalent control devices. We have
information about the general type of fuel being burned during the
emission tests. However, we have no detailed information about the
specific characteristics (such as mercury or chlorine content) of the
fuel being burned during the emissions tests for the best controlled
source. Nonetheless, EPA believes 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
[[Page 1682]]
current proposal adequately addresses the impact that fuel
characteristics (such as mercury and chlorine content) can have on
mercury emissions from sources 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.
Similar control technology analysis was done for the boilers and
process heaters in this subcategory for organic HAP. One control
technique, controlling inlet temperature to the PM control device, that
has demonstrated controlling downstream formation of dioxins in other
source categories (e.g., municipal waste combustors) was analyzed for
industrial boilers. Inlet and outlet dioxins test data were available
on four boilers controlled with PM control devices. In all cases, no
increase in dioxins emissions were indicated across the PM control
device even at high inlet temperatures. However, we are requesting
comment on controls that would achieve reductions of organic HAP,
including any additional data that might be available. The EPA did find
that CO monitoring can reduce organic HAP emissions, and has included
it in the new source MACT floors as described previously in this
preamble.
In light of this analysis, EPA determined that, in general, the
combination of a fabric filter, a packed bed scrubber, and CO
monitoring forms the basis for the MACT floor level of control for new
solid fuel boilers and process heaters in this subcategory.
b. Small Units--Heat Inputs Less than or Equal to 10 MMBtu/hr. The
most effective control technology identified for removing non-mercury
metallic HAP and PM is fabric filters. Because there are no options
reasonably available for reducing non-mercury metallic HAP emissions
other than add-on control, we consider a source with a fabric filter to
be the best controlled similar unit in this subcategory for purposes of
non-mercury metallic HAP and PM emissions. The most effective control
technology identified for units in this subcategory for removing acid
gases, such as HCl, is wet scrubbers. The most effective control
technology identified for removing mercury is fabric filters.
The EPA identified no control technology being used in the existing
population of boilers and process heaters that consistently achieved
lower emission rates than uncontrolled levels, such that a best
controlled similar source for organic HAP could be identified.
Therefore, we concluded that the MACT floor for new sources in this
subcategory is no emissions reductions for organic HAP. Furthermore, CO
monitoring is not required for small boilers and process heaters by any
State rules.
Consequently, EPA determined that the combination of a fabric
filter and a wet scrubber forms the basis for the MACT floor level of
control for new solid fuel boilers and process heaters in this
subcategory.
The emissions database did not contain test data for boilers and
process heaters less than 10 MMBtu/hr heat input. In order to develop
emission levels for this subcategory, we decided to use test data from
units in the large solid 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
designs and emissions), emissions of the specific HAP for which limits
are being proposed (HCl, mercury, PM and metals) are expected to be
related more to the type of fuel burned and the type of control used
than to the unit design. Consequently, we determined that emissions
test data from units greater than 10 MMBtu/hr heat input could be used
to establish the MACT floor levels for this subcategory for HCl, PM,
non-mercury metallic HAP (using PM as a surrogate), and mercury because
the fuels and controls are similar.
The MACT floor emission levels based on emissions data from the
unit representing the best controlled similar source, and incorporating
operational variability, are 0.026 lb PM/MMBtu or 0.0001 lb selected
non-mercury metals/MMBtu, 0.000003 lb mercury/MMBtu, and 0.02 lb HCl/
MMBtu. We are requesting comment on using emission data from another
subcategory to develop emission levels for this subcategory. We are
also requesting any available emissions information for this
subcategory.
c. Limited Use Units--Capacity Utilizations Less than or Equal to
10 Percent. The most effective control technology identified for
removing non-mercury metallic HAP, PM, and mercury is fabric filters.
Therefore, we consider a source with a fabric filter to be the best
controlled similar unit in this subcategory for purposes of non-mercury
metallic HAP, PM, and mercury emissions. The most effective control
technology identified for units in this subcategory for removing acid
gases, such as HCl, is wet scrubbers.
The EPA did find that monitoring CO is used by at least one unit
and can minimize organic HAP emissions, and has included it in the new
source MACT floor for this subcategory as described previously in this
preamble.
Therefore, based on this analysis, EPA determined that the
combination of a fabric filter, a wet scrubber, and CO monitoring forms
the basis for the MACT floor level of control for new solid fuel
boilers and process heaters in this 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 test data 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, mercury, and 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 levels based on
test data from unit representing the best controlled similar source,
and incorporating operational variability, are 0.026 lb PM/MMBtu or
0.0001 lb metals/MMBtu, 0.000003 lb mercury/MMBtu, and 0.02 lb HCl/
MMBtu. We are requesting comment on using emission data from another
subcategory to develop emission levels for this subcategory. We are
also requesting any available emissions information for this
subcategory.
2. New Liquid Fuel-Fired Units
a. Large Units--Heat Inputs Greater than 10 MMBtu/hr. The most
effective control technology identified for removing non-mercury
metallic HAP and PM is ESP. Therefore, because there are no options
reasonably available for reducing non-mercury metallic HAP emissions
other than add-on control, we consider a source with an ESP to be the
best controlled similar unit in this subcategory for purposes of non-
[[Page 1683]]
mercury metallic HAP and PM emissions.
As discussed earlier, a PM level is set as a surrogate for non-
mercury metallic HAP. The emissions database did not contain test data
for boilers and process heaters with ESP. In order to develop a PM
emission level for this subcategory, we decided to use test data from
oil-fired utility boilers controlled with ESP. We considered this to be
an appropriate methodology because although the units in this
subcategory are generally smaller than utility boilers, emissions of
the specific HAP for which limits are being proposed (PM as a surrogate
for metals) are expected to be related more to the type of fuel burned
and the type of control used than to the size of the unit.
Consequently, we determined that emissions test data from oil-fired
utility boilers could be used to establish the MACT floor levels for
this subcategory for non-mercury metallic HAP (using PM as a surrogate)
because the fuels and controls are similar.
The MACT floor emission level based on PM emissions data from the
unit representing the best controlled similar source, and incorporating
operational variability, is 0.03 lb PM/MMBtu. Unlike for solid fuel
subcategories, we are not aware of any liquid fuels that are low in
metals but would have high PM emissions. Therefore, we are not
proposing an alternative metals standard for the liquid subcategories.
The most effective control technology identified for removing
inorganic HAP that are acid gases, such as HCl, are packed bed
scrubbers. Because there are no options reasonably available for
reducing HCl emissions other than add-on control, we consider a source
with a packed bed scrubber to be the best controlled similar source in
this subcategory for purpose of HCl emissions. The emissions database
did not contain HCl test data for liquid fuel boilers and process
heaters. In order to develop a HCl emission level for this subcategory,
we decided to use available fuel analysis data from oil-fired units and
emission reduction performance of well designed and operated packed bed
scrubbers. We considered this to be an appropriate methodology because
this approach reasonably estimates the best source's level of control,
adjusted for unavoidable variation in fuel characteristics which have a
direct impact on emissions. The MACT floor emission level based on the
estimated performance from a liquid fuel unit with a packed scrubber
representing the best controlled similar unit, and incorporating
operational variability, is 0.0005 lb HCl/MMBtu.
Similar control technology analyses were done for the boilers and
process heaters in this subcategory for mercury and organic HAP.
Information in the emissions database or from other source
categories does not show that control technologies, such as fabric
filters, ESP, or wet scrubbers, achieve reductions in mercury emissions
from liquid fuel-fired industrial, commercial, and institutional
boilers and process heaters. Therefore, EPA identified no control
technology being used in the existing population of boilers and process
heaters in these subcategories that consistently achieved lower
emission rates than uncontrolled levels, such that a best controlled
similar source for organic HAP could be identified. However, we did
find that monitoring CO is a good combustion practice that can reduce
organic HAP emissions, and have included it in the new source MACT
floor as described previously in this preamble. We concluded the MACT
floor for new sources in this subcategory is no emissions reductions
for mercury.
In light of this analysis, the EPA determined that, in general, the
combination of an ESP, a packed bed scrubber, and CO monitoring forms
the basis for the MACT floor level of control for new liquid fuel
boilers and process heaters in this subcategory.
b. Small Units--Heat Inputs Less than or Equal to 10 MMBtu/hr. The
most effective control technology identified for removing non-mercury
metallic HAP used by units in this subcategory is ESP. Therefore,
because there are no options reasonably available for reducing non-
mercury metallic HAP emissions other than add-on control, we consider a
source with an ESP to be the best controlled similar unit in this
subcategory for purposes of non-mercury metallic HAP and PM emissions.
The most effective control technology identified for units in this
subcategory for removing acid gases, such as HCl, is wet scrubbers.
Information in the emissions database or from other source
categories does not show that control technologies, such as fabric
filters, ESP, or wet scrubbers, achieve reductions in mercury emissions
from liquid fuel-fired industrial, commercial, and institutional
boilers and process heaters. Therefore, EPA could not identify a
control technology being used in the existing population of boilers and
process heaters that consistently achieved lower emission rates than
uncontrolled levels, such that a best controlled similar source for
mercury or organic HAP could be identified. We concluded the MACT floor
for new sources in this subcategory is no emissions reductions for
mercury or organic HAP.
Thus, EPA determined that the combination of a fabric filter and a
wet scrubber forms the basis for the MACT floor level of control for
new liquid fuel boilers and process heaters in this subcategory.
The emissions test database did not contain test data for liquid
fuel boilers and process heaters less than 10 MMBtu/hr heat input
capacity. In order to develop emission levels for this subcategory, we
decided to use information from units in the large liquid 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 designs and emissions),
emissions of the specific types of HAP for which limits are being
proposed (HCl and metals) are expected to be more related to the type
of fuel burned and the type of control than to unit design.
Consequently, we determined that emissions information from units
greater than 10 MMBtu/hr heat input capacity 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 PM test data from a
liquid fuel unit with an ESP representing the best controlled similar
unit, and incorporating operational variability, is 0.03 lb PM/MMBtu.
The MACT floor emission level based on a liquid fuel unit with a wet
scrubber representing the best controlled similar unit, and
incorporating operational variability, is 0.0009 lb HCl/MMBtu. We are
requesting comment on using emission data from another subcategory to
develop emission levels for this subcategory. We are also requesting
any available emissions information for this subcategory.
c. Limited Use Units--Capacity Utilizations Less than or Equal to
10 Percent. The most effective control technology identified for
removing non-mercury metallic HAP used by units in this subcategory is
ESP. Therefore, because there are no options reasonably available for
reducing non-mercury metallic HAP emissions other than add-on control,
we consider a source with an ESP to be the best controlled similar unit
in this subcategory for purposes of non-mercury metallic HAP and PM
emissions. The most effective control technology identified for units
in this subcategory for removing acid gases, such as HCl, is wet
scrubbers.
Information in the emissions database or from other source
categories does not show that other control technologies,
[[Page 1684]]
such as fabric filters, ESP, or wet scrubbers, achieve reductions in
mercury emissions from liquid fuel-fired industrial, commercial, and
institutional boilers and process heaters. The EPA identified no
control technology being used in the existing population of boilers and
process heaters that consistently achieved lower emission rates than
uncontrolled levels, such that a best controlled similar source for
mercury could be identified. We concluded the MACT floor for new
sources in this subcategory is no emissions reductions for mercury.
We did find that monitoring CO can reduce organic HAP emissions and
is used by at least one unit in this subcategory, and have included it
in the new source MACT floor as described previously in this preamble.
Therefore, based on this analysis, EPA determined that the
combination of a fabric filter, a wet scrubber, and CO monitoring forms
the basis for the MACT floor level of control for new liquid fuel
boilers and process heaters in this subcategory.
The emissions test database did not contain test data for limited
use liquid fuel boilers and process heaters. In order to develop
emission levels for this subcategory, we decided to use information
from units in the large liquid 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 HAP
for which limits are being proposed (HCl and metals) are more related
to the type of fuel burned and the type of control used than to unit
operation. Consequently, we determined that emissions information from
units greater than 10 MMBtu/hr heat input capacity 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 PM test
data from a liquid fuel unit with an ESP representing the best
controlled similar unit, and incorporating operational variability, is
0.03 lb PM/MMBtu. The MACT floor emission level based on a liquid fuel
unit with a wet scrubber representing the best controlled similar unit,
and incorporating operational variability, is 0.0009 lb HCl/MMBtu. We
are requesting comment on using emission data from another subcategory
to develop emission levels for this subcategory. We are also requesting
any available emissions information for this subcategory.
3. Gaseous Fuel Subcategories
No existing units were using control technologies that achieve
consistently lower emission rates than uncontrolled sources for any of
the pollutant groups of interest, except organic HAP. At least one unit
in the population database in the large and limited use gaseous fuel
subcategories is required to monitor CO. Therefore, the MACT floor for
gaseous fuel-fired units includes a CO monitoring requirement and
emission limit, as described previously in this preamble, but it does
not include any emission limits for PM, metallic HAP, mercury, or
inorganic HAP based on the utilization of add-on control technology.
I. How Did EPA Consider Beyond-the-Floor for New Units?
The MACT floor level of control for new units is based on the
emission control that is achieved in practice by the best controlled
similar source within each of the subcategories. No technologies were
identified that would achieve non-mercury metals reduction greater than
the new source floors for the liquid and solid subcategories or CO
monitoring for the solid, liquid, and gaseous subcategories. For
inorganic HAP control, we determined that packed bed scrubbers achieve
higher emissions reductions than MACT floors consisting of a wet
scrubber. Packed bed scrubbers are the technology basis of the MACT
floor for the large unit subcategory, but wet scrubbers were the
technology basis of the floors for the small unit and limited unit
subcategories. Therefore, we examined the cost and emission reduction
benefits of applying a packed bed scrubber as a beyond-the-floor option
for new solid and liquid units within the small and limited use
subcategories. The results of this analysis indicated that annualized
costs would be an additional 2 million dollars per year for additional
reductions of approximately three tons of HCl per year. We determined
that costs were excessive for the limited emissions reductions that
would be achieved. Nonair quality health, environmental impacts, and
energy effects were not significant factors, because there would be
little difference in the nonair quality health and environmental
impacts between packed bed scrubbers and wet scrubbers. Therefore, EPA
did not select this beyond-the-floor option, and the proposed new
source MACT level of control for PM, metallic HAP, and inorganic HAP
(HCl) is the same as the MACT floor level of control for all of the
subcategories.
In reviewing potential regulatory options beyond the new source
MACT floor level of control, EPA identified one existing solid fuel-
fired industrial boiler that was using carbon injection technology for
mercury control. However, emission data obtained from this unit
indicated that it was not achieving mercury emission reduction from the
uncontrolled levels. Moreover, we do not have information to otherwise
show that carbon injection is effective for reducing mercury emissions
from industrial, commercial, and institutional boilers and process
heaters. Information in the emissions database or from other source
categories does not show that other control technologies, such as
fabric filters, ESP, or wet scrubbers, achieve reductions in mercury
emissions from liquid fuel-fired industrial, commercial, and
institutional boilers and process heaters. Therefore, carbon injection,
for solid fuel units, and other control techniques, for liquid fuel
units, were not evaluated as regulatory options. However, EPA requests
comments on whether carbon injection and/or other control techniques
should be considered as beyond-the-floor options and whether new
industrial, commercial, or institutional boilers and process heaters
could use carbon injection technology, or other control techniques to
consistently achieve mercury emission levels that are lower than levels
from similar sources without such controls. Comments should include
information on emissions, current demonstrated applications, and costs.
For the solid fuel and liquid fuel subcategories, fuel switching to
natural gas is a potential regulatory option beyond the new source
floor level of control that would reduce mercury and metallic HAP
emissions. However, based on current trends within the industry, EPA
projects that the majority of new boilers and process heaters will be
built to fire natural gas as opposed to solid and liquid fuels such
that the overall emissions reductions associated with this option would
be minimal while the total cost of fuel switching would be
approximately 600 million dollars. The additional emissions reductions
would be 30 tons per year of HCl, 90 tons per year of inorganic HAP and
120 tons per year of total non-mercury metallic HAP. Section III.D of
this preamble provides additional rationale for not going beyond the
floor to require fuel switching. For example, natural gas supplies are
not available in some areas, and supplies to industrial customers can
be limited during periods when natural gas demand exceeds
[[Page 1685]]
supply. Thus, this potential control option may be unavailable to many
sources in practice. Furthermore, organic HAP may be increased by fuel
switching. Limited emissions reductions in combination with the high
cost of fuel switching and considerations about the availability and
technical feasibility of fuel switching makes this an unreasonable
regulatory option that was not considered further. Nonair quality
health, environmental impacts, and energy effects were not significant
factors. No beyond-the-floor options for gas-fired boilers were
identified.
Based on the analysis discussed above, EPA decided to not go beyond
the MACT floor level of control for new sources for MACT in the
proposed rule. A detailed description of the beyond-the-floor
consideration is in the memorandum ``Methodology for Estimating Cost
and Emissions Impacts for Industrial, Commercial, Institutional Boilers
and Process Heaters National Emission Standards for Hazardous Air
Pollutants'' in the docket.
J. How Did EPA Determine Testing and Monitoring Requirements for the
Proposed Rule?
The CAA requires us to develop regulations that include monitoring
and testing requirements. The purpose of these requirements is to allow
us to determine whether an affected source is operating in compliance
with the proposed rule. The proposed monitoring and testing
requirements are discussed below.
1. Testing
The proposed rule requires you to perform an initial performance
test for PM (or total selected metals), mercury, and HCl if you are
required to meet an emission limit. Additionally, the proposed rule
requires annual performance tests to ensure on an ongoing basis that
the air pollution control device is operating properly and its
performance has not deteriorated. The majority of emissions tests upon
which the proposed emission limits are based were conducted using
approved EPA test methods.
If you conduct a performance test, you would also determine
parameter operating limits during the tests. The majority of test
methods that the proposed rule would require for the performance tests
have been required under many other EPA standards. No applicable
voluntary consensus standards were identified.
If you are required to meet an HCl emission limit and do not have a
scrubber or elect to take no credit for the scrubber emissions
reductions, you must record the average chlorine content level in the
input fuel as an operating limit. However, if you plan to burn a new
fuel, a fuel from a new mixture, or a fuel from a new supply than what
was burned during the initial performance test, then you must
recalculate the chlorine input. If the results of recalculating the
chlorine input exceeds the average chlorine level established during
the initial performance test, you must conduct a new performance test
to demonstrate compliance with the emission level.
We are also allowing you to record the mercury in the input fuels
as an operating limit if you elect to take no credit for the control
device emission reduction. However, if you plan to burn a new fuel, a
fuel from a new mixture, or a fuel from a new supply than what was
burned during the initial performance test, then you must recalculate
the mercury input. If the results of the recalculation exceed the
average level established during the initial performance test, you must
conduct a new performance test to demonstrate compliance with the
mercury emission level.
We are also allowing you to record the total selected metals in the
input fuels as an operating limit if you choose to comply with the
metals emission limit instead of the PM limit. However, if you plan to
burn a new fuel, a fuel from a new mixture, or a fuel from a new supply
than what was burned during the initial performance test, then you must
recalculate the total selected metals input. If the results of the
recalculation exceed the average level established during the initial
performance test, you must conduct a new performance test to
demonstrate compliance with the metals emission level.
2. Continuous Monitoring
The most direct means of ensuring compliance with emission limits
is the use of continuous emission monitoring systems (CEMS). We
consider other options when CEMS are not available or when the impacts
of including such requirements are considered unreasonable. When
monitoring options other than CEMS are considered, it is often
necessary for us to balance more reasonable costs against the quality
or accuracy of the actual emissions monitoring data. Although
monitoring of operating parameters cannot provide a direct measurement
of emissions, it is often a suitable substitute for CEMS. The
information provided can be used to ensure that air pollution control
equipment is operating properly. Because the parameter requirements are
calibrated during the initial and annual stack tests, they provide a
reasonable surrogate for direct monitoring of emissions. This
information reasonably assures the public that the reductions
envisioned by the proposed rule are being achieved.
The EPA evaluated the cost of applying HCl CEMS to boilers and
process heaters. For HCl CEM monitoring, capital costs were estimated
to be $88,000 per unit and annualized costs were estimated to be
$33,000 per unit. We determined the costs would make them an
unreasonable monitoring option. In addition, toxic metals are not
directly measurable with CEMS, and CEMS for PM have not been
demonstrated in the United States for the purpose of determining
compliance.
To ensure continuous compliance with the proposed emission limits
and/or operating limits, the proposed rule would require continuous
parameter monitoring of control devices and recordkeeping. We selected
the following requirements based on reasonable cost, ease of execution,
and usefulness of the resulting data to both the owners or operators
and EPA for ensuring continuous compliance with the emission limits
and/or operating limits.
We are proposing that certain parameters be continuously monitored
for the types of control devices commonly used in the industry. These
parameters include opacity monitoring except for wet scrubbers; pH,
pressure drop and liquid flow-rate for wet scrubbers; and sorbent
injection rate for dry scrubbers. You must also install a bag leak
detection system for fabric filters. If you cannot monitor opacity for
control systems with an ESP then you must monitor the secondary current
and voltage or total power input for the ESP. These monitoring
parameters have been used in other standards for similar industries.
The values of these parameters are established during the initial or
most recent performance test that demonstrates compliance. These values
are your operating limits for the control device.
You would be required to set parameters based on 1-hour block
averages during the compliance test, and demonstrate continuous
compliance by monitoring 3-hour block average values for most
parameters. We selected this averaging period to reflect operating
conditions during the performance test to ensure the control system is
continuously operating at the same or better level as during a
performance test demonstrating compliance with the emission limits.
[[Page 1686]]
To demonstrate continuous compliance with the emission and
operating limits, you would also need daily records of the quantity,
type, and origin of each fuel burned and hours of operation of the
affected source. If you are complying with the chlorine or total
selected metals fuel input option, you must keep records of the
calculations supporting your determination of the chlorine and total
selected metals content in the fuel.
K. How Did EPA Determine Compliance Times for the Proposed Rule?
Section 112 of the CAA specifies the dates by which affected
sources must comply with the emission standards. New or reconstructed
units must be in compliance with the proposed rule immediately upon
startup or [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER],
whichever is later. Existing sources are allowed 3 years to comply with
the final rule. This is the maximum period allowed by the CAA. We
believe that 3 years for compliance is necessary to allow adequate time
to design, install and test control systems that will be retrofitted
onto existing boilers, as well as obtain permits for the use of add-on
controls.
L. How Did EPA Determine the Required Records and Reports for the
Proposed Rule?
You would be required to comply with the applicable requirements in
the NESHAP General Provisions, subpart A of 40 CFR part 63, as
described in Table 10 of the proposed subpart DDDDD. We evaluated the
General Provisions requirements and included those we determined to be
the minimum notification, recordkeeping, and reporting necessary to
ensure compliance with, and effective enforcement of, the proposed
rule.
We are also requiring that you keep daily records of the total fuel
use by each affected source, subject to an emission limit or work
practice standard, 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. This information is necessary to ensure
that the affected source is complying with the emission limits from the
correct subcategory.
We are requiring additional recordkeeping if you choose to comply
with the chlorine, mercury or total selected metals fuel input option.
You will need to keep records of the calculations and supporting
information used to develop the chlorine, mercury, or total selected
metals fuel input operating limit.
M. How Does the Proposed Rule Affect Permits?
The CAA requires that sources subject to the proposed rule be
operated pursuant to a permit issued under EPA-approved State operating
permit program. The operating permit programs are developed under title
V of the CAA and the implementing regulations under 40 CFR parts 70 and
71. If you are operating in the first 3 years of your operating permit,
you will need to obtain a revised permit to incorporate the proposed
rule. If you are in the last 2 years of your operating permit, you will
need to incorporate the proposed rule into the next renewal of your
permit.
N. What Alternative Provisions Are Being Considered?
The EPA is considering a bubbling compliance alternative for
determining compliance with the non-mercury metallic HAP, HCl, mercury,
and PM standards for existing sources. The bubbling compliance
alternative would allow owners and operators to set non-mercury metals,
mercury, HCl, and PM emissions limits for each existing boiler or
process heater in the same subcategory such that if these limits are
met, the total emissions from all existing boilers or process heaters
in the subcategory are less than or equal to a subcategory specific
bubble limit. The subcategory specific bubble limit would be the
proposed emissions limits for non-mercury metallic HAP, mercury, HCl,
and PM.
The bubbling compliance alternative would not be applicable to new
sources and could only be used between boilers and process heaters in
the same subcategory. For example, bubbling between a solid fuel-fired
boiler greater than 10 million Btu/hour could only be conducted with
other solid fuel-fired boilers or process heaters with heat input
capacities greater than 10 million Btu/hour. Also, owners or owners of
existing sources subject to the Industrial Boiler New Source
Performance Standards (NSPS) (40 CFR part 60, subparts Db and Dc) would
be required to continue to meet the PM emission standard of that NSPS
regardless of whether they are complying with the bubbling alternative
or not (because the NSPS is a separate regulatory requirement which
remains in place).
Owners or operators that would choose to comply with the HAP
metals, mercury, HCl, or PM standards using the bubbling compliance
alternative would be required to submit HAP metals, mercury, HCl, and/
or PM emissions limits to the Administrator for approval for each
existing source included in the bubbling compliance alternative. Before
emissions limits would be approved, the owner or operator would need to
submit documentation demonstrating that if the emissions limits for
each source (e.g., each boiler or heater) are met, the entire group of
sources within the bubbling compliance alternative would be in
compliance with the subcategory-wide allowable non-mercury metallic
HAP, mercury, HCl, and PM emission levels. Once approved by the
Administrator, the non-mercury metallic HAP, mercury, HCl, and PM
emissions levels would be incorporated into the operating permit for
the source. Thereafter, the owner and operator of the facility would
demonstrate compliance with the standards by demonstrating that each
boiler or process heater included in the bubbling compliance
alternative emits less than or equal to the approved non-mercury
metallic HAP, mercury, HCl, and PM emissions limits for that source.
The EPA is considering this bubbling compliance alternative as part
of the EPA's general policy of encouraging the use of flexible
compliance approaches where they can be properly monitored and
enforced. Emissions averaging can provide sources the flexibility to
comply in the least costly manner while still maintaining regulation
that is workable and enforceable. However, to implement this
alternative, the final rule will need to define the affected source
more broadly to include all the existing boilers and process heaters
for each subcategory located at the same facility. Therefore, EPA is
soliciting comments on the bubbling compliance alternative, whether EPA
should specify this bubbling compliance alternative in the final rule,
and whether new units added to an existing affected source should be
included as part of, and applicable to, the existing source bubble
limit. Comments should include information on the potential cost
savings a facility could expect from implementation of the bubbling
compliance provision, along with supporting documentation for this
estimated cost saving.
IV. Impacts of the Proposed Rule
A. What Are the Air Impacts?
Table 2 of this preamble illustrates, for each subcategory, the
emissions reductions achieved by the proposed rule (i.e., the
difference in emissions between a boiler or process heater controlled
to the floor level of control and boilers or process heaters at the
current baseline) for new and existing sources. Nationwide emissions of
[[Page 1687]]
selected HAP (i.e., HCl, hydrogen fluoride, lead, and nickel) will be
reduced by 58,500 tons per year for existing units and 73 tons per year
for new units. Emissions of HCl will be reduced by 42,000 tons per year
for existing units and 72 tons per year for new units. Emissions of
mercury will be reduced by 1.9 tons per year for existing units and
0.006 tons per year for new units. Emissions of PM will be reduced by
565,000 tons per year for existing units and 480 tons per year for new
units. Emissions of total selected non-mercury metals (i.e., arsenic,
beryllium, cadmium, chromium, lead, manganese, nickel, and selenium)
will be reduced by 1,100 tons per year for existing units and will be
reduced by 1.4 tons per year for new units. In addition, emissions of
sulfur dioxide are established to be reduced by 113,000 tons per year
for existing sources and 110 tons per year for new sources. A
discussion of the methodology used to estimate emissions and emissions
reductions is presented in ``Estimation of Baseline Emissions and
Emissions Reductions for Industrial, Commercial, and Institutional
Boilers and Process Heaters'' in the docket.
Table 2.--Summary of Emissions Reductions for Existing and New Sources
[Tons/yr]
----------------------------------------------------------------------------------------------------------------
Non mercury
Source Subcategory HCl PM metals a Mercury
----------------------------------------------------------------------------------------------------------------
Existing Units.................... Large solid units.... 42,100 560,000 1,100 2
Small solid units.... 0 0 0 0
Limited use solid 0 2,800 8 0.002
units.
Liquid units......... 0 0 0 0
Gaseous units........ 0 0 0 0
New Units......................... Large solid units.... 70 31 0.01 0.006
Small solid units.... 2.4 440 1.4 0.0006
Limited use solid 0.2 11 0.02 0.00002
units.
Liquid units......... 0 0 0 0
Gaseous units........ 0 0 0 0
----------------------------------------------------------------------------------------------------------------
a Includes arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium.
B. What Are the Water and Solid Waste Impacts?
The EPA estimated the additional water usage that would result from
the MACT floor level of control to be 110 million gallons per year for
existing sources and 0.6 million gallons per year for new sources. In
addition to the increased water usage, an additional 3.7 million
gallons per year of wastewater would be produced for existing sources
and 0.6 million gallons per year for new sources. The costs of treating
the additional wastewater are $18,000 for existing sources and $2,300
for new sources. These costs are accounted for in the control costs
estimates.
The EPA estimated the additional solid waste that would result from
the MACT floor level of control to be 102,000 tons per year for
existing sources and 1 ton per year for new sources. The costs of
handling the additional solid waste generated are $1.5 million for
existing sources and $17,000 for new sources. These costs are also
accounted for in the control costs estimates.
A discussion of the methodology used to estimate impacts is
presented in ``Estimation of Impacts for Industrial, Commercial, and
Institutional Boilers and Process Heaters NESHAP'' in the Docket.
C. What Are the Energy Impacts?
The EPA expects an increase of approximately 1,130 million kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. Of this amount, 1,120 million kWh would be from existing sources
and 13 million kWh are estimated from new sources. The increase results
from the electricity required to operate control devices installed to
meet the proposed rule, such as wet scrubbers and fabric filters.
D. What Are the Control Costs?
To estimate the national cost impacts of the proposed rule for
existing sources, EPA developed several model boilers and process
heaters and determined the cost of control equipment for these model
boilers. The EPA assigned a model boiler or heater to each existing
unit in the database based on the fuel, size, design, and current
controls. The analysis considered all air pollution control equipment
currently in operation at existing boilers and process heaters. Model
costs were then assigned to all existing units that could not otherwise
meet the proposed emission limits. The resulting total national cost
impact of the proposed rule is 1,790 million dollars in capital
expenditures and 860 million dollars per year in total annual costs.
The total capital and annual costs include costs for testing,
monitoring, and recordkeeping and reporting. Table 3 of this preamble
shows the capital and annual cost impacts for each subcategory. Costs
include testing and monitoring costs, but not recordkeeping and
reporting costs.
Table 3.--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
Estimated/
projected Annualized Capital
Source Subcategory number of cost costs
affected (10\6\ $/ (10\6\ $)
units yr)
----------------------------------------------------------------------------------------------------------------
Existing Units............................ Large solid units............ 3,481 814 1,605
Small solid units............ 327 0 0
Limited use solid units...... 249 23 105
Liquid units................. 7,251 0 0
Gaseous units................ 46,892 0 0
[[Page 1688]]
New Units................................. Large solid units............ 211 10 21
Small solid units............ 25 3 3
Limited use solid units...... 11 1 1
Large liquid units........... 90 1 3
Small liquid units........... 164 0 0
Limited use liquid units..... 51 0.3 2
Gaseous units................ 3,463 11 51
----------------------------------------------------------------------------------------------------------------
Using Department of Energy projections on fuel expenditures, the
number of additional boilers that could be potentially constructed was
estimated. The resulting total national cost impact of the proposed
rule in the 5th year is 58 million dollars in capital expenditures and
18.6 million dollars per year in total annual costs. Costs are mainly
for testing and monitoring.
A discussion of the methodology used to estimate cost impacts is
presented in ``Methodology and Results of Estimating the Cost of
Complying with the Industrial, Commercial, and Institutional Boiler and
Process Heater NESHAP'' in the Docket.
E. Can We Achieve the Goals of the Proposed Rule in a Less Costly
Manner?
We have made every effort in developing this proposal to minimize
the cost to the regulated community and allow maximum flexibility in
compliance options consistent with our statutory obligations. We
recognize, however, that the proposal may still require some facilities
to take costly steps to further control emissions even though those
emissions may not result in exposures which could pose an excess
individual lifetime cancer risk greater than one in one million or
which exceed thresholds determined to provide an ample margin of safety
for protecting public health and the environment from the effects of
hazardous air pollutants. We are, therefore, specifically soliciting
comment on whether there are further ways to structure the proposed
rule to focus on the facilities which pose significant risks and avoid
the imposition of high costs on facilities that pose little risk to
public health and the environment.
Representatives of the plywood and composite wood products industry
provided EPA with descriptions of three mechanisms that they believed
could be used to implement more cost-effective reductions in risk. The
docket for today's proposed rule contains white papers prepared by
industry that outline their proposed approaches. These approaches could
be effective in focusing regulatory controls on facilities that pose
significant risks and avoiding the imposition of high costs on
facilities that pose little risk to public health or the environment,
and we are seeking public comment on the utility of each of these
approaches with respect to this rule.
One of the approaches, an applicability cutoff for threshold
pollutants, would be implemented under the authority of CAA section
112(d)(4); the second approach, subcategorization and delisting, would
be implemented under the authority of CAA sections 112(c)(1) and
112(c)(9); and, the third approach, would involve the use of a
concentration-based applicability threshold. We are seeking comment on
whether these approaches are legally justified and, if so, we ask for
information that could be used to support such approaches.
The maximum achievable control technology, or MACT, program
outlined in CAA section 112(d) is intended to reduce emissions of HAP
through the application of MACT to major sources of toxic air
pollutants. Section 112(c)(9) of the CAA is intended to allow EPA to
avoid setting MACT standards for categories or subcategories of sources
that pose less than a specified level of risk to public health and the
environment. The EPA requests comment on whether the proposals
described here appropriately rely on these provisions of CAA section
112. While both approaches focus on assessing the inhalation exposures
of HAP emitted by a source, EPA specifically requests comment on the
appropriateness and necessity of extending these approaches to account
for non-inhalation exposures or to account for adverse environmental
impacts. In addition to the specific requests for comment noted in this
section, we are also interested in any information or comment
concerning technical limitations, environmental and cost impacts,
compliance assurance, legal rationale, and implementation relevant to
the identified approaches. We also request comment on appropriate
practicable and verifiable methods to ensure that sources' emissions
remain below levels that protect public health and the environment. We
will evaluate all comments before determining whether either of the
three approaches will be included in the final rule.
1. Industry Emissions and Potential Health Effects
To estimate the potential baseline risks posed by the Industrial
Boiler and Process Heater source category, EPA performed a crude risk
analysis of the source category that focused only on cancer risks. The
results of the analysis are based on approaches for estimating cancer
incidence that carry significant assumptions, uncertainties, and
limitations. Based on the assessment, if the proposed rule is
implemented at all facilities in the source category, cancer incidence
in the U.S. may be reduced by as many as tens of cases per year. Due to
the uncertainties associated with the analysis, this analysis should be
regarded as one perspective on the estimate of annual cancer incidence
reduction; the true risk reductions are unknown. (Details of this
assessment are available in two memoranda in the docket: Memorandum on
``Method for Approximate (``Top Down'') Estimates of Aggregate Cancer
Risk Associated with Two Maximum Achievable Control Technology (MACT)
Source Categories: Reciprocating Internal Combustion Engines (RICE) and
Industrial/Commercial/Institutional Boilers'' and Memorandum on
``Additional Perspectives on (``Top Down'') Estimates of Aggregate
Cancer Risk Associated with Industrial/Commercial/Institutional
Boilers''.)
[[Page 1689]]
2. Applicability Cutoffs for Threshold Pollutants Under Section
112(d)(4) of the CAA
The first approach is an applicability cutoff for threshold
pollutants that is based on EPA's authority under CAA section 112(d)(4)
to establish standards for HAP which are threshold pollutants. A
threshold pollutant is one for which there is a concentration or dose
below which adverse effects are not expected to occur over a lifetime
of exposure. For such pollutants, CAA section 112(d)(4) allows EPA to
consider the threshold level, with an ample margin of safety, when
establishing emission standards. Specifically, CAA section 112(d)(4)
allows EPA to establish emission standards that are not based upon the
maximum achievable control technology specified under CAA section
112(d)(2) for pollutants for which a health threshold has been
established. Such standards may be less stringent than MACT.
Historically, EPA has interpreted CAA section 112(d)(4) to allow
categories of sources that emit only threshold pollutants to avoid
further regulation if those emissions result in ambient levels that do
not exceed the threshold, with an ample margin of safety.\2\
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\2\ See 63 FR 18754, 18765-66 (April 15, 1998) (Pulp and Paper
Combustion Sources Proposal NESHAP).
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A different interpretation would allow us to exempt individual
facilities within a source category that meet the CAA section 112(d)(4)
requirements. There are three potential scenarios under this
interpretation of the CAA section 112(d)(4) provision. One scenario
would allow an exemption for individual facilities that emit only
threshold pollutants and can demonstrate that their emissions of
threshold pollutants would not result in air concentrations above the
threshold levels, with an ample margin of safety, even if the category
is otherwise subject to MACT. A second scenario would allow the CAA
section 112(d)(4) provision to be applied to both threshold and
nonthreshold pollutants, using the one in a million cancer risk level
for decision making for nonthreshold pollutants.
A third scenario would allow a CAA section 112(d)(4) exemption at a
facility that emits both threshold and nonthreshold pollutants. For
those emission points where only threshold pollutants are emitted and
where emissions of the threshold pollutants would not result in air
concentrations above the threshold levels, with an ample margin of
safety, those emission points could be exempt from the MACT standard.
The MACT standard would still apply to nonthreshold emissions from
other emission points at the source. For this third scenario, emission
points that emit a combination of threshold and nonthreshold pollutants
that are co-controlled by MACT would still be subject to the MACT level
of control. However, any threshold HAP eligible for exemption under CAA
section 112(d)(4) that are controlled by control devices different from
those controlling non-threshold HAP would be able to use the exemption,
and the facility would still be subject to the parts of the standard
that control nonthreshold pollutants or that control both threshold and
nonthreshold pollutants.
a. Estimation of hazard quotients and hazard indices. Under the CAA
section 112(d)(4) approach, EPA would have to determine that emissions
of each of the threshold pollutants emitted by industrial boiler and
process heater sources at the facility do not result in exposures which
exceed the threshold levels, with an ample margin of safety. The common
approach for evaluating the potential hazard of a threshold air
pollutant is to calculate a hazard quotient by dividing the pollutant's
inhalation exposure concentration (often assumed to be equivalent to
its estimated concentration in air at a location where people could be
exposed) by the pollutant's inhalation Reference Concentration (RfC).
An RfC is defined as an estimate (with uncertainty spanning perhaps an
order of magnitude) of a continuous inhalation exposure that, over a
lifetime, likely would not result in the occurrence of adverse health
effects in humans, including sensitive individuals. The EPA typically
establishes an RfC by applying uncertainty factors to the critical
toxic effect derived from the lowest- or no-observed-adverse-effect
level of a pollutant.\3\ A hazard quotient less than one means that the
exposure concentration of the pollutant is less than the RfC, and,
therefore, presumed to be without appreciable risk of adverse health
effects. A hazard quotient greater than one means that the exposure
concentration of the pollutant is greater than the RfC. Further, EPA
guidance for assessing exposures to mixtures of threshold pollutants
recommends calculating a hazard index (HI) by summing the individual
hazard quotients for those pollutants in the mixture that affect the
same target organ or system by the same mechanism.\4\ Hazard index
values would be interpreted similarly to hazard quotients; values below
one would generally be considered to be without appreciable risk of
adverse health effects, and values above one would generally be cause
for concern.
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\3\ ``Methods for Derivation of Inhalation Reference
Concentrations and Applications of Inhalation Dosimetry.'' EPA-600/
8-90-066F, Office of Research and Development, USEPA, October 1994.
\4\ ``Supplementary Guidance for Conducting Health Risk
Assessment of Chemical Mixtures. Risk Assessment Forum Technical
Panel,'' EPA/630/R-00/002. USEPA, August 2000. http://www.epa.gov/nceawww1/pdfs/chem
mix/chem mix 08 2001.pdf.
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For the determinations discussed herein, EPA would generally plan
to use RfC values contained in EPA's toxicology database, the
Integrated Risk Information System (IRIS). When a pollutant does not
have an approved RfC in IRIS, or when a pollutant is a carcinogen, EPA
would have to determine whether a threshold exists based upon the
availability of specific data on the pollutant's mode or mechanism of
action, potentially using a health threshold value from an alternative
source, such as the Agency for Toxic Substances and Disease Registry
(ATSDR) or the California Environmental Protection Agency (CalEPA).
Table 4 of this preamble provides RfC, as well as unit risk estimates,
for the HAP emitted by facilities in the industrial boiler and process
heater source category. A unit risk estimate is defined as the upper-
bound excess lifetime cancer risk estimated to result from continuous
exposure to an agent at a concentration of 1 microgram per cubic meter
([mu]g/m3) in air.
[[Page 1690]]
Table 4.--Dose-Response Assessment Values for HAP Reported Emitted by the Industrial Boiler and Process Heater
Source Category
----------------------------------------------------------------------------------------------------------------
Reference concentration \a\ Unit risk estimate \b\ (1/
Chemical name CAS No. (mg/m\3\) ([mu]g/m \3\))
----------------------------------------------------------------------------------------------------------------
Acetaldehyde.................... 75-07-0 9.0E-IRIS 03 2.2E-06 IRIS
Acrolein........................ 107-02-8 2.0E-IRIS 05
Arsenic compounds............... 7440-38-2 3.0E-CAL 05 4.3E-03 IRIS
Benzene......................... 71-43-2 6.0E-CAL 02 7.8E-06 IRIS
Beryllium compounds............. 7440-41-7 2.0E-IRIS 05 2.4E-03 IRIS
Cadmium compounds............... 7440-43-9 2.0E-CAL 05 1.8E-03 IRIS
Chromium (VI) compounds......... 18540-29-9 1.0E-IRIS 04 1.2E-02 IRIS
Dibenzofuran.................... 132-64-9
Dibutylphthalate................ 84-74-2
p-Dichlorobenzene............... 106-46-7 8.0E-IRIS 01 1.1E-05 CAL
Ethyl benzene................... 100-41-4 1.0E+0 IRIS 0
Formaldehyde.................... 50-00-0 9.8E-ATSDR 03 1.3E-05 IRIS
Hydrochloric acid............... 7647-01-0 2.0E-IRIS 02
Hydrogen fluoride............... 7664-39-3 3.0E-P-CAL 02
Lead compounds.................. 7439-92-1 1.5E-EPA 03 ORD 1.2E-05 CAL
Manganese compounds............. 7439-96-5 5.0E-IRIS 05
Mercury compounds............... HG--CMPDS 9.0E-CAL 05
Methyl chloroform............... 71-55-6 1.0E+0 CAL 0
Methyl ethyl ketone............. 78-93-3 1.0E+0 IRIS 0
Methylene chloride.............. 75-09-2 1.0E+0 ATSDR 0 4.7E-07 IRIS
Nickel compounds................ 7440-02-0 2.0E-ATSDR 04
Nickel subsulfide............... 12035-72-2 .............................. 4.8E-04 IRIS
PAHs (shown below as 7-PAH)
Benzo (a) anthracene............ 56-55-3 .............................. 1.1E-04 CAL
Benzo (b) fluoranthene.......... 205-99-2 .............................. 1.1E-04 CAL
Benzo (k) fluoranthene.......... 207-08-9 .............................. 1.1E-04 CAL
Benzo (a) pyrene................ 50-32-8 .............................. 1.1E-03 CAL
Chrysene........................ 218-01-9 .............................. 1.1E-05 CAL
Dibenz (a,h) anthracene......... 53-70-3 .............................. 1.2E-03 CAL
Indeno (1,2,3-cd) pyrene........ 193-39-5 .............................. 1.4E-04 CAL
Phosphorus \c\
2,3,7,8-Tetrachlorodibenzo-p- 1746-01-6 4.0E-CAL 08 3.3E+01 EPA ORD
dioxin.
Toluene......................... 108-88-3 4.0E-IRIS 01
m-Xylene \c\.................... 108-38-3
o-Xylene \c\.................... 95-47-6
Xylenes (mixed)................. 1330-20-7 4.3E-ATSDR 01
----------------------------------------------------------------------------------------------------------------
\a\ Reference Concentration: An estimate (with uncertainty spanning perhaps an order of magnitude) of a
continuous inhalation exposure to the human population (including sensitive subgroups which include children,
asthmatics and the elderly) that is likely to be without an appreciable risk of deleterious effects during a
lifetime. It can be derived from various types of human or animal data, with uncertainty factors generally
applied to reflect limitations of the data used.
\b\ Unit Risk Estimate: The upper-bound excess lifetime cancer risk estimated to result from continuous exposure
to an agent at a concentration of 1 [mu]g/m \3\ in air. The interpretation of the Unit Risk Estimate would be
as follows: if the Unit Risk Estimate = 1.5 x 10-6 per [mu]g/m \3\, 1.5 excess tumors are expected to develop
per 1,000,000 people if exposed daily for a lifetime to 1 [mu]g of the chemical in 1 cubic meter of air. Unit
Risk Estimates are considered upper bound estimates, meaning they represent a plausible upper limit to the
true value. (Note that this is usually not a true statistical confidence limit.) The true risk is likely to be
less, but could be greater.
\c\ No dose-response assessment is available.
Sources:
IRIS = EPA Integrated Risk Information System (http://www.epa.gov/iris/subst/index.html).
ATSDR = U.S. Agency for Toxic Substances and Disease Registry (http://www.atsdr.cdc.gov/mrls.html).
CAL = California Office of Environmental Health Hazard Assessment (http://www.oehha.ca.gov/air/hot_spots/
index.html).
To establish an applicability cutoff under CAA section 112(d)(4),
EPA would need to define ambient air exposure concentration limits for
any threshold pollutants involved. There are several factors to
consider when establishing such concentrations. First, we would need to
ensure that the concentrations that would be established would protect
public health with an ample margin of safety. As discussed above, the
approach EPA commonly uses when evaluating the potential hazard of a
threshold air pollutant is to calculate the pollutant's hazard
quotient, which is the exposure concentration divided by the RfC.
EPA's ``Supplementary Guidance for Conducting Health Risk
Assessment of Chemical Mixtures'' suggests that the noncancer health
effects associated with a mixture of pollutants ideally are assessed by
considering the pollutants' common mechanisms of toxicity. The guidance
also suggests, however, that when exposures to mixtures of pollutants
are being evaluated, the risk assessor may calculate a HI. The
recommended method is to calculate multiple hazard indices for each
exposure route of interest, and for a single specific toxic effect or
toxicity to a single target organ. The default approach recommended by
the guidance is to sum the hazard quotients for those pollutants that
induce the same toxic effect or affect the same target organ. A mixture
is then assessed by several HI, each representing one toxic effect or
target organ. The guidance notes that the pollutants included in the HI
calculation are any pollutants that show the effect being assessed,
regardless of the critical effect upon which the RfC is based. The
guidance cautions that if the
[[Page 1691]]
target organ or toxic effect for which the HI is calculated is
different from the RfC's critical effect, then the RfC for that
chemical will be an overestimate, that is, the resultant HI potentially
may be overprotective. Conversely, since the calculation of an HI does
not account for the fact that the potency of a mixture of HAP can be
more potent than the sum of the individual HAP potencies, an HI may
potentially be underprotective in some situations.
b. Options for establishing a hazard index limit. One consideration
in establishing a hazard index limit is whether the analysis considers
the total ambient air concentrations of all the emitted HAP to which
the public is exposed.\5\ There are at least several options for
establishing a hazard index limit for the CAA section 112(d)(4)
analysis that reflect, to varying degrees, public exposure.
---------------------------------------------------------------------------
\5\ Senate Debate on Conference Report (October 27, 1990),
reprinted in ``A Legislative History of the Clean Air Act Amendments
of 1990,'' Comm. Print S. Prt. 103-38 (1993) (``Legis. Hist.'') at
868.
---------------------------------------------------------------------------
One option is to allow the hazard index posed by all threshold HAP
emitted from sources at the facility to be no greater than one. This
approach is protective if no additional threshold HAP exposures would
be anticipated from other sources in the vicinity of the facility or
through other routes of exposure (e.g., through ingestion).
A second option is to adopt a default percentage approach, whereby
the hazard index limit of the HAP emitted by the facility is set at
some percentage of one (e.g., 20 percent or 0.2). This approach
recognizes the fact that the facility in question is only one of many
sources of threshold HAP to which people are typically exposed every
day. Because noncancer risk assessment is predicated on total exposure
or dose, and because risk assessments focus only on an individual
source, establishing a hazard index limit of 0.2 would account for an
assumption that 20 percent of an individual's total exposure is from
that individual source. For the purposes of this discussion, we will
call all sources of HAP, other than the facility in question,
background sources. If the facility is allowed to emit HAP such that
its own impacts could result in HI values of one, total exposures to
threshold HAP in the vicinity of the facility could be substantially
greater than one due to background sources, and this would not be
protective of public health, since only HI values below one are
considered to be without appreciable risk of adverse health effects.
Thus, setting the hazard index limit for the facility at some default
percentage of one will provide a buffer which would help to ensure that
total exposures to threshold HAP near the facility (i.e., in
combination with exposures due to background sources) will generally
not exceed one, and can generally be considered to be without
appreciable risk of adverse health effects.
The EPA requests comment on using the default percentage approach
and on setting the default hazard index limit at 0.2. The EPA is also
requesting comment on whether an alternative HI limit, in some multiple
of one would be a more appropriate applicability cutoff.
A third option is to use available data (from scientific literature
or EPA studies, for example) to determine background concentrations of
HAP, possibly on a national or regional basis. These data would be used
to estimate the exposures to HAP from non-industrial boiler and process
heater sources in the vicinity of an individual facility. For example,
the EPA's National-scale Air Toxics Assessment (NATA) \6\ and ATSDR's
Toxicological Profiles \7\ contain information about background
concentrations of some HAP in the atmosphere and other media. The
combined exposures from these sources and from other sources (as
determined from the literature or studies) would then not be allowed to
exceed a hazard index limit of one. The EPA requests comment on the
appropriateness of setting the hazard index limit at one for such an
analysis.
---------------------------------------------------------------------------
\6\ See http://www.epa.gov/ttn/atw/nata.
\7\ See http://www.atsdr.cdc.gov/toxpro2.html.
---------------------------------------------------------------------------
A fourth option is to allow facilities to estimate or measure their
own facility-specific background HAP concentrations for use in their
analysis. With regard to the third and fourth options, the EPA requests
comment on how these analyses could be structured. Specifically, EPA
requests comment on how the analyses should take into account
background exposure levels from air, water, food and soil encountered
by the individuals exposed to emissions from industrial boilers and
process heaters. In addition, we request comment on how such analyses
should account for potential increases in exposures due to the use of
new HAP or the increased use of a previously emitted HAP, or the effect
of other nearby sources that release HAP.
EPA requests comment on the feasibility and scientific validity of
each of these or other approaches. Finally, EPA requests comment on how
we should implement the CAA section 112(d)(4) applicability cutoffs,
including appropriate mechanisms for applying cutoffs to individual
facilities. For example, would the title V permit process provide an
appropriate mechanism?
c. Tiered analytical approach for predicting exposure. Establishing
that a facility meets the cutoffs established under CAA section
112(d)(4) will necessarily involve combining estimates of pollutant
emissions with air dispersion modeling to predict exposures. The EPA
envisions that we would promote a tiered analytical approach for these
determinations. A tiered analysis involves making successive
refinements in modeling methodologies and input data to derive
successively less conservative, more realistic estimates of pollutant
concentrations in air and estimates of risk.
As a first tier of analysis, EPA could develop a series of simple
look-up tables based on the results of air dispersion modeling
conducted using conservative input assumptions. By specifying a limited
number of input parameters, such as stack height, distance to property
line, and emission rate, a facility could use these look-up tables to
determine easily whether the emissions from their sources might cause a
hazard index limit to be exceeded.
A facility that does not pass this initial conservative screening
analysis could implement increasingly more site-specific but more
resource-intensive tiers of analysis using EPA-approved modeling
procedures, in an attempt to demonstrate that exposure to emissions
from the facility does not exceed the hazard index limit. The EPA's
guidance could provide the basis for conducting such a tiered
analysis.\8\
---------------------------------------------------------------------------
\8\ ``A Tiered Modeling Approach for Assessing the Risks due to
Sources of Hazardous Air Pollutants.'' EPA-450/4-92-001. David E.
Guinnup, Office of Air Quality Planning and Standards, USEPA, March
1992.
---------------------------------------------------------------------------
The EPA requests comment on methods for constructing and
implementing a tiered analytical approach for determining applicability
of the CAA section 112(d)(4) criterion to specific industrial boiler
and process heater sources. It is also possible that ambient monitoring
data could be used to supplement or supplant the tiered modeling
approach described above. It is envisioned that the appropriate
monitoring to support such a determination could be extensive. The EPA
requests comment on the appropriate use of monitoring in the
determinations described above.
d. Accounting for dose-response relationships. In the past, EPA
routinely treated carcinogens as nonthreshold pollutants. The EPA
recognizes that
[[Page 1692]]
advances in risk assessment science and policy may affect the way EPA
differentiates between threshold and nonthreshold HAP. The EPA's draft
Guidelines for Carcinogen Risk Assessment \9\ suggest that carcinogens
be assigned non-linear dose-response relationships where data warrant.
Moreover, it is possible that dose-response curves for some pollutants
may reach zero risk at a dose greater than zero, creating a threshold
for carcinogenic effects. It is possible that future evaluations of the
carcinogens emitted by this source category would determine that one or
more of the carcinogens in the category is a threshold carcinogen or is
a carcinogen that exhibits a non-linear dose-response relationship but
does not have a threshold.
---------------------------------------------------------------------------
\9\ ``Draft Revised Guidelines for Carcinogen Risk Assessment.''
NCEA-F-0644. USEPA, Risk Assessment Forum, July 1999. pp 3-9ff.
http://www.epa.gov/ncea/raf/pdfs/cancer_gls.pdf.
---------------------------------------------------------------------------
The dose-response assessments for formaldehyde and acetaldehyde are
currently undergoing revision by the EPA. As part of this revision
effort, EPA is evaluating formaldehyde and acetaldehyde as potential
non-linear carcinogens. The revised dose-response assessments will be
subject to review by the EPA Science Advisory Board, followed by full
consensus review, before adoption into the EPA Integrated Risk
Information System. At this time, EPA estimates that the consensus
review will be completed by the end of 2003. The revision of the dose-
response assessments could affect the potency factors of these HAP, as
well as their status as threshold or nonthreshold pollutants. At this
time, the outcome is not known. In addition to the current reassessment
by EPA, there have been several reassessments of the toxicity and
carcinogenicity of formaldehyde in recent years, including work by the
World Health Organization and the Canadian Ministry of Health.
The EPA requests comment on how we should consider the state of the
science as it relates to the treatment of threshold pollutants when
making determinations under CAA section 112(d)(4). In addition, EPA
requests comment on whether there is a level of emissions of a
nonthreshold carcinogenic HAP (e.g., benzene, methylene chloride) at
which it would be appropriate to allow a facility to use the approaches
discussed in this section.
If the CAA section 112(d)(4) approach were adopted, the proposed
rulemaking would likely indicate that the requirements of the rule do
not apply to any source that demonstrates, based on a tiered approach
that includes EPA-approved modeling of the affected source's emissions,
that the anticipated HAP exposures do not exceed the specified hazard
index limit.
3. Applicability Cutoffs From Hydrogen Chloride Controls Under CAA
Section 112(d)(4) of the CAA
This approach is an applicability cutoff for the threshold
pollutant hydrogen chloride that is based on EPA's authority under CAA
section 112(d)(4). Industry's suggested approach interprets this
provision to allow EPA to exempt, from the hydrogen chloride controls,
individual facilities that can demonstrate that their emissions of
hydrogen chloride will not result in air concentrations above the
inhalation reference concentration for hydrogen chloride, even if the
category is otherwise subject to MACT.
If this approach were adopted, the proposed rulemaking would likely
indicate that the requirements of the rule pertaining to hydrochloric
acid do not apply to any source that demonstrates, based on EPA-
approved modeling of the affected source's emissions, that the
anticipated hydrochloric acid exposures do not exceed the inhalation
reference concentration for hydrochloric acid.
4. Subcategory Delisting Under Section 112(c)(9)(B) of the CAA
The EPA is authorized to establish categories and subcategories of
sources, as appropriate, pursuant to CAA section 112(c)(1), in order to
facilitate the development of MACT standards consistent with section
112 of the CAA. Further, CAA section 112(c)(9)(B) allows EPA to delete
a category (or subcategory) from the list of major sources for which
MACT standards are to be developed when the following can be
demonstrated: (1) In the case of carcinogenic pollutants, that ``no
source in the category * * * emits (carcinogenic) air pollutants in
quantities which may cause a lifetime risk of cancer greater than one
in one million to the individual in the population who is most exposed
to emissions of such pollutants from the source''; (2) in the case of
pollutants that cause adverse noncancer health effects, that
``emissions from no source in the category or subcategory * * * exceed
a level which is adequate to protect public health with an ample margin
of safety''; and (3) in the case of pollutants that cause adverse
environmental effects, that ``no adverse environmental effect will
result from emissions from any source.''
Given these authorities and the suggestions from the white paper
prepared by industry representatives (see docket number OAR-2002-0058),
EPA is considering whether it would be possible to establish a
subcategory of facilities within the larger industrial boiler and
process heater source category that would meet the risk-based criteria
for delisting. Such criteria would likely include the same requirements
as described previously for the second scenario under the CAA section
112(d)(4) approach, whereby a facility would be in the low-risk
subcategory if its emissions of threshold pollutants do not result in
exposures which exceed the HI limits and if its emissions of
nonthreshold pollutants do not result in exposures which exceed a
cancer risk level of 10-6. The EPA requests comment on what
an appropriate HI limit would be for a determination that a facility be
included in the low-risk subcategory.
Since each facility in such a subcategory would be a low-risk
facility (i.e., if each met these criteria), the subcategory could be
delisted in accordance with CAA section 112(c)(9), thereby limiting the
costs and impacts of the proposed rule to only those facilities that do
not qualify for subcategorization and delisting.
Facilities seeking to be included in the delisted subcategory would
be responsible for providing all data required to determine whether
they are eligible for inclusion. Facilities that could not demonstrate
that they are eligible to be included in the low-risk subcategory would
be subject to MACT and possible future residual risk standards. The EPA
solicits comment on implementing a risk-based approach for establishing
subcategories of industrial boiler and process heater facilities.
Establishing that a facility qualifies for the low-risk subcategory
under CAA section 112(c)(9) will necessarily involve combining
estimates of pollutant emissions with air dispersion modeling to
predict exposures. The EPA envisions that we would employ the same
tiered analytical approach described earlier in the CAA section
112(d)(4) discussion for these determinations.
One concern that EPA has with respect to this CAA section 112(c)(9)
approach is the effect that it could have on the MACT floors. If many
of the facilities in the low-risk subcategory are well-controlled, that
could make the MACT floor less stringent for the remaining facilities.
One approach that has been suggested to mitigate this effect would be
to establish the MACT floor now based on controls in place for the
[[Page 1693]]
entire category and to allow facilities to become part of the low-risk
subcategory in the future, after the MACT based standards are
established. This would allow low risk facilities to use the CAA
section 112(c)(9) exemption without affecting the MACT floor
calculation. The EPA requests comment on this suggested approach.
Another approach under CAA section 112(c)(9) would be to define a
subcategory of facilities within the industrial boiler and process
heater source category based upon technological differences, such as
differences in production rate, emission vent flow-rates, overall
facility size, emissions characteristics, processes, or air pollution
control device viability. The EPA requests comment on how we might
establish industrial boiler and process heater subcategories based on
these, or other, source characteristics. If it could then be determined
that each source in this technologically-defined subcategory presents a
low risk to the surrounding community, the subcategory could then be
delisted in accordance with CAA section 112(c)(9). The EPA requests
comment on the concept of identifying technologically-based
subcategories that may include only low-risk facilities within this
source category.
If this CAA section 112(c)(9) approach were adopted, the rulemaking
would likely indicate that the rule does not apply to any source that
demonstrates that it belongs in a subcategory which has been delisted
under CAA section 112(c)(9).
F. What Are the Economic Impacts?
The economic impact analysis shows that the expected price increase
for output in the 40 affected industries would be no more than 0.04
percent as a result of the proposed rule for industrial boilers and
process heaters. The expected change in production of affected output
is a reduction of only 0.03 percent or less in the same industries. In
addition, impacts to affected energy markets show that prices of
petroleum, natural gas, electricity and coal should increase by no more
than 0.05 percent as a result of implementation of the proposed rule,
and output of these types of energy should decrease by no more than
0.01 percent. Therefore, it is likely that there is no adverse impact
expected to occur for those industries that produce output affected by
the proposed rule, such as lumber and wood products, chemical
manufacturers, petroleum refining, and furniture manufacturing.
G. What Are the Social Costs and Benefits of the Proposed Rule?
Our assessment of costs and benefits of the proposed rule is
detailed in the ``Regulatory Impact Analysis for the Proposed
Industrial, Commercial, and Institutional Boilers and Process Heaters
MACT.'' The Regulatory Impact Analysis (RIA) is located in the Docket.
It is estimated that 3 years after implementation of the proposed
requirements, HAP would be reduced by 58,500 tons/yr (53,200 megagrams
per year (Mg/yr)) due to reductions in hydrochloric acid, arsenic,
mercury, hydrofluoric acid, and several other HAP from existing
affected emission sources. Of these reductions, 42,000 tons/yr (38,200
Mg/yr) are of hydrochloric acid. In addition to these reductions, there
are 73 tons/yr (66 Mg/yr) of HAP reductions expected from new sources.
Of these reductions, virtually all of them are of hydrochloric acid.
The health effects associated with these HAP are discussed earlier in
this preamble. While it is beneficial to society to reduce these HAP,
we are unable to quantify and provide a monetized estimate of the
benefits at this time.
Despite our inability to quantify and provide monetized benefit
estimates from HAP reductions, it is possible to derive rough estimates
for one of the more important benefit categories, i.e., the potential
number of cancer cases avoided and cancer risk reduced as a result of
the imposition of the MACT level of control on this source category.
Our analysis suggests that imposition of the MACT level of control
would reduce cancer cases by possibly tens of cases per year, on
average, starting some years after implementation of the standard. This
risk reduction estimate is uncertain and should be regarded as an
extremely rough estimate, and should be viewed in the context of the
full spectrum of unquantified noncancer effects associated with the HAP
reductions. Noncancer effects associated with the HAP are presented
earlier in this preamble.
The control technologies used to reduce the level of HAP emitted
from affected sources are also expected to reduce emissions of PM
(PM10, PM2.5), and sulfur dioxide
(SO2). It is estimated that PM10 emissions
reductions total approximately 562,000 tons/yr (510,000 Mg/yr),
PM2.5 emissions reductions total approximately 159,000 tons/
yr (145,000 Mg/yr), and SO2 emissions reductions total
approximately 102,670 Mg/yr (113,000 tons/yr). These estimated
reductions occur from existing sources in operation 3 years after the
implementation of the requirements of the proposed rule and are
expected to continue throughout the life of the sources.
Human health effects associated with exposure to PM10
and PM2.5 include premature mortality (short-term exposure
to PM10 and long-term exposure to PM2.5), chronic
bronchitis, additional hospital admissions from respiratory and
cardiovascular causes, acute respiratory symptoms, and other effects.
Welfare effects associated with PM10 and PM2.5
emissions include impaired recreational and residential visibility,
household soiling, and materials damage. As SO2 emissions
transform into PM, they can lead to the same health and welfare effects
listed above.
For PM10 and PM2.5, we did provide a monetary
estimate for the benefits associated with the reduction of the
emissions, and we have conducted several analyses recently that
estimate the monetized benefits of PM reductions, including: the RIA of
the PM/Ozone national ambient air quality standards (NAAQS) (1997), the
Nitrogen Oxide (NOX) State Implementation Plan (SIP) Call
(1998), the CAA section 126 RIA (1999), a study conducted for section
812(b) of the CAA (1999), the Tier 2/Gasoline Sulfur Standards (1999),
and the Heavy Duty Engine/Diesel Fuel Standards (2000).
On September 26, 2002, the National Academy of Sciences (NAS)
released a report on its review of the Agency's methodology for
analyzing the health benefits of measures taken to reduce air
pollution. The report focused on EPA's approach for estimating the
health benefits of regulations designed to reduce concentrations of
airborne particulate matter (PM).
In its report, the NAS said that EPA has generally used a
reasonable framework for analyzing the health benefits of PM-control
measures. It recommended, however, that the Agency take a number of
steps to improve its benefits analysis. In particular, the NAS stated
that the Agency should:
--Include benefits estimates for a range of regulatory options;
--Estimate benefits for intervals, such as every 5 years, rather than a
single year;
--Clearly state the projected baseline statistics used in estimating
health benefits, including those for air emissions, air quality, and
health outcomes;
--Examine whether implementation of proposed regulations might cause
unintended impacts on human health or the environment;
[[Page 1694]]
--When appropriate, use data from non-U.S. studies to broaden age
ranges to which current estimates apply and to include more types of
relevant health outcomes; and
--Begin to move the assessment of uncertainties from its ancillary
analyses into its primary analyses by conducting probabilistic,
multiple-source uncertainty analyses. This assessment should be based
on available data and expert judgment.
Although the NAS made a number of recommendations for improvement
in EPA's approach, it found that the studies selected by EPA for use in
its benefits analysis were generally reasonable choices. In particular,
the NAS agreed with EPA's decision to use cohort studies to derive
benefits estimates. It also concluded that the Agency's selection of
the American Cancer Society (ACS) study for the evaluation of PM-
related premature mortality was reasonable, although it noted the
publication of new cohort studies that should be evaluated by the
Agency.
Several of the NAS recommendations addressed the issue of
uncertainty and how the Agency can better analyze and communicate the
uncertainties associated with its benefits assessments. In particular,
the Committee expressed concern about the Agency's reliance on a single
value from its analysis and suggested that EPA develop a probabilistic
approach for analyzing the health benefits of proposed regulatory
actions. The Agency agrees with this suggestion and is working to
develop such an approach for use in future rulemakings.
In this benefits analysis for the proposed rule, the Agency has
used an interim approach that shows the impact of several important
alternative assumptions about the estimation and valuation of
reductions in premature mortality and chronic bronchitis. This
approach, which was developed in the context of the Agency's Clear
Skies analysis, provides an alternative estimate of health benefits
using the time series studies in place of cohort studies, as well as
alternative valuation methods for mortality and chronic bronchitis risk
reductions.
For the proposed rule, we conducted an air quality assessment to
determine the change in ambient concentrations of PM10 and
PM2.5 that result from reductions of PM and SO2
at existing affected facilities. Our air quality analysis was conducted
using the source-receptor (S-R) matrix model, a model that provides
changes in PM10 and PM2.5 concentrations based on
changes in PM and/or PM precursor emissions. Unfortunately, our data is
not able to define the exact location of the reductions for every
affected boiler and process heater. The air quality analysis was
conducted for emissions reductions from those emissions sources that
have a known link to a specific control device, which represents
approximately 50 percent of the total emissions reductions mentioned
above. Using this subset of information, we utilized the S-R matrix to
determined the air quality change nationwide. The results of the air
quality assessment served as input to a model that estimates the total
monetary value of benefits of the health effects listed above. Total
benefits associated with this portion of the analysis are $8.2 billion
in the year 2005 (presented in 1999 dollars).
For those emissions reductions from affected sources that do not
have a known link to a specific control device, the results of the air
quality analysis serve as a reasonable approximation of air quality
changes to transfer to the remaining emissions reductions of the
proposed rule. Because there is not a reasonable way to apportion the
total benefits of the combined impact of the PM and SO2
reductions from the air quality and benefit analyses completed above,
we performed two additional S-R matrix analyses. One analysis was
performed to evaluate the impact on air quality of the PM reductions
alone (holding SO2 unchanged), and one to evaluate the
impact on air quality from the SO2 reductions alone (holding
PM unchanged). With independent PM and SO2 air quality
assessments, we can determine the total benefit associated with each
component of total pollutant reductions. The total benefit associated
with the PM and SO2 reductions with unspecified location are
$7.9 billion.
Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited to some
extent by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Deficiencies in the scientific literature often result in the inability
to estimate changes in health and environmental effects, such as
potential increases in premature mortality associated with increased
exposure to carbon monoxide. Deficiencies in the economics literature
often result in the inability to assign economic values even to those
health and environmental outcomes which can be quantified. While these
general uncertainties in the underlying scientific and economics
literatures are discussed in detail in the RIA and its supporting
documents and references, the key uncertainties which have a bearing on
the results of the benefit-cost analysis of today's action are the
following:
1. The exclusion of potentially significant benefit categories
(e.g., health and ecological benefits of reduction in hazardous air
pollutants emissions);
2. Errors in measurement and projection for variables such as
population growth;
3. Uncertainties in the estimation of future year emissions
inventories and air quality;
4. Uncertainties associated with the extrapolation of air quality
monitoring data to some unmonitored areas required to better capture
the effects of the standards on the affected population;
5. Variability in the estimated relationships of health and welfare
effects to changes in pollutant concentrations; and
6. Uncertainties associated with the benefit transfer approach.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the industrial boilers and process heaters MACT under two different
sets of assumptions.
We have used two approaches (base and alternative estimates) to
provide benefits in health effects and in monetary terms. They differ
in the method used to estimate and value reduced incidences of
mortality and chronic bronchitis, which is explained in detail in the
RIA. While there is a substantial difference in the specific estimates,
both approaches show that the industrial boilers and process heaters
MACT may provide benefits to public health, whether expressed as health
improvements or as economic benefits. These include prolonging lives,
reducing cases of chronic bronchitis and hospital admissions, and
reducing thousands of cases in other indicators of adverse health
effects, such as work loss days, restricted activity days, and days
with asthma attacks. In addition, there are a number of health and
environmental effects which we were unable to quantify or monetize.
These effects, denoted by ``B'' are additive to the both the base and
alternative estimates of benefits. Results also reflect the use of two
different discount rates for the valuation of reduced incidences of
mortality; a 3 percent rate which is recommended by EPA's Guidelines
for Preparing Economic Analyses (U.S.
[[Page 1695]]
EPA, 2000a), and 7 percent which is recommended by OMB Circular A-94
(OMB, 1992).
More specifically, the base estimate of benefits reflects the use
of peer-reviewed methodologies developed for earlier risk and benefit-
cost assessments related to the Clean Air Act, such as the regulatory
assessments of the Heavy Duty Diesel and Tier II rules and the section
812 Report to Congress. The alternative estimate explores important
aspects of the key elements underlying estimates of the benefits of
reducing PM and SO2 emissions, specifically focusing on
estimation and valuation of mortality risk reduction and valuation of
chronic bronchitis. The alternative estimate of mortality reduction
relies on recent scientific studies finding an association between
increased mortality and short-term exposure to particulate matter over
days to weeks, while the base estimate relies on a recent reanalysis of
earlier studies that associate long-term exposure to fine particles
with increased mortality. The alternative estimate differs in the
following ways: it explicitly omits any impact of long-term exposure on
premature mortality, it uses different data on valuation and makes
adjustments relating to the health status and potential longevity of
the populations most likely affected by PM, it also uses a cost-of-
illness method to value reductions in cases of chronic bronchitis while
the base estimate is based on individual's willingness to pay (WTP) to
avoid a case of chronic bronchitis. In addition, one key area of
uncertainty is the value of a statistical life (VSL) for risk
reductions in mortality, which is also the category of benefits that
accounts for a large portion of the total benefit estimate. The
adoption of a value for the projected reduction in the risk of
premature mortality is the subject of continuing discussion within the
economic and public policy analysis community. There is general
agreement that the value to an individual of a reduction in mortality
risk can vary based on several factors, including the age of the
individual, the type of risk, the level of control the individual has
over the risk, the individual's attitude toward risk, and the health
status of the individual.
The Environmental Economics Advisory Committee (EEAC) of the EPA
Science Advisory Board (SAB) recently issued an advisory report which
states that ``the theoretically appropriate method is to calculate
willingness to pay for individuals whose ages correspond to those of
the affected population, and that it is preferable to base these
calculations on empirical estimates of WTP by age.'' (EPA-SAB-EEAC-00-
013). In developing our base estimate of the benefits of premature
mortality reductions, we have appropriately discounted over the lag
period between exposure and premature mortality. However, the empirical
basis for adjusting the current $6 million VSL for other factors does
not yet justify including these in our base estimate. A discussion of
these factors is contained in the RIA and supporting documents. The EPA
recognizes the need for additional research by the scientific community
to develop additional empirical support for adjustments to VSL for the
factors mentioned above. Furthermore, EPA prefers not to draw
distinctions in the monetary value assigned to the lives saved even if
they differ in age, health status, socioeconomic status, gender or
other characteristic of the adult population.
Given the advice from the SAB, we employed the suggested approach
for the benefit analysis of the Heavy Duty Engine/Diesel Fuel standards
conducted in 2000 to the Industrial, Commercial, and Institutional
Boiler and Process Heater MACT discussed in this preamble. A full
discussion of considerations made in our presentation of benefits is
summarized in the preamble of the Final Heavy Duty Diesel Program
issued in December 2000, and in all supporting documentation and
analyses of the Heavy Duty Diesel Program, and in the RIA for the
proposed rulemaking.
In addition to the presentation of mortality valuation, our
estimate also includes a ``B'' to represent those additional health and
environmental benefits which could not be expressed in quantitative
incidence and/or economic value terms. A full listing of the benefit
categories that could not be quantified or monetized in our estimate
are provided in the RIA for the proposed rule. A full appreciation of
the overall economic consequences of the proposed industrial boiler and
process heater standards requires consideration of all benefits and
costs expected to result from today's proposed rule, not just those
benefits and costs which could be expressed here in dollar terms. A
full listing of the benefit categories that could not be quantified or
monetized in our estimate are provided in Table 5 of this preamble.
Table 5.--Unquantified Benefit Categories
------------------------------------------------------------------------
Unquantified
Unquantified benefit benefit
categories associated categories
with HAP associated with
PM
------------------------------------------------------------------------
Health Categories........... Airway responsiveness Changes in
Pulmonary inflammation pulmonary
Increased susceptibility function.
to respiratory infection Morphological
Acute inflammation and changes.
respiratory cell damage Altered host
Chronic respiratory defense
damage/Premature aging mechanisms.
of lungs Cancer.
Emergency room visits for Other chronic
asthma respiratory
disease.
Emergency room
visits for
asthma.
Emergency room
visits for non-
asthma
respiratory
and
cardiovascular
causes.
Lower and upper
respiratory
symptoms.
Acute
bronchitis.
Shortness of
breath.
Increased
school absence
rates.
Welfare Categories.......... Ecosystem and vegetation Materials
effects damage.
Damage to urban Damage to
ornamentals (e.g., ecosystems
grass, flowers, shrubs, (e.g., acid
and trees in urban sulfate
areas) deposition).
Commercial field crops Nitrates in
Fruit and vegetable crops drinking
Reduced yields of tree water.
seedlings, commercial Visibility in
and non- commercial recreational
forests and
Damage to ecosystems residential
Materials damage areas.
------------------------------------------------------------------------
[[Page 1696]]
In summary, the base estimate using the VSL approach yields a total
monetized benefit estimate of $16.1 billion + B (1999 dollars) in 2005
when using a 3 percent interest rate (or approximately $15.4 billion +
B when using a 7 percent interest rate). The alternative estimate
totals approximately $2.4 billion + B when using a 3 percent interest
rate (or approximately $2.6 billion + B when using a 7 percent interest
rate).
Using the results of the benefit analysis, we can use benefit-cost
comparison (or net benefits) as another tool to evaluate the
reallocation of society's resources needed to address the pollution
externality created by the operation of industrial boilers and process
heaters. The additional costs of internalizing the pollution produced
at major sources of emissions from industrial boilers and process
heaters are compared to the improvement in society's well-being from a
cleaner and healthier environment. Comparing benefits of the proposed
rule to the costs imposed by alternative ways to control emissions
optimally identifies a strategy that results in the highest net benefit
to society. In the case of the proposed rule, we are proposing only one
option, the minimal level of control mandated by the CAA, or the MACT
floor. Other alternatives that lead to higher levels of control (or
beyond-the-floor alternatives) lead to higher estimates of benefits net
of costs, but also lead to additional economic impacts including more
substantial impacts to small entities. For more details, please refer
to the RIA for the proposed rule.
Table 6 of this preamble presents a summary of costs, benefits, and
net benefits (i.e., benefits minus costs). Based on estimated
compliance costs associated with the proposed rule and the predicted
change in prices and production in the affected industries, the
estimated social costs of the proposed rule are $780 million (1999
dollars). Social costs are different from compliance costs in that
social costs take into account the interactions between affected
producers and the consumers of affected products in response to the
imposition of the compliance costs.
Therefore, the Agency's base estimate of monetized benefits net of
costs is $15.2 billion + B (1999 dollars) in 2005 when using a 3
percent discount rate (or approximately $15 billion + B when using a 7
percent discount rate). However, using the more conservative
alternative estimate of benefits, net benefits are $1.5 billion + B
(1999 dollars) under a 3 percent discount rate (or approximately $1.7
billion + B when using a 7 percent discount rate).
In both cases, net benefits would be greater if all the benefits of
the HAP and other pollutant reductions could be quantified. Notable
omissions to the net benefits include all benefits of HAP reductions,
including reduced cancer incidences, toxic morbidity effects, and
cardiovascular and CNS effects. It is also important to note that not
all benefits of SO2 and PM reductions have been monetized.
Table 6.--Annual Net Benefits of the Industrial Boilers and Process
Heaters NESHAP in 2005 A
------------------------------------------------------------------------
Beyond the MACT
MACT floor floor (million
(million 1999$) 1999$)
------------------------------------------------------------------------
Social Costs B................. $837.............. $1,923
Social Benefits: B, C, D
HAP-related health and Not monetized..... Not monetized.
welfare benefits.
PM-related welfare benefits Not monetized..... Not monetized.
SO2- and PM-related health
benefits:
Primary Estimate
--Using 3% Discount Rate... $16,300 + B....... $17,230 + B.
Using 7% Discount Rate..... $15,430 + B....... $16,310 + B.
Alternative Estimate
--Using 3% Discount Rate... $2,350 + B........ $2,380 + B.
--Using 7% Discount Rate... $2,585 + B........ $2,620 + B.
Net Benefits (Benefits -Costs):
C, D
Primary Estimate
--Using 3% Discount Rate... $15,465........... $15,305 + B.
--Using 7% Discount Rate... $14,595........... $14,385 + B.
Alternative Estimate
--Using 3% Discount Rate... $1,515............ $455 + B.
--Using 7% Discount Rate... $1,750............ $700 + B.
------------------------------------------------------------------------
A All costs and benefits are rounded to the nearest $5 million. Thus,
figures presented in this table may not exactly equal benefit and cost
numbers presented in earlier sections of the chapter.
B Note that costs are the total costs of reducing all pollutants,
including HAP as well as SO2 and PM10. Benefits in this table are
associated only with PM and SO2 reductions.
C Not all possible benefits or disbenefits are quantified and monetized
in this analysis. Potential benefit categories that have not been
quantified and monetized are listed in Table 8-13. B is the sum of all
unquantified benefits and disbenefits.
D Monetized benefits are presented using two different discount rates.
Results calculated using 3 percent discount rate are recommended by
EPA's Guidelines for Preparing Economic Analyses (U.S. EPA, 2000a).
Results calculated using 7 percent discount rate are recommended by
OMB Circular A-94 (OMB, 1992).
V. Public Participation and Requests for Comment
The ICCR Federal Advisory Committee (i.e., the Coordinating
Committee), which is discussed previously in this preamble, was
designed and created to foster active participation from stakeholders,
including environmental groups, regulated industries, local
governments, Federal agencies, and State and local regulatory agencies.
The stakeholders were able to participate in the development of FACA
committee recommendations on many regulatory issues.
The ICCR Coordinating Committee also encouraged the public to
provide
[[Page 1697]]
input on its data and recommendations throughout the 2-year charter.
To enhance the public's ability to participate, EPA maintained a
bulletin board on the Technology Transfer Network to disseminate
information on the ICCR Coordinating Committee and Work Group meeting
schedules and minutes, works in progress, and final recommendations.
The public could submit comments on any information posted on the
bulletin board to members of the ICCR Coordinating Committee or Work
Group. Individuals could also attend the ICCR Coordinating Committee
and Work Group meetings and comment on the information being presented
and discussed. After the FACA charter expired, individual stakeholders
and members of the public were encourage to submit individual comments
and information to EPA staff. On several occasions after the FACA
charter expired, EPA met with individual stakeholder groups to discuss
the status of the proposed rulemaking and to hear their concerns and
comments regarding the proposed rulemaking.
To continue participation of stakeholders in the rulemaking
process, EPA is requesting comments and data to support the proposed
rule. The EPA requests comments on all aspects of the proposed rule
from all interested parties.
VI. Administrative Requirements
A. Executive Order 12866, Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether a regulatory action is ``significant''
and, therefore, subject to review by the Office of Management and
Budget (OMB) and the requirements of the Executive Order. The Executive
Order defines ``significant regulatory action'' as one that is likely
to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, the Agency has
determined that the proposed rule is a ``significant regulatory
action'' because it has an annual effect on the economy of over $100
million. As such, this proposed action was submitted to OMB for review.
B. Executive Order 13132, Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications.'' ``Policies that have
federalism implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.
The proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132.
The agency is required by section 112 of the CAA, to establish the
standards in the proposed rule. The proposed rule primarily affects
private industry, and does not impose significant economic costs on
State or local governments. The proposed rule does not include an
express provision preempting State or local regulations. Thus, the
requirements of section 6 of the Executive Order do not apply to the
proposed rule.
Although section 6 of Executive Order 13132 does not apply to the
proposed rule, we consulted with representatives of State and local
governments to enable them to provide meaningful and timely input into
the development of the proposed rule. This consultation took place
during the ICCR FACA committee meetings where members representing
State and local governments participated in developing recommendations
for EPA's combustion-related rulemakings, including the proposed rule.
The concerns raised by representatives of State and local governments
were considered during the development of the proposed rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on the proposed rule
from State and local officials.
C. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 9, 2000), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' The proposed rule does not have tribal
implications, as specified in Executive Order 13175.
The proposed rule does not significantly or uniquely affect the
communities of Indian tribal governments. We do not know of any
industrial-commercial-institutional boilers or process heaters owned or
operated by Indian tribal governments. However, if there are any, the
effect of the proposed rule on communities of tribal governments would
not be unique or disproportionate to the effect on other communities.
Thus, Executive Order 13175 does not apply to the proposed rule. The
EPA specifically solicits additional comment on the proposed rule from
tribal officials.
D. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, the Agency must evaluate the environmental health or
safety effects of the proposed rule on children, and explain why the
proposed rule is preferable to other potentially effective and
reasonably feasible alternatives.
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Executive Order has
the potential to influence the regulation. The proposed rule is not
subject to Executive Order 13045 because it is based on technology
performance and not on health or safety risks.
E. Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L.
[[Page 1698]]
104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows us to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we must develop a small
government agency plan under section 203 of the UMRA. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
We have determined that the proposed rule contains a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and Tribal governments, in the aggregate, or the private
sector in any 1 year. Accordingly, we have prepared a written statement
entitled ``Unfunded Mandates Reform Act Analysis for the Proposed
Industrial Boilers and Process Heaters NESHAP'' under section 202 of
the UMRA which is summarized below.
1. Statutory Authority
As discussed in section I of this preamble, the statutory authority
for the proposed rulemaking is section 112 of the CAA. Title III of the
CAA Amendments was enacted to reduce nationwide air toxic emissions.
Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups
of chemicals deemed by Congress to be HAP. These toxic air pollutants
are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT based standards. This NESHAP applies to all industrial,
commercial, and institutional boilers and process heaters located at
major sources of HAP emissions.
In compliance with section 205(a) of the UMRA, we identified and
considered a reasonable number of regulatory alternatives. Additional
information on the costs and environmental impacts of these regulatory
alternatives is presented in the docket.
The regulatory alternative upon which the proposed rule is based
represents the MACT floor for industrial boilers and process heaters
and, as a result, it is the least costly and least burdensome
alternative.
2. Social Costs and Benefits
The regulatory impact analysis prepared for the proposed rule
including the Agency's assessment of costs and benefits, is detailed in
the ``Regulatory Impact Analysis for the Proposed Industrial Boilers
and Process Heaters MACT'' in the docket. Based on estimated compliance
costs associated with the proposed rule and the predicted change in
prices and production in the affected industries, the estimated social
costs of the proposed rule are $780 million (1999 dollars).
It is estimated that 5 years after implementation of the proposed
rule, HAP will be reduced by 58,500 tons per year due to reductions in
arsenic, beryllium, dioxin, hydrochloric acid, and several other HAP
from industrial boilers and process heaters. Studies have determined a
relationship between exposure to these HAP and the onset of cancer,
however, there are some questions remaining on how cancers that may
result from exposure to these HAP can be quantified in terms of
dollars. Therefore, the Agency is unable to provide a monetized
estimate of the benefits of the HAP reduced by the proposed rule at
this time. However, there are significant reductions in PM and in
SO2 that occur. Reductions of 560,000 tons of PM with a
diameter of less than or equal to 10 micrometers (PM10),
159,000 tons of PM with a diameter of less than or equal to 2.5
micrometers (PM10), and 112,000 tons of SO2 are
expected to occur. These reductions occur from existing sources in
operation 5 years after the implementation of the regulation and are
expected to continue throughout the life of the affected sources. The
major health effect that results from these PM and SO2
emissions reductions is a reduction in premature mortality. Other
health effects that occur are reductions in chronic bronchitis, asthma
attacks, and work-lost days (i.e., days when employees are unable to
work).
While we are unable to monetize the benefits associated with the
HAP emissions reductions, we are able to monetize the benefits
associated with the PM and SO2 emissions reductions. For
SO2 and PM, we estimated the benefits associated with health
effects of PM but were unable to quantify all categories of benefits
(particularly those associated with ecosystem and environmental
effects). Unquantified benefits are noted with ``B'' in the estimates
presented below. Our base estimate of the monetized benefits in 2005
associated with the implementation of the proposed alternative is $16.1
billion (1999 dollars) when using a 3 percent discount rate (or
approximately $15.4 billion + B when using a 7 percent discount rate).
This estimate, at a 3 percent discount rate, is about $15 billion (1999
dollars) higher than the estimated social costs shown earlier in this
section. The alternative estimate of benefits is $2.4 billion (1999
dollars) when using a 3 percent discount rate (or approximately $2.6
billion + B when using a 7 percent discount rate). This estimate, at a
3 percent discount rate, is about $1.5 billion higher than the
estimated social costs. The general approach to value benefits is
discussed in more detail earlier in this preamble. For more detailed
information on the benefits estimated for the proposed rulemaking,
refer to the RIA in the docket.
3. Future and Disproportionate Costs
The Unfunded Mandates Act requires that we estimate, where accurate
estimation is reasonably feasible, future compliance costs imposed by
the proposed rule and any disproportionate budgetary effects. Our
estimates of the future compliance costs of the proposed rule are
discussed previously in this preamble.
We do not believe that there will be any disproportionate budgetary
effects of the proposed rule on any particular areas of the country,
State or local governments, types of communities (e.g., urban, rural),
or particular industry segments. This is true for the 257 facilities
owned by 54 different government bodies and is borne out by the results
of the ``Economic Impact Analysis of the Proposed Industrial Boilers
and Process Heaters NESHAP,''
[[Page 1699]]
the results of which are discussed previously in this preamble.
4. Effects on the National Economy
The Unfunded Mandates Act requires that we estimate the effect of
the proposed rule on the national economy. To the extent feasible, we
must estimate the effect on productivity, economic growth, full
employment, creation of productive jobs, and international
competitiveness of the U.S. goods and services, if we determine that
accurate estimates are reasonably feasible and that such effect is
relevant and material.
The nationwide economic impact of the proposed rule is presented in
the ``Economic Impact Analysis for the Industrial Boilers and Process
Heaters MACT'' in the docket. This analysis provides estimates of the
effect of the proposed rule on some of the categories mentioned above.
The results of the economic impact analysis are summarized previously
in this preamble. The results show that there will be little impact on
prices and output from the affected industries, and little impact on
communities that may be affected by the proposed rule. In addition,
there should be little impact on energy markets (in this case, coal,
natural gas, petroleum products, and electricity). Hence, the potential
impacts on the categories mentioned above should be minimal.
5. Consultation with Government Officials
The Unfunded Mandates Act requires that we describe the extent of
the Agency's prior consultation with affected State, local, and tribal
officials, summarize the officials' comments or concerns, and summarize
our response to those comments or concerns. In addition, section 203 of
the UMRA requires that we develop a plan for informing and advising
small governments that may be significantly or uniquely impacted by a
proposal. Although the proposed rule does not affect any State, local,
or Tribal governments, we have consulted with State and local air
pollution control officials. We also have held meetings on the proposed
rule with many of the stakeholders from numerous individual companies,
environmental groups, consultants and vendors, labor unions, and other
interested parties. We have added materials to the Air Docket to
document these meetings.
In addition, we have determined that the proposed rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. While some small governments may have some sources
affected by the proposed rule, the impacts are not expected to be
significant. Therefore, today's proposed rule is not subject to the
requirements of section 203 of the UMRA.
F. Regulatory Flexibility Act (RFA), as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et
seq.
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of today's proposed rule on
small entities, small entity is defined as: (1) A small business
according to Small Business Administration (SBA) size standards by the
North American Industry Classification System category of the owning
entity. The range of small business size standards for the 40 affected
industries ranges from 500 to 1,000 employees, except for petroleum
refining and electric utilities. In these latter two industries, the
size standard is 1,500 employees and a mass throughput of 75,000
barrels/day or less, and 4 million kilowatt-hours of production or
less, respectively; (2) a small governmental jurisdiction that is a
government of a city, county, town, school district or special district
with a population of less than 50,000; and (3) a small organization
that is any not-for-profit enterprise which is independently owned and
operated and is not dominant in its field.
After considering the economic impact of the proposed rule on small
entities, EPA certifies that this action will not have a significant
impact on a substantial number of small entities. Based on SBA size
definitions for the affected industries and reported sales and
employment data, the Agency identified 185 of the 576 companies, or 32
percent, owning affected facilities as small businesses. Although small
businesses represent 32 percent of the companies within the source
category, they are expected to incur 4 percent of the total compliance
costs of $862.7 million (1998 dollars). There are only ten small firms
with compliance costs equal to or greater than 3 percent of their
sales. In addition, there are 24 small firms with cost-to-sales ratios
between 1 and 3 percent.
An economic impact analysis was performed to estimate the changes
in product price and production quantities for the proposed rule. As
mentioned in the summary of economic impacts, the estimated changes in
prices and output for affected firms is no more than 0.05 percent.
This analysis indicates that the proposed rule should not generate
a significant impact on a substantial number of small entities for
following reasons. First, there are 34 small firms (or 18 percent of
all affected small firms) with compliance costs equal to or greater
than 1 percent of their sales. Of these, ten small firms (or 5 percent
of all affected small firms) with compliance costs equal to or greater
than 3 percent of their sales. Second, the results of the economic
impact analysis show minimal impacts on prices and output from affected
firms, including small entities, due to the implementation of the
proposed rule. For more information, consult the docket for the
proposed rule.
The proposed rule will not have a significant economic impact on a
substantial number of small entities as a result of several decisions
EPA made regarding the development of the rule which resulted in
limiting the impact of the rule on small entities. First, as mentioned
earlier in this preamble, EPA identified small units (heat input of 10
MMBtu/hr or less) and limited use boilers (operate less than 10 percent
of the time) as separate subcategories different from large units. Many
small and limited use units are located at small entities. As also
discussed earlier, the results of the MACT floor analysis for these
subcategories of existing sources was that no MACT floor could be
identified except for the limited use solid fuel subcategory which is
less stringent than the MACT floor for large units. Furthermore, the
results of the beyond-the-floor analysis for these subcategories
indicated that the costs would be too high to consider them feasible
options. Consequently, the proposed rule contains no emission
limitations for any of the existing small and limited use subcategories
except the existing limited use solid fuel subcategory. In addition,
the proposed alternative metals emission limit resulted in minimizing
the impacts on small entities since some of the potential entities
burning a fuel containing very little metals are small entities. We
continue to be interested in the potential impacts of the proposed rule
on small entities and welcome comments on issues related to such
impacts.
[[Page 1700]]
G. Paperwork Reduction Act
The information collection requirements in the proposed rule will
be submitted for approval to the Office of Management and Budget under
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information
Collection Request (ICR) document has been prepared by EPA (ICR No.
2028.01) and a copy may be obtained from Susan Auby by mail at the
Collection Strategies Division, U.S. Environmental Protection Agency
(2822), 1200 Pennsylvania Avenue NW., Washington, DC 20460, by e-mail
at auby.susan@epa.gov, or by calling (202) 566-1672. A copy may also be
downloaded off the Internet at http://www.epa.gov/icr.
The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant
to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The proposed rule would require maintenance inspections of the
control devices but would not require any notifications or reports
beyond those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance.
The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the standards) is estimated to be $165 million. This includes 2.7
million labor hours per year at a total labor cost of $142 million per
year, and total non-labor capital costs of $24 million per year. This
estimate includes a one-time performance test, semiannual excess
emission reports, maintenance inspections, notifications, and
recordkeeping. Monitoring costs were also included in the cost
estimates presented in the control costs impacts estimates in section
IV.D of this preamble. The total burden for the Federal government
(averaged over the first 3 years after the effective date of the
standard) is estimated to be 346,000 hours per year at a total labor
cost of $14 million per year.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An Agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for our
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
Comments are requested on the Agency's need for this information,
the accuracy of the provided burden estimates, and any suggested
methods for minimizing respondent burden, including through the use of
automated collection techniques. Send comments on the ICR to the
Director, Collection Strategies Division, U.S. Environmental Protection
Agency (2822), 1200 Pennsylvania Ave., NW., Washington, DC 20460; and
to the Office of Information and Regulatory Affairs, Office of
Management and Budget, 725 17th St., NW., Washington, DC 20503, marked
``Attention: Desk Officer for EPA.'' Include the ICR number in any
correspondence.
Since OMB is required to make a decision concerning the ICR between
30 and 60 days after January 13, 2003, a comment to OMB is best assured
of having its full effect if OMB receives it by February 12, 2003. The
final rule will respond to any OMB or public comments on the
information collection requirements contained in the proposed rule.
H. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Public Law 104-113; 15 U.S.C. 272 note) directs
the EPA to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to the Office of Management and
Budget, with explanations when an agency does not use available and
applicable voluntary consensus standards.
This rulemaking involves technical standards. The EPA cites the
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A,
3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with
the NTTAA, EPA conducted searches to identify voluntary consensus
standards in addition to these EPA methods. No applicable voluntary
consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19.
The search and review results have been documented and are placed in
the docket for the proposed rule.
The three voluntary consensus standards described below were
identified as acceptable alternatives to EPA test methods for the
purposes of the proposed rule.
The voluntary consensus standard ASME PTC 19-10-1981--Part 10,
``Flue and Exhaust Gas Analyses,'' is cited in the proposed rule for
its manual method for measuring the oxygen, carbon dioxide, and carbon
monoxide content of exhaust gas. This part of ASME PTC 19-10-1981--Part
10 is an acceptable alternative to Method 3B.
The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers and Process Heaters Using
Portable Analyzers'' is an acceptable alternative to EPA Method 3A for
identifying carbon monoxide and oxygen concentrations for the proposed
rule when the fuel is natural gas.
The voluntary consensus standard ASTM Z65907, ``Standard Method for
Both Speciated and Elemental Mercury Determination,'' is an acceptable
alternative to EPA Method 29 (portion for mercury only) for the purpose
of the proposed rule. This standard can be used in the proposed rule to
determine the mercury concentration in stack gases for boilers with
rated heat input capacities of greater than 250 MMBtu per hour.
In addition to the voluntary consensus standards EPA uses in the
proposed rule, the search for emissions measurement procedures
identified 15 other voluntary consensus standards.
[[Page 1701]]
The EPA determined that 13 of these 15 standards identified for
measuring emissions of the HAP or surrogates subject to emission
standards in the proposed rule were impractical alternatives to EPA
test methods for the purposes of the rule. Therefore, EPA does not
intend to adopt these standards for this purpose. The reasons for this
determination for the 13 methods are discussed below.
The voluntary consensus standard ASTM D3154-00, ``Standard Method
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the
proposed rulemaking since the standard appears to lack in quality
control and quality assurance requirements. Specifically, ASTM D3154-00
does not include the following: (1) Proof that openings of standard
pitot tube have not plugged during the test; (2) if differential
pressure gauges other than inclined manometers (e.g., magnehelic
gauges) are used, their calibration must be checked after each test
series; and (3) the frequency and validity range for calibration of the
temperature sensors.
The voluntary consensus standard ASTM D3464-96 (2001), ``Standard
Test Method Average Velocity in a Duct Using a Thermal Anemometer,'' is
impractical as an alternative to EPA Method 2 for the purposes of the
proposed rule primarily because applicability specifications are not
clearly defined, e.g., range of gas composition, temperature limits.
Also, the lack of supporting quality assurance data for the calibration
procedures and specifications, and certain variability issues that are
not adequately addressed by the standard limit EPA's ability to make a
definitive comparison of the method in these areas.
The voluntary consensus standard ISO 10780:1994, ``Stationary
Source Emissions-Measurement of Velocity and Volume Flow-Rate of Gas
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in
the proposed rule. The standard recommends the use of an L-shaped
pitot, which historically has not been recommended by EPA. The EPA
specifies the S-type design which has large openings that are less
likely to plug up with dust.
The voluntary consensus standard, CAN/CSA Z223.2-M86 (1999),
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide,
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA
Method 3A since it does not include quantitative specifications for
measurement system performance, most notably the calibration procedures
and instrument performance characteristics. The instrument performance
characteristics that are provided are nonmandatory and also do not
provide the same level of quality assurance as the EPA methods. For
example, the zero and span/calibration drift is only checked weekly,
whereas the EPA methods requires drift checks after each run.
Two very similar voluntary consensus standards, ASTM D5835-95
(2001), ``Standard Practice for Sampling Stationary Source Emissions
for Automated Determination of Gas Concentration,'' and ISO 10396:1993,
``Stationary Source Emissions: Sampling for the Automated Determination
of Gas Concentrations,'' are impractical alternatives to EPA Method 3A
for the purposes of the proposed rule because they lack in detail and
quality assurance/quality control requirements. Specifically, these two
standards do not include the following: (1) Sensitivity of the method;
(2) acceptable levels of analyzer calibration error; (3) acceptable
levels of sampling system bias; (4) zero drift and calibration drift
limits, time span, and required testing frequency; (5) a method to test
the interference response of the analyzer; (6) procedures to determine
the minimum sampling time per run and minimum measurement time; and (7)
specifications for data recorders, in terms of resolution (all types)
and recording intervals (digital and analog recorders, only).
The voluntary consensus standard ISO 12039:2001, ``Stationary
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and
Oxygen--Automated Methods,'' is not acceptable as an alternative to EPA
Method 3A. This ISO standard is similar to EPA Method 3A, but is
missing some key features. In terms of sampling, the hardware required
by ISO 12039:2001 does not include a 3-way calibration valve assembly
or equivalent to block the sample gas flow while calibration gases are
introduced. In its calibration procedures, ISO 12039:2001 only
specifies a two-point calibration while EPA Method 3A specifies a
three-point calibration. Also, ISO 12039:2001 does not specify
performance criteria for calibration error, calibration drift, or
sampling system bias tests as in the EPA method, although checks of
these quality control features are required by the ISO standard.
The voluntary consensus standard ASME PTC-38-80 R85 (1985),
``Determination of the Concentration of Particulate Matter in Gas
Streams,'' is not acceptable as an alternative for EPA Method 5 because
ASTM PTC-38-80 is not specific about equipment requirements, and
instead presents the options available and the pro's and con's of each
option. The key specific differences between ASME PTC-38-80 and the EPA
methods are that the ASME standard: (1) Allows in-stack filter
placement as compared to the out-of-stack filter placement in EPA
Methods 5 and 17; (2) allows many different types of nozzles, pitots,
and filtering equipment; (3) does not specify a filter weighing
protocol or a minimum allowable filter weight fluctuation as in the EPA
methods; and (4) allows filter paper to be only 99 percent efficient,
as compared to the 99.95 percent efficiency required by the EPA
methods.
The voluntary consensus standard ASTM D3685/D3685M-98, ``Test
Methods for Sampling and Determination of Particulate Matter in Stack
Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the
following areas that are needed to produce quality, representative
particulate data:
(1) Requirement that the filter holder temperature should be
between 120[deg]C and 134[deg]C, and not just ``above the acid dew-
point;'' (2) detailed specifications for measuring and monitoring the
filter holder temperature during sampling; (3) procedures similar to
EPA Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4)
technical guidance for performing the Method 5 sampling procedures,
e.g., maintaining and monitoring sampling train operating temperatures,
specific leak check guidelines and procedures, and use of reagent
blanks for determining and subtracting background contamination; and
(5) detailed equipment and/or operational requirements, e.g., component
exchange leak checks, use of glass cyclones for heavy particulate
loading and/or water droplets, operating under a negative stack
pressure, exchanging particulate loaded filters, sampling preparation
and implementation guidance, sample recovery guidance, data reduction
guidance, and particulate sample calculations input.
The voluntary consensus standard ISO 9096:1992, ``Determination of
Concentration and Mass Flow-Rate of Particulate Matter in Gas Carrying
Ducts--Manual Gravimetric Method,'' is not acceptable as an alternative
for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods
1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA
Method 5 for collection of particulate matter. The standard ISO 9096
does not provide applicable technical guidance for performing many of
the integral
[[Page 1702]]
procedures specified in Methods 1, 2, and 5. Major performance and
operational details are lacking or nonexistent, and detailed quality
assurance/quality control guidance for the sampling operations required
to produce quality, representative particulate data (e.g., guidance for
maintaining and monitoring train operating temperatures, specific leak
check guidelines and procedures, and sample preparation and recovery
procedures) are not provided by the standard, as in EPA Method 5. Also,
details of equipment and/or operational requirements, such as those
specified in EPA Method 5, are not included in the ISO standard, e.g.,
stack gas moisture measurements, data reduction guidance, and
particulate sample calculations.
The voluntary consensus standard CAN/CSA Z223.1-M1977, ``Method for
the Determination of Particulate Mass Flows in Enclosed Gas Streams,''
is not acceptable as an alternative for EPA Method 5. Detailed
technical procedures and quality control measures that are required in
EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second,
CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing
requirement to repeat weighing every 6 hours until a constant weight is
achieved. Third, EPA Method 5 requires the filter weight to be reported
to the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the
nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot
for velocity measurement when plugging of the tube opening is not
expected to be a problem. Whereas, EPA Method 5 requires an S-shaped
pitot.
The voluntary consensus standard EN 1911-1,2,3 (1998), ``Stationary
Source Emissions--Manual Method of Determination of HCl--Part 1:
Sampling of Gases Ratified European Text--Part 2: Gaseous Compounds
Absorption Ratified European Text--Part 3: Adsorption Solutions
Analysis and Calculation Ratified European Text,'' is impractical as an
alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot
be considered equivalent to EPA Method 26 or 26A because the sample
absorbing solution (water) would be expected to capture both HCl and
chlorine gas, if present, without the ability to distinguish between
the two. The EPA Methods 26 and 26A use an acidified absorbing solution
to first separate HCl and chlorine gas so that they can be selectively
absorbed, analyzed, and reported separately. In addition, in EN 1911
the absorption efficiency for chlorine gas would be expected to vary as
the pH of the water changed during sampling.
The voluntary consensus standard EN 13211 (1998), is not acceptable
as an alternative to the mercury portion of EPA Method 29 primarily
because it is not validated for use with impingers, as in the EPA
method, although the method describes procedures for the use of
impingers. This European standard is validated for the use of fritted
bubblers only and requires the use of a side (split) stream arrangement
for isokinetic sampling because of the low sampling rate of the
bubblers (up to 3 liters per minute, maximum). Also, only two bubblers
(or impingers) are required by EN 13211, whereas EPA Method 29 require
the use of six impingers. In addition, EN 13211 does not include many
of the quality control procedures of EPA Method 29, especially for the
use and calibration of temperature sensors and controllers, sampling
train assembly and disassembly, and filter weighing.
Two of the 15 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the proposed rule because they are under development by a
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2.
Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR
part 63, list the EPA testing methods included in the proposed rule.
Under Sec. 63.7(f) and Sec. 63.8(f) of subpart A of the General
Provisions, a source may apply to EPA for permission to use alternative
test methods or alternative monitoring requirements in place of any of
the EPA testing methods, performance specifications, or procedures.
I. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211, (66 FR 28355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, Office of Management and Budget, a
Statement of Energy Effects for certain actions identified as
significant energy actions. Section 4(b) of Executive Order 13211
defines ``significant energy actions'' as ``any action by an agency
(normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation,
including notices of inquiry, advance notices of proposed rulemaking,
and notices of proposed rulemaking: (1)(i) that is a significant
regulatory action under Executive Order 12866 or any successor order,
and (ii) is likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) that is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
significant energy action.'' The proposed rule is not a ``significant
regulatory action'' because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy. The basis
for the determination is as follows.
The reduction in petroleum product output, which includes
reductions in fuel production, is estimated at only 0.001 percent, or
about 68 barrels per day based on 2000 U.S. fuel production nationwide.
That is a minimal reduction in nationwide petroleum product output. The
reduction in coal production is estimated at only 0.014 percent, or
about 3.5 million tons per year (or less than 1,000 tons per day) based
on 2000 U.S. coal production nationwide. The combination of the
increase in electricity usage estimated in section IV. C of this
preamble with the effect of the increased price of affected output
yields an increase in electricity output estimated at only 0.012
percent, or about 0.72 billion kilowatt-hours per year based on 2000
U.S. electricity production nationwide. All energy price changes
estimated show no increase in price more than 0.05 percent nationwide,
and a similar result occurs for energy distribution costs. We also
expect that there will be no discernable impact on the import of
foreign energy supplies, and no other adverse outcomes are expected to
occur with regards to energy supplies. All of the results presented
above account for the pass through of costs to consumers, as well as
the cost impact to producers. For more information on the estimated
energy effects, please refer to the economic impact analysis for the
proposed rule. The analysis is available in the public docket.
Therefore, we conclude that the proposed rule when implemented is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.
[[Page 1703]]
Dated: November 26, 2002.
Christine Todd Whitman,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
63 of the Code of the Federal Regulations is proposed to be amended as
follows:
PART 63--[AMENDED]
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
2. Part 63 is amended by adding subpart DDDDD to read as follows:
Subpart DDDDD--National Emission Standards for Hazardous Air Pollutants
for Industrial, Commercial, and Institutional Boilers and Process
Heaters
What This Subpart Covers
Sec.
63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What parts of my facility does this subpart cover?
63.7495 When do I have to comply with this subpart?
Emission Limitations and Work Practice Standards
63.7500 What emission limitations and work practice standards must I
meet?
General Compliance Requirements
63.7505 What are my general requirements for complying with this
subpart?
Testing and Initial Compliance Requirements
63.7510 By what date must I conduct performance tests or other
initial compliance demonstrations?
63.7515 When must I conduct subsequent performance tests?
63.7520 What performance tests, design evaluations, and other
procedures must I use?
63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission
limitations and work practice standards?
Continuous Compliance Requirements
63.7535 How do I monitor and collect data to demonstrate continuous
compliance?
63.7540 How do I demonstrate continuous compliance with the emission
limitations and work practice standards?
Notifications, Reports, and Records
63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?
Other Requirements and Information
63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?
Tables to Subpart DDDDD of Part 63
Table 1 to Subpart DDDDD of Part 63--Emission Limits
Table 2.A to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters in the Large, Limited Use, or Small Solid Fuel
Subcategories
Table 2.B to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters in the Large, Limited Use, or Small Liquid Fuel
Subcategories
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
Table 4.A to Subpart DDDDD of Part 63--Requirements for Performance
Tests for Particulate Matter Emissions or Total Selected Metals
Emissions from Boilers or Process Heaters in Large, Limited Use, or
Small Solid Fuel Subcategories
Table 4.B to Subpart DDDDD of Part 63--Requirements for Performance
Tests for Particulate Matter Emissions from Boilers or Process
Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories
Table 4.C to Subpart DDDDD of Part 63--Requirements for Performance
Tests for Hydrogen Chloride Emissions from Boilers or Process
Heaters in Large, Limited Use, or Small Solid Fuel Subcategories
Table 4.D to Subpart DDDDD of Part 63--Requirements for Performance
Tests for Hydrogen Chloride Emissions from Boilers or Process
Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories
Table 4.E to Subpart DDDDD of Part 63--Requirements for Performance
Tests for Mercury Emissions from Boilers or Process Heaters in
Large, Limited Use, or Small Solid Fuel Subcategories
Table 5.A to Subpart DDDDD of Part 63--Initial Compliance With
Emission Limitations for Particulate Matter or Total Selected Metals
for Boilers or Process Heaters in Large, Limited Use, or Small Solid
Fuel Subcategories
Table 5.B to Subpart DDDDD of Part 63--Initial Compliance With
Emission Limitations for Particulate Matter for Boilers or Process
Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories
Table 5.C to Subpart DDDDD of Part 63--Initial Compliance With
Emission Limitations for Hydrogen Chloride for Boilers or Process
Heaters in Large, Limited Use, or Small Solid Fuel Subcategories
Table 5.D to Subpart DDDDD of Part 63--Initial Compliance With
Emission Limitations for Hydrogen Chloride for Boilers or Process
Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories
Table 5.E to Subpart DDDDD of Part 63--Initial Compliance With
Emission Limitations for Mercury for Boilers or Process Heaters in
Large, Limited Use, or Small Solid Fuel, Subcategories
Table 6 to Subpart DDDDD of Part 63--Initial Compliance with Work
Practice Standards
Table 7.A to Subpart DDDDD of Part 63--Continuous Compliance with
Emission Limitations for Boilers or Process Heaters in Large,
Limited Use, or Small Solid Fuel Subcategories
Table 7.B to Subpart DDDDD of Part 63--Continuous Compliance with
Emission Limitations for Boilers or Process Heaters in Large,
Limited Use, or Small Liquid Fuel Subcategories
Table 8 to Subpart DDDDD of Part 63--Continuous Compliance with Work
Practice Standards
Table 9 to Subpart DDDDD of Part 63--Requirements for Reports
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters
What This Subpart Covers
Sec. 63.7480 What is the purpose of this subpart?
This subpart establishes national emission limitations and work
practice standards for hazardous air pollutants emitted from
industrial, commercial, and institutional boilers and process heaters.
This subpart also establishes requirements to demonstrate initial and
continuous compliance with the emission limitations and work practice
standards.
Sec. 63.7485 Am I subject to this subpart?
You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler or process heater that
is located at, or is part of, a major source of hazardous air
pollutants (HAP) emissions, except as specifically exempted in Sec.
63.7490.
(a) An industrial, commercial, or institutional boiler is an
enclosed device using controlled flame combustion and having the
primary purpose of recovering thermal energy in the form of steam or
hot water. Waste heat boilers are excluded. A process heater is an
enclosed device using controlled flame with the unit's primary purpose
being to transfer heat indirectly to process streams (liquids, gases,
or solids) instead of generating steam.
(b) 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 9.07 megagrams (10 tons) or more per year or any
combination of HAP at a rate of
[[Page 1704]]
22.68 megagrams (25 tons) or more per year.
Sec. 63.7490 What parts of my facility does this subpart cover?
(a) This subpart applies to each new, reconstructed, or existing
affected source.
(b) The affected source is each industrial, commercial, or
institutional boiler or process heater, as defined in Sec. 63.7485
that is not one of the types of combustion units listed in Sec.
63.7490(b)(1) through (10).
(1) A municipal waste combustor covered by 40 CFR part 60, subpart
AAAA, subpart BBBB, subpart Eb or subpart Cb.
(2) A hospital/medical/infectious waste incinerator covered by 40
CFR part 60, subpart Ce or subpart Ec.
(3) An electric utility steam generating unit that is a fossil
fuel-fired combustion unit of more than 25 megawatts that serves a
generator that produces electricity for sale. A unit that cogenerates
steam and electricity and supplies more than one-third of its potential
electric output capacity and more than 25 megawatts electrical output
to any utility power distribution system for sale is considered an
electric utility steam generating unit.
(4) A boiler or process heater required to have a permit under
section 3005 of the Solid Waste Disposal Act or covered by 40 CFR part
63, subpart EEE (e.g., hazardous waste combustors).
(5) A commercial and industrial solid waste incineration unit
covered by 40 CFR part 60, subpart CCCC or subpart DDDD.
(6) A recovery boiler or furnace covered by 40 CFR part 63, subpart
MM.
(7) A boiler or process heater that is used specifically for
research and development. This does not include units that only provide
steam to a process at a research and development facility.
(8) A hot water heater as defined in this subpart.
(9) A refining kettle covered by 40 CFR part 63, subpart X.
(10) An ethylene cracking furnace covered by 40 CFR part 63,
subpart YY.
(c) An affected source is a new affected source if you commenced
construction of the affected source after January 13, 2003 and you meet
the applicability criteria at the time you commenced construction.
(d) An affected source is reconstructed if you meet the criteria as
defined in Sec. 63.2.
(e) An affected source is existing if it is not new or
reconstructed.
Sec. 63.7495 When do I have to comply with this subpart?
(a) If you have a new or reconstructed affected source, you must
comply with this subpart according to paragraph (a)(1) or (2) of this
section.
(1) If you start up your affected source before [DATE THE FINAL
RULE IS PUBLISHED IN THE FEDERAL REGISTER], then you must comply with
the emission limitations and work practice standards for new and
reconstructed sources in this subpart no later than [DATE THE FINAL
RULE IS PUBLISHED IN THE FEDERAL REGISTER].
(2) If you startup your affected source after [DATE THE FINAL RULE
IS PUBLISHED IN THE FEDERAL REGISTER], then you must comply with the
emission limitations and work practice standards for new and
reconstructed sources in this subpart upon startup of your affected
source.
(b) If you have an existing affected source, you must comply with
the emission limitations for existing sources no later than 3 years
after [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER].
(c) If you have an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP,
paragraphs (c)(1) and (2) of this section apply to you.
(1) Any new or reconstructed boiler or process heater at the
existing facility must be in compliance with this subpart upon startup.
(2) Any existing boiler or process heater at the existing facility
must be in compliance with this subpart within 3 years after the
facility becomes a major source.
(d) You must meet the notification requirements in Sec. 63.7545
according to the schedule in Sec. 63.7545 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limitations and work practice
standards in this subpart.
Emission Limitations and Work Practice Standards
Sec. 63.7500 What emission limitations and work practice standards
must I meet?
(a) You must meet the requirements in paragraphs (a)(1) through (3)
of this section.
(1) You must meet each emission limit in Table 1 to this subpart
that applies to you.
(2) You must meet each operating limit in Tables 2.A and 2.B to
this subpart that applies to you. If you use a control device or
combination of control devices not covered in Tables 2.A or 2.B to this
subpart, or you wish to establish and monitor an alternative operating
limit and alternative monitoring parameters, you must apply to the
Administrator for approval of alternative monitoring under Sec.
63.8(f).
(3) You must meet each work practice standard in Table 3 to this
subpart that applies to you.
(b) If your new or reconstructed boiler or process heater is in one
of the liquid fuel subcategories (the large liquid fuel subcategory,
the limited use liquid fuel subcategory, or the small liquid fuel
subcategory) and burns only fossil fuels and other gases and does not
burn any residual oil, you are subject to the emission limits in Table
1 to this subpart, but you are not required to conduct a performance
test to demonstrate compliance with the emission limits. However, you
must meet all applicable requirements in Sec. Sec. 63.7530 and
63.7535.
(c) As provided in Sec. 63.6(g), the Environmental Protection
Agency (EPA) may choose to grant you permission to use an alternative
to the work practice standards in this section.
General Compliance Requirements
Sec. 63.7505 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limitations
(including operating limits) and the work practice standards in this
subpart at all times, except during periods of startup, shutdown, and
malfunction.
(b) You must always operate and maintain your affected source,
including air pollution control and monitoring equipment, according to
the provisions in Sec. 63.6(e)(1)(i).
(c) You must develop a site-specific monitoring plan according to
the requirements in paragraphs (c)(1) through (4) of this section.
(1) For each monitoring system required in this section, you must
develop and submit for approval a site-specific monitoring plan that
addresses paragraphs (c)(1)(i) through (iii) of this section.
(i) Installation of the continuous monitoring system (CMS) sampling
probe or other interface at a measurement location relative to each
affected process unit such that the measurement is representative of
control of the exhaust emissions (e.g., on or downstream of the last
control device);
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
[[Page 1705]]
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations).
(2) In your site-specific monitoring plan, you must also address
paragraphs (c)(2)(i) through (iii) of this section.
(i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 63.8(c)(1), (c)(3), and (c)(4)(ii);
(ii) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 63.8(d); and
(iii) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec. 63.10(c), (e)(1) and (e)(2)(i).
(3) You must conduct a performance evaluation of each CMS in
accordance with your site-specific monitoring plan.
(4) You must operate and maintain the CMS in continuous operation
according to the site-specific monitoring plan.
(d) You must develop and implement a written startup, shutdown, and
malfunction plan (SSMP) according to the provisions in Sec.
63.6(e)(3).
Testing and Initial Compliance Requirements
Sec. 63.7510 By what date must I conduct performance tests or other
initial compliance demonstrations?
(a) For each existing affected source, you must conduct performance
tests, set operating limits, and conduct monitoring equipment
performance evaluations by the compliance date that is specified for
your source in Sec. 63.7495 and according to the applicable provisions
in Sec. 63.7(a)(2) as cited in Table 10 to this subpart.
(b) For each new or reconstructed affected source, you must conduct
performance tests, set operating limits, and conduct monitoring
equipment performance evaluations within 180 calendar days after the
compliance date that is specified for your source in Sec. 63.7495 and
according to the provisions in Sec. 63.7(a)(2) as cited in Table 10 to
this subpart.
Sec. 63.7515 When must I conduct subsequent performance tests?
(a) You must conduct all applicable performance tests according to
the procedures in Sec. 63.7520 on an annual basis unless you follow
the requirements listed in paragraphs (b) through (h) of this section.
The first subsequent performance tests must be completed within 12
months of the initial performance test but no earlier than 10 months
after the initial performance test and every 12 months thereafter,
unless you follow the requirements listed in paragraphs (b) through (h)
of this section.
(b) You can conduct performance tests less often for a given
pollutant if you have test data for at least 3 years, and all stack
tests for the pollutant (particulate matter, hydrogen chloride,
mercury, or total selected metals) for over 3 consecutive years show
that you comply with the emission limit. In this case, you do not have
to conduct a stack test for that pollutant for the next 2 years. You
must do a stack test during the third year and no more than 36 months
following the previous stack test.
(c) If your boiler or process heater continues to meet the emission
limit for particulate matter, hydrogen chloride, mercury, or total
selected metals, you may choose to conduct stack tests for these
pollutants every third year, but each such test must be within 36
months of the previous stack test.
(d) If a stack test shows noncompliance with an emission limit for
particulate matter, hydrogen chloride, mercury, or total selected
metals, you must conduct annual stack tests for that pollutant until
all stack tests over a 3-year period show compliance.
(e) You are not required to conduct a performance test for total
selected metals annually if you choose to comply with the alternative
total selected metals emission limit instead of particulate matter, and
your operating limit is the total selected metals fuel input. You must
still meet all applicable continuous compliance requirements in Sec.
63.7540.
(f) You are not required to conduct a performance test for hydrogen
chloride annually if your operating limit for hydrogen chloride is
chlorine fuel input. You must still meet all applicable continuous
compliance requirements in Sec. 63.7540.
(g) You are not required to conduct a performance test for mercury
annually if your operating limit for mercury is mercury fuel input. You
must still meet all applicable continuous compliance requirements in
Sec. 63.7540.
(h) You must report the results of annual performance tests within
60 days after the completion of the tests. This report should also
verify that the operating limits for your affected source have not
changed or provide documentation of revised operating parameters
established as specified in Tables 4.A through 4.E to this subpart. The
reports for all subsequent performance tests should include all
applicable information required in Sec. 63.7550.
Sec. 63.7520 What performance tests, design evaluations, and other
procedures must I use?
(a) You must conduct all performance tests according to Sec.
63.7(c), (d), (f), and (h). You must also develop a site-specific test
plan according to the requirements in Sec. 63.7(c).
(b) You must conduct each performance test in Tables 4.A through
4.E to this subpart that applies to you.
(c) For boilers or process heaters in one of the liquid fuel
subcategories that burn only fossil fuels and other gases and do not
burn any residual oil, you are not required to conduct a performance
test to demonstrate compliance with the emission limits.
(d) You must conduct each performance test under the specific
conditions listed in Tables 4.A through 4.E to this subpart. You must
conduct performance tests at the representative process operating
conditions that are expected to result in the highest emissions of
hydrogen chloride, particulate matter, and mercury, and you must
demonstrate initial compliance and establish your operating limits
based on this test. This requirement could result in the need to
conduct more than one performance test. If you choose to comply with
the alternative total selected metals emission limit instead of
particulate matter, you must conduct all performance tests at the
representative process operating conditions that are expected to result
in the highest emissions of hydrogen chloride, total selected metals
and mercury.
(e) You may not conduct performance tests during periods of
startup, shutdown, or malfunction.
(f) You must conduct three separate test runs for each performance
test required in this section, as specified in Sec. 63.7(e)(3). Each
test run must last at least 1 hour.
(g) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 of appendix A of this part to convert the measured
particulate matter concentrations, the measured hydrogen chloride
concentrations, the measured total selected metals concentrations, and
the measured mercury concentrations that result from the initial
performance test to pound per million British thermal unit (MMBtu) heat
input emission rates. Method 26A of appendix A of this part must be
used for the hydrogen chloride performance test for those boilers and
process heaters with wet scrubbers. All other boilers and process
heaters must use Method 26 of
[[Page 1706]]
appendix A of this part for the hydrogen chloride performance test.
(h) For performance tests using Method 5, Method 29, Method 26A and
Method 17 of appendix A of this part, use Method 1 of appendix A of
this part to select the sampling location and number of traverse
points. For Method 26 of appendix A of this part, you must use a
minimum of three traverse points.
(i) If you use a control device or combination of control devices
not covered in Tables 4.A through 4.E to this subpart, or you wish to
establish and monitor an alternative operating limit, you must apply to
the Administrator for approval of alternative monitoring under Sec.
63.8(f).
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) Each continuous emissions monitoring system (CEMS) for carbon
monoxide must be installed, operated, and maintained according to the
procedures in paragraphs (a)(1) through (4) of this section by the
compliance date.
(1) Each CEMS must be installed, operated, and maintained according
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and
according to the site-specific monitoring plan developed according to
Sec. 63.7505(c).
(2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec. 63.8 and according to PS 4A of
40 CFR part 60, appendix B.
(3) Each CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period.
(4) The CEMS data must be reduced as specified in Sec. 63.8(g)(2).
(b) Each continuous opacity monitoring system (COMS) must be
installed, operated, certified and maintained according to the
procedures in paragraphs (b)(1) through (7) of this section by the
compliance date.
(1) Each COMS must be installed, operated, and maintained according
to PS 1 of 40 CFR part 60, appendix B.
(2) You must conduct a performance evaluation of each COMS
according to the requirements in Sec. 63.8 and according to PS 1 of 40
CFR part 60, appendix B.
(3) As specified in Sec. 63.8(c)(4)(i), each COMS must complete a
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
(4) The COMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
COMS according to the requirements in Sec. 63.8(d). At a minimum, the
monitoring plan must include a daily calibration drift assessment, a
quarterly performance audit, and an annual zero alignment audit of each
COMS.
(6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). Identify periods the COMS is out-of-control including any
periods that the COMS fails to pass a daily calibration drift
assessment, a quarterly performance audit, or an annual zero alignment
audit.
(7) You must determine and record all the 6-minute averages and 3-
hour block averages collected for periods during which the COMS is not
out-of-control.
(c) You must install, operate, and maintain each continuous
parameter monitoring system (CPMS) according to the requirements in
Sec. 63.8 and the procedures in paragraphs (c)(1) through (5) of this
section by the compliance date specified in Sec. 63.7495.
(1) The CPMS must complete a minimum of one cycle of operation for
each successive 15-minute period. You must have a minimum of four
successive cycles of operation to have a valid hour of data.
(2) Except for, monitoring malfunctions, associated repairs and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must conduct all monitoring in continuous operation at all times
that the unit is operating. A monitoring malfunction is any sudden,
infrequent, not reasonably preventable failure of the monitoring system
to provide valid data. Monitoring failures that are caused in part by
poor maintenance or careless operation are not malfunctions.
(3) For purposes of calculating data averages, you must not use
data recorded during monitoring malfunctions, associated repairs, out-
of-control periods, or required quality assurance or control
activities. You must use all the data collected during all other
periods in assessing compliance. Any period for which the monitoring
system is out-of-control and data are not available for required
calculations constitutes a deviation from the monitoring requirements.
(4) Determine the 3-hour block average of all recorded readings,
except as provided in paragraph (c)(3) of this section.
(5) Record the results of each inspection, calibration, and
validation check.
(d) For the equipment to monitor voltage and secondary current (or
total power input) of the electrostatic precipitator (ESP), you must
meet the requirements in paragraphs (c) and (d)(1) and (2) of this
section.
(1) Use the ESP manufacturer's installed voltage and secondary
current monitoring equipment to measure voltage and secondary current
to the ESP.
(2) At least monthly, inspect all components of the CPMS for
integrity and all electrical connections for continuity.
(e) For the equipment to monitor sorbent injection rate (e.g.,
weigh belt, weigh hopper, or hopper flow measurement device), you must
meet the requirements in paragraphs (c) and (e)(1) through (4) of this
section.
(1) Locate the device in a position(s) that provides a
representative measurement of the total sorbent injection rate.
(2) Install and calibrate the device in accordance with
manufacturer's procedures and specifications.
(3) At least monthly, inspect all components for integrity and all
electrical connections for continuity.
(4) At least annually, calibrate the device in accordance with the
manufacturer's procedures and specifications.
(f) If you use a fabric filter to comply with the requirements of
this subpart, you must install, calibrate, maintain, and continuously
operate a bag leak detection system as specified in paragraphs (f)(1)
through (8) of this section.
(1) You must install and operate a bag leak detection system for
each exhaust stack of the fabric filter.
(2) Each bag leak detection system must be installed, operated,
calibrated, and maintained in a manner consistent with the
manufacturer's written specifications and recommendations and in
accordance with the guidance provided in ``Fabric Filter Bag Leak
Detection Guidance,'' EPA-454/R-98-015, September 1997.
(3) The bag leak detection system must be certified by the
manufacturer to be capable of detecting particulate matter emissions at
concentrations of 10 milligrams per actual cubic meter or less.
(4) The bag leak detection system sensor must provide output of
relative or absolute particulate matter loadings.
(5) The bag leak detection system must be equipped with a device to
[[Page 1707]]
continuously record the output signal from the sensor.
(6) The bag leak detection system must be equipped with an alarm
system that will sound automatically when an increase in relative
particulate matter emissions over a preset level is detected. The alarm
must be located where it is easily heard by plant operating personnel.
(7) For positive pressure fabric filter systems, a bag leak
detection system must be installed in each baghouse compartment or
cell. For negative pressure or induced air fabric filters, the bag leak
detector must be installed downstream of the fabric filter.
(8) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limitations and work practice standards?
(a) You must demonstrate initial compliance with each emission
limitation and work practice standard that applies to you according to
Tables 5.A through 5.E and 6 to this subpart.
(b) For new or reconstructed boilers or process heaters in one of
the liquid fuel subcategories that burn only fossil fuels and other
gases and do not burn any residual oil, you are not required to conduct
a performance test to demonstrate compliance with the emission limits.
(1) To demonstrate initial compliance, you must include a signed
statement in the Notification of Compliance Status report required in
Sec. 63.7545(e) that indicates you burn only liquid fossil fuels other
than residual oils either alone or in combination with gaseous fuels.
(2) You must also keep records, as required in Sec. 63.7555, that
demonstrate that you burn only liquid fossil fuels other than residual
oils either alone or in combination with gaseous fuels.
(c) You must establish each site-specific operating limit in Tables
2.A and 2.B to this subpart that applies to you according to the
requirements in Sec. 63.7520, Tables 4.A through 4.E to this subpart,
and paragraphs (c)(1) through (6) of this section, as applicable.
(1) If you do not use a wet or dry scrubber, you must set your
operating limit for hydrogen chloride emissions based on the chlorine
fuel input established during the initial performance test according to
the procedures in paragraphs (c)(1)(i) and (ii) of this section.
(i) During the initial performance test for hydrogen chloride, you
must measure the average hourly fuel input, average chlorine
concentration, and average heat input of each fuel burned during the 3-
hour performance test.
(ii) You must set your operating limit for hydrogen chloride using
Equation 1 of this section:
[GRAPHIC] [TIFF OMITTED] TP13JA03.000
Where:
Clinput = Average amount of chlorine entering the boiler or
process heater through fuels burned in units of pounds per Btu. This is
the operating limit.
Ci = Average concentration of chlorine in fuel, i, during
each of the three 1-hour test periods as measured using the test
methods specified in Tables 4.C and 4.D to this subpart, in units of
pound per pound for solid fuels, pounds per gallon for liquid fuels, or
pound per dry standard cubic foot for gaseous fuels.
Qi = Average hourly input of fuel, i, during each of the
three 1-hour test periods in units of pound per hour for solid fuels,
gallons per hour for liquid fuels, or dry standard cubic feet per hour
for gaseous fuels. If you do not burn multiple fuels during the
performance test, it is not necessary to determine the value of this
term. Insert a value of ``1'' for Qi.
Hv,i = Average heat input of fuel, i, during each of the
three 1-hour test periods in units of Btu per hour as measured by the
test methods indicated in Tables 4.C and 4.D to this subpart.
n = Number of different fuel types in the worst-case fuel input stream
burned during each of the three 1-hour performance tests.
(2) If you do not use a wet scrubber, you must establish an opacity
operating limit during the initial performance test for particulate
matter or total selected metals and mercury. This opacity level must
not exceed 20 percent.
(3) If you use a wet scrubber and you conduct separate performance
tests for particulate matter, hydrogen chloride, and mercury emissions,
you must establish one set of operating limits for pH, liquid flow-
rate, and pressure drop. The pH must be the level established during
the hydrogen chloride performance test. The liquid flow-rate and
pressure drop operating limits must be the highest of the values
established during the performance tests.
(4) If you do not use a control device or do not want to take
credit for the control device and you choose to comply with the
alternative total selected metals emission limit instead of particulate
matter, you must set your operating limit for total selected metals
emissions based on the metals fuel input established during the initial
performance test according to the procedures in paragraphs (c)(4)(i)
and (ii) of this section.
(i) During the initial performance test for total selected metals,
you must measure the average hourly fuel input if you burn a
combination of multiple fuels, average total selected metals
concentration of the fuel input, and average heat input of each fuel
burned during the 3-hour performance test.
(ii) You must set your operating limit for total selected metals
using Equation 2 of this section:
[GRAPHIC] [TIFF OMITTED] TP13JA03.001
Where:
Metalsinput = Average amount of total selected metals
entering the boiler or process heater through fuels burned in units of
pounds per Btu. This is the operating limit.
Mi = Average concentration of total selected metals in fuel,
i, during each of the three 1-hour test periods as measured using the
test methods specified in Table 4.E to this subpart, in units of pound
per pound for solid fuels, pound per gallon for liquid fuels, or pound
per dry standard cubic foot for gaseous fuels.
Qi = Average hourly input of fuel, i, during each of the
three 1-hour test periods in units of pounds per hour for solid fuels,
gallons per hour for liquid fuels, or dry standard cubic feet per hour
for gaseous fuels. If you do not burn multiple fuels during the
performance test, it is
[[Page 1708]]
not necessary to determine the value of this term. Insert a value of
``1'' for Qi.
Hv,i = Average heat input of fuel, i, during each of the
three 1-hour test periods in units of Btu per hour as measured by the
test methods indicated in Table 4.E to this subpart.
n = Number of different fuel types in the worst-case fuel input stream
burned during the 3-hour performance test.
(5) If you do not use a control device or do not want to take
credit for the control device, you must set your operating limit for
mercury emissions based on the mercury fuel input established during
the initial performance test according to the procedures in paragraphs
(c)(5)(i) and (ii) of this section.
(i) During the initial performance test for mercury, you must
measure the average hourly fuel input if you burn a combination of
multiple fuels, average mercury concentration of the fuel input, and
average heat input of each fuel burned during the 3-hour performance
test.
(ii) You must set your operating limit for mercury using Equation 3
of this section:
[GRAPHIC] [TIFF OMITTED] TP13JA03.002
Where:
Mercuryinput = Average amount of mercury entering the boiler
or process heater through fuels burned in units of pounds per Btu. This
is the operating limit.
HGi = Average concentration of mercury in fuel, i, during
each of the three 1-hour test periods as measured using the test
methods specified in Table 4.E to this subpart, in units of pound per
pound for solid fuels, pound per gallon for liquid fuels, or pound per
dry standard cubic foot for gaseous fuels.
Qi = Average hourly input of fuel, i, during each of the
three 1-hour test periods in units of pounds per hour for solid fuels,
gallons per hour for liquid fuels, or dry standard cubic feet per hour
for gaseous fuels. If you do not burn multiple fuels during the
performance test, it is not necessary to determine the value of this
term. Insert a value of ``1'' for Qi.
Hv,i = Average heat input of fuel, i, during each of the
three 1-hour test periods in units of Btu per hour as measured by the
test methods indicated in Table 4.E to this subpart.
n = Number of different fuel types in the worst-case fuel input stream
burned during the 3-hour performance test.
(6) You must establish parameter operating limits according to
paragraphs (c)(6)(i) through (v) of this section.
(i) To establish an opacity operating limit, you must set the
maximum opacity operating limit equal to the maximum 1-hour average
opacity value measured during the three-run performance test for
particulate matter or total selected metals and mercury, or 20 percent,
whichever is lower.
(ii) To establish operating limits for a wet scrubber, you must set
the minimum operating limits for pH, liquid flow-rate, and pressure
drop equal to the minimum 1-hour average values measured during the
three-run performance test.
(iii) To establish operating limits for an electrostatic
precipitator, you must set the minimum operating limits for voltage and
secondary current (or total power input) equal to the minimum 1-hour
average values measured during the three-run performance test.
(iv) To establish operating limits for a dry scrubber, you must set
the minimum sorbent injection rate operating limit equal to the minimum
1-hour average value measured during the three-run performance test.
(v) The operating limit for fabric filters requires that a bag leak
detection system be installed according to the requirements in Sec.
63.7525, and that each fabric filter must be operated such that the bag
leak detection system alarm does not sound more than 5 percent of the
operating time during a 6-month period.
(d) You must submit the Notification of Compliance Status report
containing the results of the initial compliance demonstration
according to the requirements in Sec. 63.7545(e).
Continuous Compliance Requirements
Sec. 63.7535 How do I monitor and collect data to demonstrate
continuous compliance?
(a) You must monitor and collect data according to this section.
(b) Except for monitor malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must monitor continuously (or collect data at all required
intervals) at all times that the affected source is operating.
(c) You may not use data recorded during monitoring malfunctions,
associated repairs, or required quality assurance or control
activities, in data averages and calculations used to report emission
or operating levels. You must use all the data collected during all
other periods in assessing the operation of the control device and
associated control system.
Sec. 63.7540 How do I demonstrate continuous compliance with the
emission limitations and work practice standards?
(a) You must demonstrate continuous compliance with each emission
limit, operating limit, and work practice standard in Tables 1 through
3 to this subpart that applies to you according to the methods
specified in Tables 7.A, 7.B, and 8 to this subpart and paragraphs
(a)(1) through (9) of this section.
(1) For affected sources electing to comply with an emission limit
based on fuel analysis, you must keep records of all fuels burned in
each boiler or process heater during the reporting period to
demonstrate that all fuels used would result in lower emissions of
particulate matter or total selected metals, lower emissions of
hydrogen chloride, and lower emissions of mercury than the emissions
from the worst-case fuel input that was burned during the initial
performance test. You must also keep records that demonstrate that all
fuels burned during the reporting period were obtained from the same
suppliers as those fuels burned during the performance test.
(2) For new or reconstructed boilers or process heaters in one of
the liquid fuel subcategories that burn only fossil fuels and other
gases and do not burn any residual oil, you are not required to set and
maintain operating limits to demonstrate continuous compliance with the
emission limits. To demonstrate continuous compliance with the emission
limits, you must include a signed statement in each semiannual
compliance report required in Sec. 63.7550 that indicates you burned
[[Continued on page 1709]]
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[[pp. 1709-1758]] National Emission Standards for Hazardous Air Pollutants for
Industrial/Commercial/Institutional Boilers and Process Heaters
[[Continued from page 1708]]
[[Page 1709]]
only liquid fossil fuels other than residual oils, either alone or in
combination with gaseous fuels, during the reporting period; and you
must also keep records, as required in paragraph (a)(1) of this section
and Sec. 63.7555, that demonstrate that you burn only liquid fossil
fuels other than residual oils, either alone or in combination with
gaseous fuels.
(3) If you plan to burn a new type of fuel, a fuel from a new
supplier, or a new mixture of fuels and your operating limit for
hydrogen chloride is chlorine input, you must demonstrate continuous
compliance by recalculating the chlorine input using Equation 1 of
Sec. 63.7530 according to the procedures specified in paragraphs
(a)(3)(i) through (iii) of this section.
(i) Determine for any new fuel the heating value and the chlorine
concentration, based on supplier data or own fuel analysis, according
to the provisions in the site-specific test plan developed according to
the requirements in Sec. 63.7520(a).
(ii) Estimate the maximum hourly input at which each fuel will be
burned.
(iii) Recalculate the amount of chlorine that would be put into the
boiler or process heater during an hour under these new conditions
using Equation 1 of Sec. 63.7530.
(4) If you plan to burn a new type of fuel, a fuel from a new
supplier or a new mixture of fuels, your operating limit for hydrogen
chloride is chlorine input, and the results of recalculating the
chlorine input using Equation 1 of Sec. 63.7530 are higher than the
chlorine input operating limit established during the initial
performance test, then you must conduct a new performance test
according to the procedures in Sec. 63.7520 to demonstrate that the
hydrogen chloride emissions do not exceed the emission limitation. You
must also establish a new operating limit based on this performance
test according to the procedures in Sec. 63.7530(c).
(5) If you plan to burn a new type of fuel, a fuel from a new
supplier, or a new mixture of fuels and you choose to comply with the
alternative total selected metals emission limit instead of particulate
matter and your operating limit is the total selected metals fuel
content, you must demonstrate continuous compliance with your operating
limit by recalculating the total selected metals input using Equation 2
of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(5)(i) through (iii) of this section.
(i) Determine for any new fuel the heating value and the total
selected metals concentration, based on supplier data or own fuel
analysis, according to the provisions in the site-specific test plan
developed according to the requirements in Sec. 63.7520(a).
(ii) Estimate the maximum hourly input at which each fuel will be
burned.
(iii) Recalculate the amount of total selected metals that would be
put into the boiler or process heater during an hour under these new
conditions using Equation 2 of Sec. 63.7530.
(6) If you plan to burn a new type of fuel, a fuel from a new
supplier or a new mixture of fuels, you choose to comply with the
alternative total selected metals emission limit instead of particulate
matter, and the results of recalculating the total selected metals
input using Equation 2 of Sec. 63.7530 are higher than the total
selected metals operating limit established during the initial
performance test, then you must conduct a new performance test
according to the procedures in Sec. 63.7520 to demonstrate that the
total selected metals emissions do not exceed the emission limit. You
must also establish a new operating limit based on this performance
test according to the procedures in Sec. 63.7530(c).
(7) If you plan to burn a new type of fuel, a fuel from a new
supplier, or a new mixture of fuels and your operating limit for
mercury emissions is the mercury fuel content, you must demonstrate
continuous compliance with your operating limit by recalculating the
mercury input using Equation 3 of Sec. 63.7530 according to the
procedures specified in paragraphs (a)(7)(i) through (iii) of this
section.
(i) Determine for any new fuel the heating value and the mercury
concentration, based on supplier data or own fuel analysis, according
to the provisions in the site-specific test plan developed according to
the requirements in Sec. 63.7520(a).
(ii) Estimate the maximum hourly input at which each fuel will be
burned.
(iii) Recalculate the amount of mercury that would be put into the
boiler or process heater during an hour under these new conditions
using Equation 3 of Sec. 63.7530.
(8) If you plan to burn a new type of fuel, a fuel from a new
supplier or a new mixture of fuels, and the results of recalculating
the mercury input using Equation 3 of Sec. 63.7530 are higher than the
mercury operating limit established during the initial performance
test, then you must conduct a new performance test according to the
procedures in Sec. 63.7520 to demonstrate that the mercury emissions
do not exceed the emission limit. You must also establish a new
operating limit based on this performance test according to the
procedures in Sec. 63.7530(c).
(9) If your unit is controlled with a fabric filter, you must
demonstrate continuous compliance with the operating limits for fabric
filters by operating each fabric filter system such that the bag leak
detection system does not sound more than 5 percent of the operating
time during a 6-month period and by keeping records of the date, time,
and duration of each alarm, the time corrective action was initiated
and completed, a brief description of the cause of the alarm and the
corrective action taken. You must also record the percent of the
operating time during each 6-month period that the alarm sounds. In
calculating this operating time percentage, if inspection of the fabric
filter demonstrates that no corrective action is required, no alarm
time is counted. If corrective action is required, each alarm shall be
counted as a minimum of 1 hour. If you take longer than 1 hour to
initiate corrective action, the alarm time shall be counted as the
actual amount of time taken to initiate corrective action.
(b) You must report each instance in which you did not meet each
emission limit and each operating limit in Tables 7.A and 7.B to this
subpart that apply to you. This includes periods of startup, shutdown,
and malfunction. You must also report each instance in which you did
not meet the work practice requirements in Table 8 to this subpart that
apply to you. These instances are deviations from the emission
limitations and work practice standards in this subpart. These
deviations must be reported according to the requirements in Sec.
63.7550.
(c) During periods of startup, shutdown, and malfunction, you must
operate in accordance with the startup, shutdown, and malfunction plan
as required in Sec. 63.7505(d).
(d) Consistent with Sec. Sec. 63.6(e) and 63.7(e)(1), deviations
that occur during a period of startup, shutdown, or malfunction are not
violations if you demonstrate to the Administrator's satisfaction that
you were operating in accordance with the startup, shutdown, and
malfunction plan. The Administrator will determine whether deviations
that occur during a period of startup, shutdown, or malfunction are
violations, according to the provisions in Sec. 63.6(e).
Notifications, Reports, and Records
Sec. 63.7545 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec. Sec.
63.6(h)(4) and (5), 63.7(b) and (c), 63.8 (e), 63.8(f)(4) and
[[Page 1710]]
(6), and 63.9 (b) through (h) that apply to you by the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you startup your affected
source before [DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL
REGISTER], you must submit an Initial Notification not later than 120
calendar days after [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL
REGISTER]. The Initial Notification must include the information
required in paragraphs (b)(1) and (2) of this section, as applicable.
(1) If your affected source has an annual capacity factor of
greater than 10 percent, your Initial Notification must include the
information required by Sec. 63.9(b)(2).
(2) If your affected source has a federally enforceable permit that
limits the annual capacity factor to less than or equal to 10 percent
such that the unit is in one of the limited use subcategories (the
limited use solid fuel subcategory, the limited use liquid fuel
subcategory, or the limited use gaseous fuel subcategory), your Initial
Notification must include the information required by Sec. 63.9(b)(2)
and also a signed statement indicating your affected source has a
federally enforceable permit that limits the annual capacity factor to
less than or equal to 10 percent.
(c) As specified in Sec. 63.9(b)(3), if you startup your new or
reconstructed affected source on or after [DATE THE FINAL RULE IS
PUBLISHED IN THE FEDERAL REGISTER], you must submit an Initial
Notification not later than 120 calendar days after you become subject
to this subpart. The Initial Notification must include the information
required in paragraphs (c)(1) and (2) of this section, as applicable.
(1) If your affected source has an annual capacity factor of
greater than 10 percent, your Initial Notification must include the
information required by Sec. 63.9(b)(3).
(2) If your affected source has a federally enforceable permit that
limits the annual capacity factor to less than or equal to 10 percent
such that the unit is in one of the limited use subcategories, your
Initial Notification must include the information required by Sec.
63.9(b)(3) and also a signed statement indicating your affected source
has a federally enforceable permit that limits the annual capacity
factor to less than or equal to 10 percent.
(d) If you are required to conduct a performance test, you must
submit a notification of intent to conduct a performance test at least
60 calendar days before the performance test is scheduled to begin as
required in Sec. 63.7(b)(1).
(e) If you are required to conduct a performance test or other
initial compliance demonstration as specified in Tables 4.A through
4.E, 5.A through 5.E, or 6 to this subpart, you must submit a
Notification of Compliance Status report according to Sec.
63.9(h)(2)(ii) and the requirements specified in paragraphs (e)(1)(i)
through (e)(1)(vii) of this section.
(1) For each initial compliance demonstration, you must submit the
Notification of Compliance Status report, including all performance
test results, before the close of business on the 60th calendar day
following the completion of the performance test and/or other initial
compliance demonstrations according to Sec. 63.10(d)(2). The
Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(l)(i) through (vii) of this
section, as applicable.
(i) A description of the affected source(s) including
identification of which subcategory the source is in, the capacity of
the source, a description of the add-on controls used on the source
description of the fuel(s) burned, and justification for the worst-case
fuel burned during the performance test.
(ii) Summary of the results of all performance tests, fuel
analyses, and calculations conducted to demonstrate initial compliance
including all established operating limits.
(iii) Identification of whether you are complying with the
particulate matter emission limit or the alternative total selected
metals emission limit.
(iv) A signed certification that you have met all applicable
emission limitations and work practice standards.
(v) A summary of the carbon monoxide emissions monitoring data
recorded during the performance test to show that you have met the work
practice standard in Table 6 to this subpart, if applicable.
(vi) If your new or reconstructed boiler or process heater is in
one of the liquid fuel subcategories and burns only liquid fossil fuels
other than residual oil either alone or in combination with gaseous
fuels, you must submit a signed statement certifying this in your
Notification of Compliance Status report.
(vii) If you had a deviation from any emission limitation or work
practice standard, you must also submit a description of the deviation,
the duration of the deviation, and the corrective action taken in the
Notification of Compliance Status report.
Sec. 63.7550 What reports must I submit and when?
(a) You must submit each report in Table 9 to this subpart that
applies to you.
(b) Unless the Administrator has approved a different schedule for
submission of reports under Sec. 63.10(a), you must submit each report
by the date in Table 9 to this subpart and according to the
requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.7495 and ending on June 30 or December 31, whichever date is the
first date following the end of the first calendar half after the
compliance date that is specified for your source in Sec. 63.7495.
(2) The first compliance report must be postmarked or delivered no
later than July 31 or January 31, whichever date is the first date
following the end of the first calendar half after the compliance date
that is specified for your source in Sec. 63.7495.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or
delivered no later than July 31 or January 31, whichever date is the
first date following the end of the semiannual reporting period.
(5) For each affected source that is subject to permitting
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the
permitting authority has established dates for submitting semiannual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (b) (1) through (4) of
this section.
(c) The compliance report must contain the information required in
paragraphs (c) (1) through (11) of this section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name,
title, and signature, certifying the truth, accuracy, and completeness
of the content of the report.
(3) Date of report and beginning and ending dates of the reporting
period.
(4) The total fuel use by each affected source electing to comply
with an emission limit based on fuel analysis for each calendar month
within the
[[Page 1711]]
semiannual reporting period including, but not limited to, a
description of the fuel, the total fuel usage amount with units of
measure, and information on the supplier of the fuel and original
source location of the fuel.
(5) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable.
(6) A signed statement indicating that you burned no new types of
fuel, no fuels from a new supplier, or no new fuel mixture. Or, if you
did burn a new type of fuel, a fuel from a new supplier, or a new fuel
mixture and your operating limit for hydrogen chloride is fuel chlorine
input, you must submit the calculation of chlorine input, using
Equation 1 of Sec. 63.7530, that demonstrates that your source is
still within its operating limit for hydrogen chloride emissions. If
you burned a new type of fuel, fuel from a new supplier, or a new fuel
mixture and your operating limit for the alternative total selected
metals emission limit is fuel total selected metals input, you must
submit the calculation of total selected metals input, using Equation 2
of Sec. 63.7530, that demonstrates that your source is still within
its operating limit for total selected metals emissions. If you burned
a new type of fuel, fuel from a new supplier, or a new fuel mixture and
your operating limit for mercury is fuel mercury input, you must submit
the calculation of mercury input, using Equation 3 of Sec. 63.7530,
that demonstrates that your source is still within its operating limit
for mercury emissions.
(7) If you wish to burn a new type of fuel, a fuel from a new
supplier, or a new fuel mixture, and you cannot demonstrate compliance
with the hydrogen chloride operating limit using Equation 1 of Sec.
63.7530, the total selected metals operating limit using Equation 2 of
Sec. 63.7530, or the mercury operating limit using Equation 3 of Sec.
63.7530, you must include in the compliance report a statement
indicating the intent to conduct a new performance test under the new
worst-case conditions.
(8) The average daily hours of operation by each source for each
calendar month within the semiannual reporting period.
(9) If you had a startup, shutdown, or malfunction during the
reporting period and you took actions consistent with your startup,
shutdown, and malfunction plan, the compliance report must include the
information in Sec. 63.10(d)(5)(i).
(10) If there are no deviations from any emission limitations
(emission limits or operating limits) in this subpart that apply to you
and there are no deviations from the requirements for work practice
standards in Table 8 to this subpart, a statement that there were no
deviations from the emission limitations or work practice standards
during the reporting period.
(11) If there were no periods during which the CMS, including CEMS,
COMS, and CPMS, were out-of-control as specified in Sec. 63.8(c)(7), a
statement that there were no periods during which the CMS were out-of-
control during the reporting period.
(d) For each deviation from an emission limitation (emission limits
or operating limits) in this subpart and for each deviation from the
requirements for work practice standards in Table 8 to this subpart
that occurs at an affected source where you are not using CMS to comply
with that emission limitation or work practice standard, the compliance
report must contain the information in paragraphs (c) (1) through (11)
of this section and the information required in paragraphs (d) (1)
through (4) of this section. This includes periods of startup,
shutdown, and malfunction.
(1) The total operating time of each affected source during the
reporting period.
(2) A description of the deviation and which limitation you
deviated from.
(3) Information on the number, duration, and cause of deviations
(including unknown cause), as applicable, and the corrective action
taken.
(4) A copy of the test report if the annual performance test showed
a deviation from the emission limit for particulate matter or the
alternative total selected metals limit, a deviation from the hydrogen
chloride emission limit, or a deviation from the mercury emission
limit.
(e) For each deviation from an emission limitation (emission
limitation and operating limit) or work practice standard in this
subpart occurring at an affected source where you are using a CMS to
comply with that emission limitation or work practice standard, you
must include the information in paragraphs (c) (1) through (11) of this
section and the information required in paragraphs (e) (1) through (12)
of this section. This includes periods of startup, shutdown, and
malfunction and any deviations from your site-specific monitoring plan
as required in Sec. 63.7505(c).
(1) The date and time that each malfunction started and stopped and
description of the nature of the deviation (i.e., what you deviated
from).
(2) The date and time that each CMS was inoperative, except for
zero (low-level) and high-level checks.
(3) The date, time, and duration that each CMS was out-of-control,
including the information in Sec. 63.8(c)(8).
(4) The date and time that each deviation started and stopped, and
whether each deviation occurred during a period of startup, shutdown,
or malfunction or during another period.
(5) A summary of the total duration of the deviation during the
reporting period and the total duration as a percent of the total
source operating time during that reporting period.
(6) A breakdown of the total duration of the deviations during the
reporting period into those that are due to startup, shutdown, control
equipment problems, process problems, other known causes, and other
unknown causes.
(7) A summary of the total duration of CMS downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
(8) An identification of each parameter that was monitored at the
affected source for which there was a deviation, including opacity,
carbon monoxide, and operating parameters for wet scrubbers and other
control devices.
(9) A brief description of the source for which there was a
deviation.
(10) A brief description of each CMS for which there was a
deviation.
(11) The date of the latest CMS certification or audit for the
system for which there was a deviation.
(12) A description of any changes in CMSs, processes, or controls
since the last reporting period for the source for which there was a
deviation.
(f) Each affected source that has obtained a title V operating
permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all
deviations as defined in this subpart in the semiannual monitoring
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source submits a compliance report
pursuant to Table 9 to this subpart along with, or as part of, the
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all
required information concerning deviations from any emission limitation
(including any operating limit), or work practice standard in this
subpart, submission of the compliance report satisfies any obligation
to report the same deviations in the semiannual monitoring report.
[[Page 1712]]
However, submission of a compliance report does not otherwise affect
any obligation the affected source may have to report deviations from
permit requirements to the permit authority.
Sec. 63.7555 What records must I keep?
(a) You must keep records according to paragraphs (a) (1) through
(3) of this section.
(1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status or semiannual
compliance report that you submitted, according to the requirements in
Sec. 63.10(b)(2)(xiv).
(2) The records in Sec. 63.6(e)(3)(iii) through (v) related to
startup, shutdown, and malfunction.
(3) Records of performance tests or other compliance
demonstrations, performance evaluations, and opacity observations as
required in Sec. 63.10(b)(2)(viii).
(b) For each CEMS, CPMS, and COMS, you must keep records according
to paragraphs (b) (1) through (5) of this section.
(1) Records described in Sec. 63.10(b)(2) (vi) through (xi).
(2) Monitoring data for COMS during a performance evaluation as
required in Sec. 63.6(h)(7) (i) and (ii).
(3) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(4) Request for alternatives to relative accuracy test for CEMS as
required in Sec. 63.8(f)(6)(i).
(5) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
(c) You must keep the records required in Tables 7.A, 7.B, and 8 to
this subpart including records of all monitoring data and calculated
averages for applicable operating limits such as opacity, pressure
drop, carbon monoxide, and pH to show continuous compliance with each
emission limitation, operating limit and work practice standard that
applies to you.
(d) You must also keep the records in paragraphs (d) (1) through
(5) of this section.
(1) You must keep records of daily fuel use by each source electing
to comply with an emission limit based on fuel analysis, including the
type(s) of fuel, amount(s) used, and the supplier(s) and original
source location(s).
(2) You must keep records of daily hours of operation by each
source.
(3) A copy of all calculations and supporting documentation of
chlorine fuel input, using Equation 1 of Sec. 63.7530, that were done
to demonstrate continuous compliance with the hydrogen chloride
emission limitation. Supporting documentation should include results of
any fuel analyses and basis for the estimates of maximum fuel input.
(4) A copy of all calculations and supporting documentation of
total selected metals fuel input, using Equation 2 of Sec. 63.7530,
that were done to demonstrate continuous compliance with the total
selected metals emission limitation. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum fuel input.
(5) A copy of all calculations and supporting documentation of
mercury fuel input, using Equation 3 of Sec. 63.7530, that were done
to demonstrate continuous compliance with the mercury emission
limitation. Supporting documentation should include results of any fuel
analyses and basis for the estimates of maximum fuel input.
(e) If your boiler or process heater has a federally enforceable
permit that limits the annual capacity factor to less than or equal to
10 percent such that the unit is in one of the limited use
subcategories, you must keep the records in paragraphs (e) (1) and (2)
of this section.
(1) A copy of the federally enforceable permit that limits the
annual capacity factor of the source to less than or equal to 10
percent.
(2) Fuel use records for the days the boiler or process heater was
operating.
Sec. 63.7560 In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 63.10(b)(1). You can keep
the records offsite for the remaining 3 years.
Other Requirements and Information
Sec. 63.7565 What parts of the General Provisions apply to me?
Table 10 to this subpart shows which parts of the General
Provisions in Sec. Sec. 63.1 through 63.15 apply to you.
Sec. 63.7570 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the U.S. EPA,
or a delegated authority such as your State, local, or tribal agency.
If the Administrator has delegated authority to your State, local, or
tribal agency, then that agency has the authority to implement and
enforce this subpart. You should contact your EPA Regional Office to
find out if this subpart is delegated to your State, local, or tribal
agency.
(b) In delegating implementation and enforcement authority to this
subpart to a State, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities contained in paragraph (c) of this section
are retained by the Administrator and are not transferred to the State,
local, or tribal agency. The U.S. EPA retains oversight of this rule
and can take enforcement actions, as appropriate.
(c) The authorities that will not be delegated to State, local, or
tribal agencies are listed in paragraphs (c)(1) through (5) of this
section.
(1) Approval of alternatives to the non-opacity emission limits and
work practice standards in Sec. 63.7500(a) through (c) under Sec.
63.6(g).
(2) Approval of alternative opacity emission limits in Sec.
63.7500(a) under Sec. 63.6(h)(9).
(3) Approval of major alternatives to test methods under Sec.
63.7(e)(2)(ii) and (f) and as defined in Sec. 63.90.
(4) Approval of major alternatives to monitoring under Sec.
63.8(f) and as defined in Sec. 63.90.
(5) Approval of major alternatives to recordkeeping and reporting
under Sec. 63.10(f) and as defined in Sec. 63.90.
Sec. 63.7575 What definitions apply to this subpart?
Terms used in this subpart are defined in the Clean Air Act, in
Sec. 63.2, and in this section as follows:
Annual capacity factor means the ratio between the actual heat
input to a boiler or process heater from the fuels burned during a
calendar year and the potential heat input to the boiler or process
heater had it been operated for 8,760 hours during a calendar year at
the maximum steady state design heat input capacity.
Bag leak detection system means an instrument that is capable of
monitoring particulate matter loadings in the exhaust of a fabric
filter (i.e., baghouse) in order to detect bag failures. A bag leak
detection system includes, but is not limited to, an instrument that
operates on electrodynamic, triboelectric, light scattering, light
[[Page 1713]]
transmittance, or other principle to monitor relative particulate
matter loadings.
Biomass fuel means wood, wood residue, and wood products (e.g.,
trees, tree stumps, tree limbs, bark, lumber, sawdust, sanderdust,
chips, scraps, slabs, millings, and shavings); vegetative agricultural
and silvicultural materials, such as logging residues (slash), nut and
grain hulls and chaff (e.g., almond, walnut, peanut, rice, and wheat),
bagasse, orchard prunings, corn stalks, coffee bean hulls and grounds.
Boiler means an enclosed device using controlled flame combustion
and having the primary purpose of recovering thermal energy in the form
of steam or hot water. Waste heat boilers are excluded from this
definition.
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials in ASTM D388-77, ``Standard Specification for Classification
of Coals by Rank,'' coal refuse, and petroleum coke. Synthetic fuels
derived from coal for the purpose of creating useful heat including,
but not limited to, solvent-refined coal, coal-oil mixtures, and coal-
water mixtures, are included in this definition for the purposes to
this subpart.
Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and
a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
Commercial/Institutional boiler means a boiler used in commercial
establishments or institutional establishments such as medical centers,
research centers, institutions of higher education, hotels, and
laundries to provide electricity, steam, and/or hot water.
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limitation
(including any operating limit) or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(3) Fails to meet any emission limitation (including any operating
limit) or work practice standard in this subpart during startup,
shutdown, or malfunction, regardless of whether or not such failure is
permitted by this subpart.
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society for Testing and
Materials in ASTM D396-78, ``Standard Specifications for Fuel Oils.''
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material.
Electric utility steam generating unit means a fossil fuel-fired
combustion unit of more than 25 megawatts that serves a generator that
produces electricity for sale. A unit that cogenerates steam and
electricity and supplies more than one-third of its potential electric
output capacity and more than 25 megawatts electrical output to any
utility power distribution system for sale is considered an electric
utility steam generating unit.
Electrostatic precipitator means an add-on air pollution control
device used to capture particulate matter by charging the particles
using an electrostatic field, collecting the particles using a grounded
collecting surface, and transporting the particles into a hopper.
Emission limitation means any emission limit or operating limit.
Fabric filter means an add-on air pollution control device used to
capture particulate matter by filtering gas streams through filter
media, also known as a baghouse.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or 51.18 and 51.24.
Firetube boiler means a boiler in which hot gases of combustion
pass through the tubes and water contacts the outside surfaces of the
tubes.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials.
Gaseous fuel includes, but is not limited to, natural gas, process
gas, refinery gas and biogas.
Heat input means heat derived from combustion of fuel in a boiler
or process heater and does not include the heat input from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources such as gas turbines, internal combustion engines, kilns, etc.
Hot water heater means a closed vessel 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
(psig), including the apparatus by which the heat is generated and all
controls and devices necessary to prevent water temperatures from
exceeding 210[deg]F (99[deg]C).
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam, hot water,
and/or electricity.
Large gaseous fuel subcategory means any boiler or process heater
that burns only gaseous fuels not combined with any liquid or solid
fuels, has a rated capacity of greater than 10 MMBtu per hour heat
input, and has an annual capacity factor of greater than 10 percent.
Large liquid fuel subcategory means any boiler or process heater
that does not burn any solid fuel and burns any liquid fuel either
alone or in combination with gaseous fuels, has a rated capacity of
greater than 10 MMBtu per hour heat input, and has an annual capacity
factor of greater than 10 percent.
Large solid fuel subcategory means any watertube boiler or process
heater that burns any amount of solid fuel either alone or in
combination with liquid or gaseous fuels, has a rated capacity of
greater than 10 MMBtu per hour heat input, and has an annual capacity
factor of greater than 10 percent.
Limited use gaseous fuel subcategory includes any boiler or process
heater that burns only gaseous fuels not combined with any liquid or
solid fuels, has a rated capacity of greater than 10 MMBtu per hour
heat input, and has a federally enforceable annual average capacity
factor of equal to or less than 10 percent.
Limited use liquid fuel subcategory includes any boiler or process
heater that does not burn any solid fuel and burns any liquid fuel
either alone or in combination with gaseous fuels, has a rated capacity
of greater than 10 MMBtu per hour heat input, and has a federally
enforceable annual average capacity factor of equal to or less than 10
percent.
Limited use solid fuel subcategory includes any boiler or process
heater that burns any amount of solid fuel either alone or in
combination with liquid or gaseous fuels, has a rated capacity of
greater than 10 MMBtu per hour heat input, and has a federally
enforceable annual average capacity factor of equal to or less than 10
percent.
[[Page 1714]]
Liquid fossil fuel means petroleum, distillate oil, residual oil
and any form of liquid fuel derived from such material.
Liquid fuel includes, but is not limited to, distillate oil,
residual oil, waste oil, and process liquids.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society for
Testing and Materials in ASTM D1835-82, ``Standard Specification for
Liquid Petroleum Gases.''
Opacity means the degree to which emissions reduce the transmission
of light and obscure the view of an object in the background.
Particulate matter means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an alternative method.
Process heater means an enclosed device using controlled flame, and
the unit's primary purpose is to transfer heat indirectly to a process
stream (liquid, gas, or solid) or to a heat transfer material for use
in a process unit instead of generating steam. Process heaters are
devices in which the combustion gases do not directly come into contact
with process materials.
Residual oil means crude oil, fuel oil numbers 1 and 2 that have a
nitrogen content greater than 0.05 weight percent, and all fuel oil
numbers 4, 5 and 6, as defined by the American Society for Testing and
Materials in ASTM D396-78, ``Standard Specifications for Fuel Oils.''
Responsible official means responsible official as defined in Sec.
70.2.
Small gaseous fuel subcategory includes any boiler or process
heater that burns only gaseous fuels not combined with any liquid or
solid fuels, and has a rated capacity of less than or equal to 10 MMBtu
per hour heat input.
Small liquid fuel subcategory includes any boiler or process heater
that does not burn any solid fuel, and burns any liquid fuel either
alone or in combination with gaseous fuels, and has a rated capacity of
less than or equal to 10 MMBtu per hour heat input.
Small solid fuel subcategory includes any firetube boiler that
burns any amount of solid fuel either alone or in combination with
liquid or gaseous fuels, and any other boiler or process heater that
burns any amount of solid fuel either alone or in combination with
liquid or gaseous fuels, and has a rated capacity of less than or equal
to 10 MMBtu per hour heat input.
Solid fuel includes, but is not limited to, coal, wood, biomass,
tires, plastics, and other nonfossil solid materials.
Total selected metals means the combination of the following
metallic hazardous air pollutants: arsenic, beryllium, cadmium,
chromium, lead, manganese, nickel and selenium.
Waste heat boiler means a device that recovers normally unused
energy and converts it to usable heat. Waste heat boilers are also
referred to as heat recovery steam generators.
Watertube boiler means a boiler in which water passes through the
tubes and hot gases of combustion pass over the outside surfaces of the
tubes.
Wet scrubber means any add-on air pollution control device that
mixes an aqueous stream or slurry with the exhaust gases from a boiler
or process heater to control emissions of particulate matter and/or to
absorb and neutralize acid gases, such as hydrogen chloride.
Work practice standard means any design, equipment, work practice,
or operational standard, or combination thereof, that is promulgated
pursuant to section 112(h) of the Clean Air Act.
Tables to Subpart DDDDD of Part 63
As stated in Sec. 63.7500, you must comply with the following
applicable emission limits:
Table 1 to Subpart DDDDD of Part 63--Emission Limits
------------------------------------------------------------------------
You must meet these emission
For . . . limits . . .
------------------------------------------------------------------------
1. Each new or reconstructed a. Emissions of particulate
industrial, commercial, or matter must not exceed 0.026
institutional boiler or process heater lb per MMBtu of heat input; or
in the large solid fuel subcategory. b. Emissions of total selected
metals must not exceed 0.0001
lb per MMBtu of heat input.
c. Emissions of hydrogen
chloride must not exceed 0.02
lb per MMBtu of heat input.
d. Emissions of mercury must
not exceed 0.000003 lb per
MMBtu of heat input.
----------------------------------------
2. Each new or reconstructed a. Emissions of particulate
industrial, commercial, institutional matter must not exceed 0.03 lb
boiler or process heater in the large per MMBtu of heat input.
liquid fuel subcategory. b. emissions of hydrogen
chloride must not exceed
0.0005 lb per MMBtu of heat
input.
----------------------------------------
3. Each new or reconstructed a. Emissions of particulate
industrial, commercial, or matter must not exceed 0.026
institutional boiler or process heater lb per MMBtu of heat input; or
in the limited use solid fuel b. Emissions of total selected
subcategory. metals must not exceed 0.0001
lb per MMBtu of heat input
c. Emissions of hydrogen
chloride must not exceed 0.02
lb per MMBtu of heat input.
d. Emissions of mercury must
not exceed 0.000003 lb per
MMBtu of heat input.
----------------------------------------
4. Each new or reconstructed a. Emissions of particulate
industrial, commercial, or matter must not exceed 0.03 lb
institutional boiler or process heater per MMBtu of heat input.
in the limited use liquid fuel b. Emissions of hydrogen
subcategory. chloride must not exceed
0.0009 lb per MMBtu of heat
input.
----------------------------------------
[[Page 1715]]
5. Each new or reconstructed a. Emissions of particulate
industrial, commercial, or matter must not exceed 0.026
institutional boiler or process heater lb per MMBtu of heat input; or
in the small solid fuel subcategory. b. Emissions of total selected
metals must not exceed 0.0001
lb per MMBtu of heat input.
c. Emissions of hydrogen
chloride must not exceed 0.02
lb per MMBtu of heat input.
d. Emissions of mercury must
not exceed 0.000003 lb per
MMBtu of heat input.
----------------------------------------
6. Each new or reconstructed a. Emissions of particulate
industrial, commercial, or matter must not exceed 0.03 lb
institutional boiler or process heater per MMBtu of heat input.
in the small liquid fuel subcategory. b. emissions of hydrogen
chloride must not exceed
0.0009 lb per MMBtu of heat
input.
----------------------------------------
7. Each existing industrial, a. Emissions of particulate
commercial, or institutional boiler or matter must not exceed 0.07 lb
process heater in the large solid fuel per MMBtu of heat input; or
subcategory.. b. Emissions of total selected
metals must not exceed 0.001
lb per MMBtu of heat input.
c. Emissions of hydrogen
chloride must not exceed 0.09
lb per MMBtu of heat input.
d. Emissions of mercury must
not exceed 0.000007 lb per
MMBtu of heat input.
----------------------------------------
8. Each existing industrial, a. Emissions of particulate
commercial, or institutional boiler or matter must not exceed 0.21 lb
process heater in the limited use per MMBtu of heat input; or
solid fuel subcategory. b. Emissions of total selected
metals must not exceed 0.001
lb per MMBtu of heat input.
------------------------------------------------------------------------
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
Table 2.A to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters in the Large, Limited Use, or Small Solid Fuel
Subcategories
------------------------------------------------------------------------
You must meet these
For . . . That is controlled operating limits . .
with . . . .
------------------------------------------------------------------------
1. Each new or reconstructed a. An add-on contol i. Maintain opacity
industrial, commercial, or other than a wet to less than or
institutional boiler or scrubber or a dry equal to the
process heater in the large scrubber operating level
solid fuel subcategory, the established during
limited use solid fuel the performance
subcategory, or the small test according to
solid fuel subcategory. the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
particulate matter
and mercury or the
opacity level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
alternative
emission limitation
for total selected
metals and the
mercury emission
limit; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
b. A fabric filter i. Maintain the
either alone or in fabric filter
combination with an operation such that
add-on control the operating limit
other than a wet established for
scrubber or a dry fabric filters in
scrubber. Sec.
63.7530(c)(6)(v) is
maintained; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
[[Page 1716]]
c. A wet scrubber... Maintain the minimum
pH, pressure drop,
and liquid flow-
rate at or above
the operating
levels established
during the
performance test
according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
mercury, and
hydrogen chloride
or the levels
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit.
d. A wet scrubber in i. Maintain the
combination with a minimum pH,
fabric filter. pressure drop, and
liquid flow-rate of
the wet scrubber at
or above the
operating levels
established during
the performance
test according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
hydrogen chloride,
and mercury or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
e. A wet scrubber in Maintain the minimum
combination with an pH, pressure drop,
electrostatic and liquid flow-
precipitator. rate of the wet
scrubber and the
minimum voltage and
secondary current
or total power
input of the
electrostatic
precipitator at or
above the operating
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
hydrogen chloride,
and mercury or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit.
f. A dry scrubber... i. Maintain the
minimum sorbent
injection rate of
the dry scrubber at
or above the
operating levels
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride
emissions; and
ii. Maintain opacity
to less than or
equal to the
operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
particulate matter
and mercury
emissions or the
opacity level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
alternative
emission limits for
total selected
metals and the
mercury emission
limit.
[[Page 1717]]
g. A dry scrubber in i. Maintain minimum
combination with a sorbent injection
fabric filter. rate of the dry
scrubber at or
above the operating
level established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limit for
hydrogen chloride
emissions; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
-----------------------------
2. Each new or reconstructed a. Either no add-on i. Maintain the fuel
industrial, commercial, or controls or add-on total selected
institutional boiler or controls for which metals content to
process heater in the large you do not wish to less than or equal
solid fuel subcategory, the take credit for any to the operating
limited use solid fuel emission reduction level established
subcategory, or the small of total selected during the
solid fuel subcategory that metals or mercury. performance test
is complying with the according to the
alternative total selected provisions in Sec.
metals emission limit 63.7530(c) that
instead of the particulate demonstrated
matter emission limit (this compliance with the
is an option for those emission limit for
units that can demonstrate total selected
compliance on the basis of metals; and
fuel analysis without ii. Maintain the
controls). fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride;
and
iii. Maintain the
fuel mercury
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
mercury.
-----------------------------
3. Each existing industrial, a. An add-on control i. Maintain opacity
commercial, or other than a wet to less than or
institutional boiler or scrubber or a dry equal to the
process heater in the large scrubber. operating level
solid fuel subcategory. established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
particulate matter
and mercury or the
opacity level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
alternative
emission limit for
total selected
metals and the
mercury emission
limit; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
b. A fabric filter i. Maintain the
either alone or in fabric filter
combination with an operation such that
add-on control the operating limit
other than a wet established for
scrubber or a dry fabric filters in
scrubber. Sec.
63.7530(c)(6)(v) is
maintained; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
c. A wet scrubber... Maintain the minimum
pH, pressure drop,
and liquid flow-
rate at or above
the operating
levels established
during the
performance test
according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
hydrogen chloride,
and mercury
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit.
[[Page 1718]]
d. A wet scrubber in i. Maintain the
combination with a minimum pH,
fabric filter. pressure drop, and
liquid flow-rate of
the wet scrubber at
or above the
operating levels
established during
the performance
test according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
hydrogen chloride,
and mercury
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
e. A wet scrubber in Maintain the minimum
combination with an pH, pressure drop,
electrostatic and liquid flow-
precipitator. rate of the wet
scrubber and the
minimum voltage and
secondary current
or total power
input of the
electrostatic
precipitator at or
above the operating
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter,
hydrogen chloride,
and mercury
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
hydrogen chloride,
mercury, and the
alternative total
selected metals
emission limit.
f. A dry scrubber... i. Maintain the
minimum sorbent
injection rate of
the dry scrubber at
or above the
operating levels
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride
emissions; and
ii. Maintain opacity
to less than or
equal to the
operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
particulate matter
and mercury or the
opacity level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
alternative
emission limit for
total selected
metals and the
mercury emission
limit.
g. A dry scrubber in i. Maintain minimum
combination with a sorbent injection
fabric filter. rate of the dry
scrubber at or
above the operating
level established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limit for
hydrogen chloride
emissions; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
-----------------------------
[[Page 1719]]
4. Each existing industrial, a. Either no add-on i. Maintain the fuel
commercial, or controls or add-on total selected
institutional boiler or controls for which metals content to
process heater in the large you do not wish to less than or equal
solid fuel subcategory that take credit for any to the operating
is complying with the emission reduction level established
alternative total selected of total selected during the
metals emission limit metals or mercury. performance test
instead of the particulate according to the
matter emission limit (this provisions in Sec.
is an option for those 63.7530(c) that
units that can demonstrate demonstrated
compliance on the basis of compliance with the
fuel analysis without emission limit for
controls). total selected
metals; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride;
and
iii. Maintain the
fuel mercury
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
mercury.
-----------------------------
5. Each existing industrial, a. An add-on control Maintain opacity to
commercial, or other than a wet less than or equal
institutional boiler or scrubber. to the operating
process heater in the level established
limited use solid fuel during the
subcategory. performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limit for
particulate matter
or the operating
level established
during the
performance test
that demonstrated
compliance with the
alternative
emission limit for
total selected
metals.
b. A fabric filter i. Maintain opacity
either alone or in to less than or
combination with an equal to the
add-on control operating level
other than a wet established during
scrubber. the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
particulate matter
or the operating
level established
during the
performance test
that demonstrated
compliance with the
alternative
emission limit for
total selected
metals; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
c. A wet scrubber... Maintain the minimum
pressure drop and
liquid flow-rate at
or above the
operating levels
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
particulate matter
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
alternative total
selected metals
emission limit.
d. A wet scrubber in i. Maintain the
combination with a minimum pressure
fabric filter. drop and liquid
flow-rate at or
above the operating
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limit for
particulate matter
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
alternative total
selected metals
emission limit; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
[[Page 1720]]
e. A wet scrubber in Maintain the minimum
combination with an pressure drop and
electrostatic c liquid flow-rate of
precipitator. the wet scrubber
and the minimum
voltage and
secondary current
of the
electrostatic
precipitator at or
above the operating
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limit for
particulate matter
emissions or the
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
alternative total
selected metals
emission limit.
-----------------------------
6. Each existing industrial, Either no add-on Maintain the fuel
commercial, or controls for which total selected
institutional boiler or you do not wish to metals content to
process heater in the take credit for any less than or equal
limited use solid fuel emission reduction to the operating
subcategory that is of total selected level established
complying with the metals. during the
alternative total selected performance test
metals emission limit according to the
instead of the particulate provisions in Sec.
matter emission limit (this 63.7530(c) that
is an option for those demonstrated
units that can demonstrate compliance with the
compliance on the basis of emission limit for
fuel analysis without total selected
controls). metals.
------------------------------------------------------------------------
As stated in Sec. 63.7500, you must comply with the following
applicable operating limits:
Table 2.B to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters in the Large, Limited Use, or Small Liquid Fuel
Subcategories
------------------------------------------------------------------------
You must meet these
For . . . That is controlled operating limits . .
with . . . .
------------------------------------------------------------------------
1. Each new or reconstructed a. An add-on control i. Maintain opacity
industrial, commercial, other than a wet to less than or
institutional boiler or scrubber or a dry equal to the
process heater in the large scrubber. operating level
liquid fuel subcategory, established during
the limited use liquid fuel the performance
subcategory, or the small test according to
liquid fuel subcategory the provisions in
(boilers or process heaters Sec. 63.7530(c)
in one of the liquid fuel that demonstrated
subcategories that burn compliance with the
only fossil fuels and gases emission limit for
and do not burn any particulate matter;
residual oil are excluded and
from this operating limit). ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
b. A fabric filter i. Maintain the
either alone or in fabric filter
combination with an operation such that
add-on control the operating limit
other than a wet established for
scrubber or a dry fabric filters in
scrubber. Sec.
63.7530(c)(6)(v) is
maintained; and
ii. Maintain the
fuel chlorine
content to less
than or equal to
the operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride.
c. A wet scrubber... Maintain the minimum
pH, pressure drop,
and liquid flow-
rate at or above
the operating
levels established
during the
performance test
according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter
emissions and
hydrogen chloride
emissions.
d. A wet scrubber in i. Maintain the
combination with a minimum pH,
fabric filter. pressure drop, and
liquid flow-rate of
the wet scrubber at
or above the
operating levels
established during
the performance
test according to
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter
emissions and
hydrogen chloride
emissions; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
[[Page 1721]]
e. A wet scrubber in Maintain the minimum
combination with an pH, pressure drop,
electrostatic and liquid flow-
precipitator. rate of the wet
scrubber and the
minimum voltage and
secondary current
or total power
input of the
electrostatic
precipitator at or
above the operating
levels established
during the
performance test
according to the
provisions in Sec.
63.7530(c) that
demonstrated
compliance with the
emission limits for
particulate matter
emissions and
hydrogen chloride
emissions.
f. A dry scrubber... i. Maintain the
minimum sorbent
injection rate of
the dry scrubber at
or above the
operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limits for
hydrogen chloride
emissions; and
ii. maintain opacity
to less than or
equal to the
operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
particulate matter
emissions.
g. A dry scrubber in i. Maintain the
combination with a minimum sorbent
fabric filter. injection rate of
the dry scrubber at
or above the
operating level
established during
the performance
test according to
the provisions in
Sec. 63.7530(c)
that demonstrated
compliance with the
emission limit for
hydrogen chloride
emissions; and
ii. Maintain the
fabric filter
operation such that
the operating limit
established for
fabric filters in
Sec.
63.7530(c)(6)(v) is
maintained.
------------------------------------------------------------------------
As stated in Sec. 63.7500, you must comply with the following
applicable work practice standards:
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
For each . . . You must . . .
------------------------------------------------------------------------
1. New or reconstructed industrial, Continuously monitor carbon
commercial, or institutional boiler or monoxide emissions according
process heater in the large solid fuel to the procedures in Sec.
subcategory, the large liquid fuel 63.7525(a) to maintain carbon
subcategory, or the large gaseous fuel monoxide emissions at or below
subcategory. an exhaust concentration of
400 ppm by volume on a dry
basis corrected to 3 percent
oxygen. The averaging time
shall be 1 calendar day.
----------------------------------------
2. New or reconstructed industrial, Continuously monitor carbon
commercial, or institutional boiler or monoxide emissions according
process heater in the limited use to the procedures in Sec.
solid fuel subcategory, the limited 63.7525(a) to maintain carbon
use liquid fuel subcategory, or the monoxide emissions at or below
limited use gaseous fuel subcategory. an exhaust concentration of
400 ppm by volume on a dry
basis corrected to 3 percent
oxygen. The averaging time
shall be 1 calendar day.
------------------------------------------------------------------------
As stated in Sec. 63.7520, you must comply with the following
requirements for performance test for existing, new or reconstructed
affected sources:
Table 4.A to Subpart DDDDD of Part 63--Requirements for Performance Tests for Particulate Matter Emissions or
Total Selected Metals Emissions From Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel
Subcategories
----------------------------------------------------------------------------------------------------------------
According to the
For . . . That is controlled You must . . . Using . . . following
with . . . requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Each new reconstructed, or a. Any type of 1. Select sampling Method 1 of 40 CFR
existing industrial, device. ports location part 60, appendix
commercial, or institutional and the number of A.
boiler or process heater in the traverse points.
large solid fuel subcategory,
the limited use solid fuel
subcategory, or the small solid
fuel subcategory.
[[Page 1722]]
ii. Determine Either Method 2 in
velocity and appendix A to
volumetric flow- part 60 of this
rate of the stack chapter, Method
gas. 2F in appendix A
to part 60 of
this chapter, or
Method 2G of
appendix A to
part 60 of this
chapter..
iii. Determine Method 3A or 3B in
oxygen and carbon appendix A to
dioxide part 60 of this
concentrations of chapter.
the stack gas.
iv. Measure Method 4 in
moisture content appendix A to
of the stack gas. part 60 of this
chapter.
b. Any type of Measure the Method 5 in
device except particulate appendix A to
positive pressure matter emission part 60 of this
fabric filters. concentrations. chapter or Method
17 in appendix A
to part 60 of
this chapter.
c. Positive Measure the Method 5D in
pressure fabric particulate appendix A to
filters. matter emission part 60 of this
concentrations. chapter
d. Any type of Convert emissions The F-factor
device. concentrations to methodology in
lb per MMBtu Method 19 in
emission rates. appendix A to
part 60 of this
chapter.
---------------------------------
2. Each new reconstructed, or Any type of device Measure the total Method 29 in
existing industrial, selected metals appendix A to
commercial, or institutional emissions part 60 of this
boiler or process heater in the concentrations. chapter.
large solid fuel subcategory,
limited use solid fuel
subcategory, or the small solid
fuel subcategory that is
complying with the alternative
total selected metals emission
limit instead of particulate
matter.
---------------------------------
3. Each new or reconstructed a. Either no add- i. Establish a (1) Data from the (a) You must
industrial, commercial, or on controls or an site-specific continuous collect opacity
institutional boiler or process add-on control maximum opacity opacity monitoring data
heater in the large solid fuel other than a wet level according monitoring system every 10 seconds
subcategory, the limited use scrubber. to provisions in and the PM or during the entire
solid fuel subcategory, or the Sec. 63.7530(c). total selected period of the
small solid fuel subcategory. metals three-run PM or
performance test. total selected
metals
performance test;
and
(b) Determine the
maximum opacity
level of all the
1-hour averages
taken during the
three-run
performance test.
b. A wet scrubber. i. Establish a (1) Data from the (a) You must
site-specific pressure drop and collect pressure
minimum pressure liquid flow-rate drop and liquid
drop and minimum monitors and the flow-rate data
liquid flow-rate PM or total every 15 minutes
operating limit selected metals during the entire
for the wet performance test. period of the
scrubber three-run PM or
according to the total selected
provisions in metals
Sec. performance test;
63.7530(c)(3). and
(b) determine the
average pressure
drop and liquid
flow-rate for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during the test
run.
c. A wet scrubber i. Establish a (1) Data from the (a) You must
in combination site-specific pressure drop and collect pressure
with a fabric minimum pressure liquid flow-rate drop and liquid
filter. drop and liquid monitors and the flow-rate data
flow-rate PM or total for the wet
operating limit selected metals scrubber every 15
for the wet performance test. minutes during
scrubber the entire period
according to the of the three-run
provisions in PM or total
Sec. selected metals
63.7530(c)(3). performance test;
and
(b) Determine the
average pressure
drop and liquid
flow-rate for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during the test
run.
[[Page 1723]]
d. A wet scrubber i. Establish a (1) Data from the (a) You must
in combination site-specific pressure drop and collect pressure
with an minimum pressure liquid flow-rate drop and liquid
electrostatic drop and liquid monitors for the flow-rate data
precipitator. flow-rate for the wet scrubber and for the wet
wet scrubber and from total scrubber and
minimum voltage current and secondary current
and secondary voltage monitors and voltage or
current or total for the total power input
power input of electrostatic for the
the electrostatic precipitator or electrostatic
precipitator and the PM or precipitator
according to the total selected every 15 minutes
provisions in metals during the entire
Sec. performance test. period of the
63.7530(c)(3). three-run PM or
total selected
metals
performance test;
and
(b) Determine the
average for each
by computing the
average of all 15-
minute readings
taken during the
test run.
---------------------------------
4. Each new or reconstructed a. Either no add- i. Establish a (1) The fuel total (a) You must
industrial, commercial, on controls or an site-specific selected metals collect one
institutional boiler or process add-on control maximum inlet content analysis sample of the
heater in the large solid fuel for which you do fuel total results and the worst-case fuel
subcategory, the limited use not wish to take selected metals calculations done stream entering
solid fuel subcategory, or the credit for content operating according to the the boiler or
small solid fuel subcategory reductions in limit according provisions in process heater
that is complying with the total selected to the provisions Sec. 63.7530(c). for each test run
alternative total selected metals. in Sec. during the three-
metals emission limit instead 63.7530(c). run performance
of the particulate matter test; and
emission limit (this is an (b) Determine the
option for those units that can total selected
demonstrate compliance on the metals content
basis of fuel analysis without and heating value
controls). of the sample
according to your
site-specific
test plan as
required in Sec.
63.7520(a); and
(c) Determine the
maximum total
selected metals
content operating
limit according
to the procedures
in Sec.
63.7530(c).
---------------------------------
5. Each existing industrial, a. Either no add- i. Establish a (1) Data from the (a) You must
commercial, or institutional on controls or an site-specific continuous collect opacity
boiler or process heater in the add-on control maximum opacity opacity monitoring data
large solid fuel subcategory or other than a wet level according monitoring system every 10 seconds
the limited use solid fuel scrubber. to provisions in and the PM or during the entire
subcategory. Sec. 63.7530(c). total selected period of the
metals three-run PM or
performance test. total selected
metals
performance test;
and
(b) Determine the
maximum opacity
level for all the
1-hour averages
taken during the
three-run
performance test.
b. A wet scrubber. i. Establish a (1) Data from the (a) You must
site-specific pressure drop and collect pressure
minimum pressure liquid flow-rate drop and liquid
drop and minimum monitors and the flow-rate data
liquid flow-rate PM or total every 15 minutes
operating limit selected metals during the entire
for the wet performance test. period of the
scrubber three-run PM or
according to the total selected
provisions in metals
Sec. performance test;
63.7530(c)(3). and
(b) Determine the
average pressure
drop and liquid
flow-rate for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during the test
run.
c. A wet scrubber i. Establish a (1) Data from the (a) You must
in combination site-specific pressure drop collect pressure
with a fabric minimum pressure liquid flow-rate drop and liquid
filter. drop and liquid monitors and the flow-rate data
flow-rate PM or total for the wet
operating limit selected metals scrubber every 15
for the wet performance test. minutes during
scrubber the entire period
according to the of the three-run
provisions in PM or total
Sec. selected metals
63.7530(c)(3). performance test;
and
(b) Determine the
average pressure
drop and liquid
flow-rate for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during the test
run.
[[Page 1724]]
d. A wet scrubber i. Establish a (1) Data from the (a) You must
in combination site-specific pressure drop and collect pressure
with an electro- minimum pressure liquid flow-rate drop and liquid
static drop and liquid monitors for the flow-rate data
precipitator. flow-rate for the wet scrubber and for the wet
wet scrubber and from the current scrubber and
minimum voltage and voltage secondary current
and secondary monitors for the and voltage or
current or total electrostatic total power input
power input of precipitator and for the
the electrostatic the PM or total electrostatic
precipitator selected metals precipitator
according to the performance test. every 15 minutes
provisions in during the entire
Sec. period of the
63.7530(c)(3). three-run PM or
total selected
metals
performance test;
and
b. Determine the
average for each
by computing the
average of all 15-
minute readings
taken during each
test run.
---------------------------------
6. Each existing industrial, a. Either no add- i. Establish a (1) The fuel total (a) You must
commercial or institutional on controls or an site-specific selected metals collect one
boiler or process heater in the add-on control maximum inlet content analysis sample of the
large solid fuel subcategory or for which you do fuel total results and the worst-case fuel
the limited use solid fuel not wish to take selected metals calculations done stream entering
subcategory that is complying credit for content operating according to the the boiler or
with the alternative total reductions in limit according provisions in process heater
selected metals emission limit total selected to the provisions Sec. 63.7530(c). for each test run
instead of the particulate metals. in Sec. during the three-
matter emission limit (this is 63.7530(c). run performance
an option for those units that test; and
can demonstrate compliance on (b) Determine the
the basis of fuel analysis total selected
without controls). metals content
and heating value
of the sample
according to your
site-specific
test plan as
required in Sec.
63.7520(a); and
(c) Determine the
maximum total
selected metals
content operating
limit according
to the procedures