[Federal Register Volume 75, Number 107 (Friday, June 4, 2010)]
[Proposed Rules]
[Pages 32006-32073]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-10827]
[[Page 32005]]
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Part V
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Proposed Rule
Federal Register / Vol. 75 , No. 107 / Friday, June 4, 2010 /
Proposed Rules
[[Page 32006]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-9148-5]
RIN 2060-AG69
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: On September 13, 2004, under authority of section 112 of the
Clean Air Act, EPA promulgated national emission standards for
hazardous air pollutants for new and existing industrial/commercial/
institutional boilers and process heaters. On June 19, 2007, the United
States Court of Appeals for the District of Columbia Circuit vacated
and remanded the national emission standards for hazardous air
pollutants for industrial/commercial/institutional boilers and process
heaters.
In response to the court's vacatur and remand, this action would
require all major sources to meet hazardous air pollutants emissions
standards reflecting the application of the maximum achievable control
technology. The proposed rule would protect air quality and promote
public health by reducing emissions of the hazardous air pollutants
listed in section 112(b)(1) of the Clean Air Act.
We are also proposing that existing major source facilities with an
affected boiler undergo an energy assessment on the boiler system to
identify cost-effective energy conservation measures.
DATES: Comments must be received on or before July 19, 2010. Under the
Paperwork Reduction Act, comments on the information collection
provisions are best assured of having full effect if the Office of
Management and Budget (OMB) receives a copy of your comments on or
before July 6, 2010.
Public Hearing. We will hold a public hearing concerning this
proposed rule and the interrelated proposed Boiler area source, CISWI,
and RCRA rules, discussed in this proposal and published in the
proposed rules section of today's Federal Register, on June 21, 2010.
Persons requesting to speak at a public hearing must contact EPA by
June 14, 2010.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by one of the following methods:
http://www.regulations.gov. Follow the instructions for
submitting comments.
http://www.epa.gov/oar/docket.html. Follow the
instructions for submitting comments on the EPA Air and Radiation
Docket Web site.
E-mail: Comments may be sent by electronic mail (e-mail)
to [email protected], Attention Docket ID No. EPA-HQ-OAR-2002-
0058.
Fax: Fax your comments to: (202) 566-9744, Docket ID No.
EPA-HQ-OAR-2002-0058.
Mail: Send your comments to: EPA Docket Center (EPA/DC),
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058.
Please include a total of two copies. In addition, please mail a copy
of your comments on the information collection provisions to the Office
of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA,
725 17th St., NW., Washington, DC 20503.
Hand Delivery or Courier: Deliver your comments to: EPA
Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC 20460. Such deliveries are only accepted during the
Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holiday), and special arrangements
should be made for deliveries of boxed information.
Instructions: All submissions must include agency name and docket
number or Regulatory Information Number (RIN) for this rulemaking. All
comments will be posted without change and may be made available online
at http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
confidential business information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through http://www.regulations.gov, your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. 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. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
Public Hearing: We will hold a public hearing concerning this
proposed rule on June 21, 2010. Persons interested in presenting oral
testimony at the hearing should contact Ms. Pamela Garrett, Energy
Strategies Group, at (919) 541-7966 by June 14, 2010. The public
hearing will be held in the Washington DC area at a location and time
that will be posted at the following Web site: http://www.epa.gov/airquality/combustion. Please refer to this Web site to confirm the
date of the public hearing as well. If no one requests to speak at the
public hearing by June 14, 2010 then the public hearing will be
cancelled and a notification of cancellation posted on the following
Web site: http://www.epa.gov/airquality/combustion.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy
form. Publicly available docket materials are available either
electronically in http://www.regulations.gov or in hard copy at the EPA
Docket Center, Room 3334, 1301 Constitution Ave., NW., Washington, DC.
The 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
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Brian Shrager, Energy Strategies
Group, Sector Policies and Programs Division, (D243-01), Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; Telephone number: (919)
541-7689; Fax number (919) 541-5450; E-mail address:
[email protected].
SUPPLEMENTARY INFORMATION: The information presented in this preamble
is organized as follows:
I. General Information
A. Does this action apply to me?
[[Page 32007]]
B. What should I consider as I prepare my comments to EPA?
C. Where can I get a copy of this document?
D. When would a public hearing occur?
II. Background Information
A. What is the statutory authority for the proposed rule?
B. Summary of the Natural Resources Defense Council v. EPA
Decision
C. Summary of Other Related Court Decisions
D. EPA's Response to the Vacatur
E. What is the relationship between the proposed rule and other
combustion rules?
F. What are the health effects of pollutants emitted from
industrial/commercial/institutional boilers and process heaters?
III. Summary of the Proposed Rule
A. What source categories are affected by the proposed rule?
B. What is the affected source?
C. Does the proposed rule apply to me?
D. What emission limitations and work practice standards must I
meet?
E. What are the startup, shutdown, and malfunction (SSM)
requirements?
F. What are the testing and initial compliance requirements?
G. What are the continuous compliance requirements?
H. What are the notification, recordkeeping and reporting
requirements?
I. Submission of Emissions Test Results to EPA
IV. Rationale for the Proposed Rule
A. How did EPA determine which 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. What other compliance alternatives were considered?
K. How did we select the compliance requirements?
L. What alternative compliance provisions are being proposed?
M. How did EPA determine compliance times for the proposed rule?
N. How did EPA determine the required records and reports for
this proposed rule?
O. How does the proposed rule affect permits?
P. Alternative Standard for Consideration
V. 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. What are the economic impacts?
F. What are the social costs and benefits of the proposed rule?
VI. Public Participation and Request for Comment
VII. Relationship of the Proposed Action to Section 112(c)(6) of the
CAA
VIII. Statutory and Executive Order Reviews
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 (RFA) 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
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by the
proposed standards include:
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Category NAICS code \1\ Examples of potentially regulated entities
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Any industry using a boiler or 211 Extractors of crude petroleum and natural gas.
process heater as defined in
the proposed rule.
321 Manufacturers of lumber and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries, and manufacturers of coal products.
316, 326, 339 Manufacturers of rubber and miscellaneous plastic products.
331 Steel works, blast furnaces.
332 Electroplating, plating, polishing, anodizing, and coloring.
336 Manufacturers of motor vehicle parts and accessories.
221 Electric, gas, and sanitary services.
622 Health services.
611 Educational services.
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\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected by this
action. To determine whether your facility, company, business,
organization, etc., would be regulated by this action, you should
examine the applicability criteria in 40 CFR 63.7485 of subpart DDDDD
(National Emission Standards for Hazardous Air Pollutants (NESHAP) for
Industrial, Commercial, and Institution Boilers and Process Heaters).
If you have any questions regarding the applicability of this action to
a particular entity, consult either the air permitting authority for
the entity or your EPA regional representative as listed in 40 CFR
63.13 of subpart A (General Provisions).
B. What should I consider as I prepare my comments to EPA?
Do not submit information containing CBI to EPA through http://www.regulations.gov or e-mail. Send or deliver information identified
as CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, U.S.
[[Page 32008]]
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention: Docket ID EPA-HQ-OAR-2002-0058. Clearly mark the part
or all of the information that you claim to be CBI. For CBI information
in a disk or CD-ROM that you mail to EPA, 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 claimed as CBI. In addition to
one complete version of the comment that includes 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.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2.
C. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this proposed action will also be available on the World Wide Web (WWW)
through the Technology Transfer Network (TTN). Following signature, a
copy of the proposed action will be posted on the TTN's policy and
guidance page for newly proposed or promulgated rules at the following
address: http://www.epa.gov/ttn/oarpg/. The TTN provides information
and technology exchange in various areas of air pollution control.
D. When would a public hearing occur?
We will hold a public hearing concerning this proposed rule on June
21, 2010. Persons interested in presenting oral testimony at the
hearing should contact Ms. Pamela Garrett, Energy Strategies Group, at
(919) 541-7966 by June 14, 2010. The public hearing will be held in the
Washington, DC area at a location and time that will be posted at the
following Web site: http://www.epa.gov/airquality/combustion. Please
refer to this Web site to confirm the date of the public hearing as
well. If no one requests to speak at the public hearing by June 14,
2010, then the public hearing will be cancelled and a notification of
cancellation posted on the following Web site: http://www.epa.gov/airquality/combustion.
II. Background Information
A. What is the statutory authority for this proposed rule?
Section 112(d) of the Clean Air Act (CAA) requires EPA to set
emissions standards for hazardous air pollutants (HAP) emitted by major
stationary sources based on the performance of the maximum achievable
control technology (MACT). The MACT standards for existing sources must
be at least as stringent as the average emissions limitation achieved
by the best performing 12 percent of existing sources (for which the
Administrator has emissions information) or the best performing 5
sources for source categories with less than 30 sources (CAA section
112(d)(3)(A) and (B)). This level of minimum stringency is called the
MACT floor. For new sources, MACT standards must be at least as
stringent as the control level achieved in practice by the best
controlled similar source (CAA section 112(d)(3)). EPA also must
consider more stringent ``beyond-the-floor'' control options. When
considering beyond-the-floor options, EPA must consider not only the
maximum degree of reduction in emissions of HAP, but must take into
account costs, energy, and nonair environmental impacts when doing so.
CAA section 112(c)(6) requires EPA to list categories and
subcategories of sources assuring that sources accounting for not less
than 90 percent of the aggregate emissions of each such pollutant
(alkylated lead compounds; polycyclic organic matter;
hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8-
tetrachlorodibenzofurans; and 2,3,7,8-tetrachloroidibenzo-p-dioxin) are
subject to standards under subsection 112(d)(2) or (d)(4). Standards
established under CAA section 112(d)(2) must reflect the performance of
MACT. ``Industrial Coal Combustion,'' ``Industrial Oil Combustion,''
``Industrial Wood/Wood Residue Combustion,'' ``Commercial Coal
Combustion,'' ``Commercial Oil Combustion,'' and ``Commercial Wood/Wood
Residue Combustion'' are listed as source categories for regulation
pursuant to CAA section 112(c)(6) due to emissions of polycyclic
organic matter (POM) and mercury (63 FR 17838, 17848, April 10, 1998).
In the documentation for the 112(c)(6) listing, the commercial fuel
combustion categories included institutional fuel combustion (``1990
Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,''
April 1998).
CAA section 129(a)(1)(A) requires EPA to establish specific
performance standards, including emission limitations, for ``solid
waste incineration units'' generally, and, in particular, for ``solid
waste incineration units combusting commercial or industrial waste''
(section 129(a)(1)(D)). Section 129 defines ``solid waste incineration
unit'' as ``a distinct operating unit of any facility which combusts
any solid waste material from commercial or industrial establishments
or the general public.'' Section 129(g)(1). Section 129 also provides
that ``solid waste'' shall have the meaning established by EPA pursuant
to its authority under the Resource Conservation and Recovery Act.
Section 129(g)(6).
In Natural Resources Defense Council v. EPA, 489 F. 3d 1250, 1257-
61 (DC Cir. 2007), the court vacated the Commercial and Industrial
Solid Waste Incineration (CISWI) Definitions Rule, 70 FR 55568
(September 22, 2005), which EPA issued pursuant to CAA section
129(a)(1)(D). In that rule, EPA defined the term ``commercial or
industrial solid waste incineration unit'' to mean a combustion unit
that combusts ``commercial or industrial waste.'' The rule defined
``commercial or industrial waste'' to mean waste combusted at a unit
that does not recover thermal energy from the combustion for a useful
purpose. Under these definitions, only those units that combusted
commercial or industrial waste and were not designed to, or did not
operate to, recover thermal energy from the combustion would be subject
to section 129 standards. The District of Columbia Circuit (DC Circuit)
rejected the definitions contained in the CISWI Definitions Rule and
interpreted the term ``solid waste incineration unit'' in CAA section
129(g)(1) ``to unambiguously include among the incineration units
subject to its standards any facility that combusts any commercial or
industrial solid waste material at all--subject to the four statutory
exceptions identified in [CAA section 129(g)(1).]'' NRDC v. EPA, 489
F.3d 1250, 1257-58.
CAA section 129 covers any facility that combusts any solid waste;
CAA section 112(g)(6) directs the Agency to the Resource Conservation
and Recovery Act (RCRA) in terms of the definition of solid waste. The
Agency is in the process of defining solid waste for purposes of
Subtitle D of RCRA. EPA initiated a rulemaking to define which
secondary materials are ``solid waste'' for purposes of subtitle D
(nonhazardous waste) of RCRA when burned in a combustion unit. (See
Advance Notice of Proposed Rulemaking (74 FR 41, January 2, 2009)
soliciting comment on whether certain secondary materials used as
alternative fuels or ingredients are solid wastes within the meaning of
Subtitle D of RCRA.) If a unit combusts solid waste, it is subject to
CAA section 129 of the Act, unless it falls within one of the four
specified exceptions in CAA section 129(g).
The solid waste definitional rulemaking under RCRA is being
proposed in a parallel action and is
[[Page 32009]]
relevant to this proceeding because some industrial, commercial, or
institutional boilers and process heaters combust secondary materials
as alternative fuels. If industrial, commercial, or institutional
boilers or process heaters combusts secondary materials that are solid
waste under the proposed definitional rule, those units would be
subject to section 129. The units subject to this rule include those
industrial, commercial, or institutional boilers and process heaters
that do not combust solid waste. EPA recognizes that it has imperfect
information on the exact nature of the secondary materials which
boilers and process heaters combust, including, for example, how much
processing of such materials occurs, if any. We nevertheless used the
information currently available to the Agency to determine which
materials are solid waste and, therefore, subject to CAA section 129,
and which are not solid waste and, therefore, subject to CAA section
112.
B. Summary of the Natural Resources Defense Council v. EPA Decision
On September 13, 2004, EPA issued the NESHAP for Industrial,
Commercial, and Institutional Boilers and Process Heaters (40 CFR
55218) (the Boiler MACT). We identified 18 subcategories of boilers and
process heaters emitting four different types of HAPs. See 69 FR
55,223-24. EPA set out to establish the MACT floor for each subcategory
emitting each HAP according to the effectiveness of various add-on
technologies. (See 68 FR 1660, 1674, Jan. 13, 2003 (proposed rule).)
Applying this methodology, EPA set 25 numerical emission standards. The
2004 final rule established emission limitations for particulate matter
(PM), as a surrogate for non-mercury HAP metals, mercury, and hydrogen
chloride (HCl), as a surrogate for acid gas HAP, for existing large
solid fuel-fired sources only. For the remaining 47 boiler subcategory/
HAP emissions, EPA determined that the appropriate MACT floor was ``no
emissions reduction'' because ``the best-performing sources were not
achieving emissions reductions through the use of an emission control
system and there were no other appropriate methods by which boilers and
process heaters could reduce HAP emissions.'' (69 FR 55,233.)
Accordingly, we established no standards. In addition, we set risk-
based standards, also known as health-based compliance alternatives, as
alternatives to the MACT-based standards for hydrogen chloride and
manganese.
EPA issued emissions standards for CISWI units on December 1, 2000,
and as part of that rulemaking, defined the term ``commercial and
industrial waste'' to mean solid waste combusted in an enclosed device
using controlled flame combustion without energy recovery that is a
distinct operating unit of any commercial or industrial facility. In
response to a petition for reconsideration, EPA filed a motion for
voluntary remand, which the court granted on September 6, 2001. On
remand, EPA solicited comments on the CISWI Rule's definitions of
``solid waste,'' ``commercial and industrial waste'' and ``CISWI
unit.'' On September 22, 2005, EPA issued the CISWI Definitions Rule,
which contained definitions that were substantively the same as those
issued before reconsideration. In particular, the 2005 CISWI
Definitions Rule defined ``commercial or industrial waste'' to include
only waste that is combusted at a facility that cannot or does not use
a process that recovers thermal energy from the combustion for a useful
purpose.
EPA received separate petitions from environmental groups,
industry, and municipalities seeking judicial review of the NESHAP for
Industrial, Commercial, and Institutional Boilers and Process Heaters
(Boiler MACT) as well as amendments to definitional terms in the
Standards of Performance for New Stationary Sources and Emission
Guidelines for Existing Sources: Commercial and Industrial Solid Waste
Incineration Units (CISWI Definitions Rule), promulgated pursuant to
CAA section 129. The environmental organizations challenged the CISWI
Definitions Rule on the ground that its definition of ``commercial or
industrial waste'' was inconsistent with the plain language of CAA
section 129 and therefore impermissibly constricted the class of
``solid waste incineration unit[s]'' that were subject to the emission
standards of the CISWI Rule. The environmental groups also challenged
specific emission standards that EPA promulgated in the Boiler MACT and
EPA's methodology for setting them. The municipalities--the American
Municipal Power-Ohio, Inc. and six of its members, the cities of Dover,
Hamilton, Orrville, Painesville, Shelby and St. Mary's--challenged the
Boiler MACT on the grounds that EPA failed to comply with the
requirements of the Regulatory Flexibility Act (RFA) and that the
standards as applied to small municipal utilities are unlawful.
As explained further below, the Court concluded that EPA's
definition of ``commercial or industrial waste,'' as incorporated in
the definition of ``commercial and industrial solid waste incineration
unit'' (CISWI unit), was inconsistent with the plain language of CAA
section 129 and that the CISWI Definitions Rule must, therefore, be
vacated. The Court also vacated and remanded the Boiler MACT, finding
that the Boiler MACT must be substantially revised as a consequence of
the vacatur and remand of the CISWI Definitions Rule.
In its decision, the Court agreed with the environmental
petitioners that EPA's definition of ``commercial or industrial
waste,'' as incorporated in the definition of CISWI units, conflicted
with the plain language of CAA section 129(g)(1). That provision
defines ``solid waste incineration unit'' to mean ``any facility which
combusts any solid waste material'' from certain types of
establishments, with four specific exclusions. The Court stated that,
based on the use of the term ``any'' and the specific exclusions for
only certain types of facilities from the definition of ``solid waste
incineration unit,'' CAA section 129 unambiguously includes among the
incineration units subject to its standards any facility that combusts
any commercial or industrial solid waste material at all--subject only
to the four statutory exclusions. The Court held that the definitions
EPA promulgated in the CISWI Definitions Rule constricted the plain
language of CAA section 129(g)(1), because the CISWI Definitions Rule
excluded from its universe operating units that combusted solid waste
and were designed for or operating with energy recovery.
Having determined that EPA's definition of ``commercial and
industrial solid waste incineration unit'' conflicts with the plain
meaning of CAA section 129 and must, therefore, be vacated, the Court
also vacated the Boiler MACT because it concluded that the Boiler MACT
would need to be revised because the universe of boilers subject to its
standards will be different once EPA revises the CISWI definitions rule
consistent with the Court's opinion. The Court did not address
petitioners' specific challenges to the Boiler MACT.
C. Summary of Other Related Court Decisions
In March 2007, the DC Circuit Court issued an opinion (Sierra Club
v. EPA, 479 F. 3d 875 (DC Cir. 2007) (Brick MACT)) vacating and
remanding CAA section 112(d) MACT standards for the Brick and
Structural Clay Ceramics source categories. Some key holdings in that
case were:
Floors for existing sources must reflect the average
emission limitation achieved by the best-performing 12 percent of
existing sources, not levels
[[Page 32010]]
EPA considers to be achievable by all sources (479 F. 3d at 880-81);
EPA cannot set floors of ``no control.'' The Court
reiterated its prior holdings, including National Lime Association,
confirming that EPA must set floor standards for all HAP emitted by the
major source, including those HAP that are not controlled by at-the-
stack control devices (479 F. 3d at 883);
EPA cannot ignore non-technology factors that reduce HAP
emissions. Specifically, the Court held that ``EPA's decision to base
floors exclusively on technology even though non-technology factors
affect emissions violates the Act.'' (479 F. 3d at 883)
Based on the Brick MACT decision, we believe a source's performance
resulting from the presence or absence of HAP in fuel materials must be
accounted for in establishing floors; i.e., a low emitter due to low
HAP fuel materials can still be a best performer. In addition, the fact
that a specific level of performance is unintended is not a legal basis
for excluding the source's performance from consideration. (National
Lime Ass'n, 233 F. 3d at 640.)
The Brick MACT decision also stated that EPA may account for
variability in setting floors. However, the court found that EPA erred
in assessing variability because it relied on data from the worst
performers to estimate best performers' variability, and held that
``EPA may not use emission levels of the worst performers to estimate
variability of the best performers without a demonstrated relationship
between the two.'' (479 F. 3d at 882.)
The majority opinion in the Brick MACT case does not address the
possibility of subcategorization to address differences in the HAP
content of raw materials. However, in his concurring opinion Judge
Williams stated that EPA's ability to create subcategories for sources
of different classes, size, or type (CAA section 112(d)(1)) may provide
a means out of the situation where the floor standards are achieved for
some sources, but the same floors cannot be achieved for other sources
due to differences in local raw materials whose use is essential. (Id.
At 884-85.9)
A second court opinion is also relevant to this proposal. In Sierra
Club v. EPA, 551 F. 3d 1019 (DC Cir. 2008), the court vacated the
portion of the regulations contained in the General Provisions which
exempt major sources from MACT standards during periods of startup,
shutdown and malfunction (SSM). The regulations (in 40 CFR 63.6(f)(1)
and 63.6(h)(1)) provided that sources need not comply with the relevant
CAA section 112(d) standard during SSM events and instead must
``minimize emissions * * * to the greatest extent which is consistent
with safety and good air pollution control practices.'' The vacated
Boiler MACT did not contain specific provisions covering operation
during SSM operating modes; rather it referenced the now-vacated
exemption in the General Provisions. As a result of the court decision,
we are addressing SSM in this proposed rulemaking. Discussion of this
issue may be found later in this preamble.
D. EPA's Response to the Vacatur
In response to the NRDC v. EPA mandate, we initiated an information
collection effort entitled ``Information Collection Effort for
Facilities with Combustion Units.'' This information collection was
conducted by EPA's Office of Air and Radiation pursuant to CAA section
114 to assist the Administrator in developing emissions standards for
boilers/process heaters and CISWI units (collectively, ``combustion
units'') pursuant to CAA sections 112(d) and 129. CAA section 114(a)
states, in pertinent part:
For the purpose of * * * (iii) carrying out any provision of
this Chapter * * * (1) the Administrator may require any person who
owns or operates any emission source * * * to- * * * (D) sample such
emissions (in accordance with such procedures or methods, at such
locations, at such intervals, during such periods and in such manner
as the Administrator shall prescribe); (E) keep records on control
equipment parameters, production variables or other indirect data
when direct monitoring of emissions is impractical * * * (G) provide
such other information as the Administrator may reasonably require *
* *
There were two components to the information collection. To obtain
the information necessary to identify and categorize all combustion
units potentially affected by the revised standards for boilers/process
heaters and for CISWI units, the first component of the information
collection effort solicited information from all potentially affected
combustion units in the format of an electronic survey. The survey was
submitted to the following facilities: (1) All facilities that
submitted an initial notification for the 2004 boiler MACT standard,
(2) all facilities identified by States as being subject to the 2004
boiler MACT standard, and (3) facilities that are classified as a major
source in their Title V permit that have a boiler or process heater
listed in their permit. The survey was also sent to units covered by
the 2000 CISWI emissions standards (40 CFR part 60 subpart CCCC) and to
facilities that have incineration units (e.g., energy recovery units)
that were listed as exempt under the 2000 CISWI standard. Each facility
was required to complete the survey for all combustion units located at
the facility. The information requested for each combustion unit
included the unit design, operation, air pollution control data, the
fuels/materials burned, and available emissions test data, continuous
emission monitoring (CEM) data, fuel/material analysis data, and
permitted and regulatory emission limits.
The second component of the information collection request effort
consisted of requiring the owners/operators of 169 boilers/process
heaters to conduct emission testing for HAP and HAP surrogates. We
first analyzed the results of the survey to determine if sufficient
emissions data existed to develop emission standards under CAA sections
112(d) for all types of boilers/process heaters, all types of materials
combusted, and all HAP to be regulated. If data were not sufficient,
then we selected pools of candidates to conduct emission testing. We
submitted a list of candidates to stakeholders, including state,
industry, and environmental stakeholders, who had an opportunity to
comment on the technical feasibility, the least-cost impact of the
testing program, and the appropriateness of the testing being
requested. We then made a selection of test sites after taking into
account stakeholder comments. The sites selected were required to
conduct an outlet stack test, consisting of three runs, in accordance
with EPA-approved protocols, for all of the following pollutants: PM
(filterable, condensable, and PM2.5), dioxins/furans (D/F),
hydrogen chloride/hydrogen fluoride, mercury, metals (including
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead,
manganese, nickel, phosphorus, and selenium), carbon monoxide (CO),
total hydrocarbons (THC), formaldehyde, oxides of nitrogen
(NOX), and sulfur dioxide (SO2). Six facilities
(two coal-fired, two biomass-fired, and two gas-fired boilers) were
required to collect CEM data over 30 operating days using mobile CEM
devices for CO, THC, and NOX. The owner/operator of each
selected combustion unit was also required to collect and analyze, in
accordance with acceptable procedures, the material(s) fed to the
combustion unit during each stack test. The results of the stack tests
and the analyses of materials combusted were required to be submitted
to the Agency and are available in the docket and can be
[[Page 32011]]
downloaded at http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
When we compared information on boilers and process heaters from
facilities submitting initial notifications to comply with the vacated
2004 Boiler MACT to the information gathering effort conducted for the
2004 Boiler MACT, a large disparity was identified in the number of
potentially affected units at major sources of HAP. Since the last
combustion unit data gathering effort in 1996, many sources have shut
down, others have selected to operate with a permit limit on their HAP
emissions in order to avoid being subject to the Boiler MACT (i.e.,
synthetic area source), and some units have switched out older solid
fuel units for newer equipment due to increased insurance and
maintenance costs.
Based on the definition of solid waste as set forth in a parallel
proposed action, we revised the population of combustion units subject
to CAA section 129 (because they combust solid waste) and the
population of boilers and process heaters subject to CAA section 112
(because they do not combust solid waste). We then used the new data to
develop a revised NESHAP for boilers and process heaters under CAA
section 112 and revised standards for incineration units covered by CAA
section 129. Specifically, the data provide the Agency with updated
information on the number of potentially affected units, available
emission test data, and fuel/material analysis data to address
variability. We are using all of the information before the
Administrator to calculate the MACT floors, set emission limits, and
evaluate the emission impacts of various regulatory options for these
revised rulemakings.
E. What is the relationship between this proposed rule and other
combustion rules?
The proposed rule regulates source categories covering industrial
boilers, institutional boilers, 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 this proposed rule any boiler or process heater that is
subject to regulation under other MACT standards.
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 those standards in 1999 and 2006. The NSPS regulates
emissions of PM, SO2, and NOX from boilers
constructed after June 19, 1984. Sources subject to the NSPS will be
subject to the final CAA section 112(d) standards for boilers and
process heaters because it regulates sources of HAP while the NSPS do
not. However, in developing the proposed rule, we considered the
monitoring requirements, testing requirements, and recordkeeping
requirements of the NSPS to avoid duplicating requirements.
This proposed rule addresses the combustion of non-solid waste
materials in boilers and process heaters. If an owner or operator of an
affected source subject to these proposed standards were to start
combusting a solid waste (as defined by the Administrator under RCRA),
the affected source would cease to be subject to this action and would
instead be subject to regulation under CAA section 129. A rulemaking
under CAA section 129 is being proposed in a parallel action and is
relevant to this action because it would apply to boilers and process
heaters located at a major source that combust any solid waste. EPA is
taking comment on whether a boiler or process heater could then opt
back into regulation under this proposed rule by taking a federally
enforceable restriction precluding the future combustion of any solid
waste material.
F. What are the health effects of pollutants emitted from industrial/
commercial/institutional boilers and process heaters?
This proposed rule protects air quality and promotes the public
health by reducing emissions of some of the HAP listed in CAA section
112(b)(1). As noted above, emissions data collected during development
of the proposed rule show that hydrogen chloride emissions represent
the predominant HAP emitted by industrial, commercial, and
institutional (ICI) boilers, accounting for 61 percent of the total HAP
emissions.\1\ ICI boilers and process heaters also emit lesser amounts
of hydrogen fluoride, accounting for about 17 percent of total HAP
emissions, and metals (arsenic, cadmium, chromium, mercury, manganese,
nickel, and lead) accounting for about 6 percent of total HAP
emissions. Organic HAP (formaldehyde, POM, acetaldehyde, benzene)
account for about 15 percent of total HAP emissions. Exposure to these
HAP, depending on exposure duration and levels of exposures, can be
associated with a variety of adverse health effects. These adverse
health effects may include, for example, irritation of the lung, skin,
and mucus membranes, effects on the central nervous system, damage to
the kidneys, and alimentary effects such as nausea and vomiting. We
have classified two of the HAP as human carcinogens (arsenic and
chromium VI) and four as probable human carcinogens (cadmium, lead,
dioxins/furans, and nickel). 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, this proposed rule would reduce emissions and
subsequent exposures.
---------------------------------------------------------------------------
\1\ See Memorandum ``Methodology for Estimating Impacts from
Industrial, Commercial, Institutional Boilers and Process Heaters at
Major Sources of Hazardous Air Pollutant Emissions'' located in the
docket.
---------------------------------------------------------------------------
III. Summary of This Proposed Rule
This section summarizes the requirements proposed in today's
action. Section IV below provides our rationale for the proposed
requirements.
A. What source categories are affected by this proposed rule?
This proposed rule affects industrial boilers, institutional
boilers, commercial boilers, and process heaters. In this proposed
rule, process heaters are defined as units in which the combustion
gases do not directly come into contact with process material or 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.
B. What is the affected source?
The affected source is: (1) The collection of all existing
industrial, commercial, or institutional boilers or process heaters
within a subcategory located at a major source facility that do not
combust solid waste or (2) each new or reconstructed industrial,
commercial, or institutional boiler or process heater located at a
major source facility that do not combust solid waste, as that term is
defined by the Administrator under RCRA.
The affected source does not include boilers and process heaters
that are subject to another standard under 40 CFR part 63 or a standard
established under CAA section 129.
C. Does this proposed rule apply to me?
This 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
[[Page 32012]]
potential to emit considering controls 10 tons per year or more of any
HAP or 25 tons per year or more of any combination of HAP.
D. What emission limitations and work practice standards must I meet?
We are proposing the emission limits presented in Table 1 of this
preamble. Emission limits were developed for new and existing sources
for eleven subcategories, which we developed based on unit design.
We are proposing that if your new or existing boiler or process
heater burns at least 10 percent coal on an annual average heat input
\2\ basis, the unit is in one of the coal subcategories. If your new or
existing boiler or process heater burns at least 10 percent biomass, on
an annual average heat input basis, and less than 10 percent coal, on
an annual average heat input basis, we are proposing that the unit is
in one of the biomass subcategories. If your new or existing boiler or
process heater burns at least 10 percent liquid fuel (such as
distillate oil, residual oil), and less than 10 percent solid fuel, on
an annual heat input basis, we are proposing that the unit is in the
liquid subcategory. If your new or existing boiler or process heater
burns gaseous fuel and less than 10 percent, on an annual average heat
input basis, of liquid or solid fuel, we are proposing that the unit is
in one of the gas subcategories.
---------------------------------------------------------------------------
\2\ Heat input means heat derived from combustion of fuel in a
boiler or process heater and does not include the heat derived from
preheated combustion air, recirculated flue gases or exhaust gases
from other sources (such as stationary gas turbines, internal
combustion engines, and kilns).
Table 1--Emission Limits for Boilers and Process Heaters
[Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
Carbon Dioxins/
Particulate Hydrogen monoxide (CO) furans (total
Subcategory matter (PM) chloride (HCl) Mercury (Hg) (ppm @3% TEQ) (ng/
oxygen) dscm)
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker.......... 0.02 0.02 0.000003 50 0.003
Existing--Coal Fluidized Bed... 0.02 0.02 0.000003 30 0.002
Existing--Pulverized Coal...... 0.02 0.02 0.000003 90 0.004
Existing--Biomass Stoker....... 0.02 0.006 0.0000009 560 0.004
Existing--Biomass Fluidized Bed 0.02 0.006 0.0000009 250 0.02
Existing--Biomass Suspension 0.02 0.006 0.0000009 1010 0.03
Burner/Dutch Oven.............
Existing--Biomass Fuel Cells... 0.02 0.006 0.0000009 270 0.02
Existing--Liquid............... 0.004 0.0009 0.000004 1 0.002
Existing--Gas (Other Process 0.05 0.000003 0.0000002 1 0.009
Gases)........................
New--Coal Stoker............... 0.001 0.00006 0.000002 7 0.003
New--Coal Fluidized Bed........ 0.001 0.00006 0.000002 30 0.00003
New--Pulverized Coal........... 0.001 0.00006 0.000002 90 0.002
New--Biomass Stoker............ 0.008 0.004 0.0000002 560 0.00005
New--Biomass Fluidized Bed..... 0.008 0.004 0.0000002 40 0.007
New--Biomass Suspension Burner/ 0.008 0.004 0.0000002 1010 0.03
Dutch Oven....................
New--Biomass Fuel Cells........ 0.008 0.004 0.0000002 270 0.0005
New--Liquid.................... 0.002 0.0004 0.0000003 1 0.002
New--Gas (Other Process Gases). 0.003 0.000003 0.0000002 1 0.009
----------------------------------------------------------------------------------------------------------------
The proposed emission limits in the above table apply only to
existing boilers and process heaters that have a designed heat input
capacity of 10 million British thermal units (Btu) per hour or greater.
Pursuant to CAA section 112(h), we are proposing a work practice
standard for three particular classes of boilers and process heaters:
Existing units that have a designed heat input capacity of less than 10
million Btu per hour and new and existing units in the Gas 1 (natural
gas/refinery gas) subcategory and in the metal process furnaces
subcategory. The work practice standard being proposed for these
boilers and process heaters would require the implementation of a tune-
up program as described in section III.F of this preamble.
We are also proposing a beyond-the-floor standard for all existing
major source facilities having affected boilers or process heaters that
would require the performance of a one-time energy assessment, as
described in section III.F of this preamble, by qualified personnel, on
the affected boilers and facility to identify any cost-effective energy
conservation measures.
E. What are the startup, shutdown, and malfunction (SSM) requirements?
The United States Court of Appeals for the District of Columbia
Circuit vacated portions of two provisions in EPA's CAA Section 112
regulations governing the emissions of HAP during periods of startup,
shutdown, and malfunction (SSM). Sierra Club v. EPA, 551 F.3d 1019 (DC
Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010). Specifically,
the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and
40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to
as the ``General Provisions Rule,'' that EPA promulgated under section
112 of the CAA. When incorporated into CAA Section 112(d) regulations
for specific source categories, these two provisions exempt sources
from the requirement to comply with the otherwise applicable CAA
section 112(d) emission standard during periods of SSM.
Consistent with Sierra Club v. EPA, EPA has established standards
in this rule that apply at all times. EPA has attempted to ensure that
we have not incorporated into proposed regulatory language any
provisions that are inappropriate, unnecessary, or redundant in the
absence of an SSM exemption. We are specifically seeking comment on
whether there are any such provisions that we have inadvertently
incorporated or overlooked. We also request comment on whether there
are additional provisions that should be added to regulatory text in
light of the absence of an SSM exemption and provisions related to the
SSM exemption (such as the SSM plan requirement and SSM recordkeeping
and reporting provisions).
In establishing the standards in this rule, EPA has taken into
account startup and shutdown periods and, for the
[[Page 32013]]
reasons explained below, has not established different standards for
those periods. The standards that we are proposing are daily or monthly
averages. Continuous emission monitoring data obtained from best
performing units, and used in establishing the standards, include
periods of startup and shutdown. Boilers, especially solid fuel-fired
boilers, do not normally startup and shutdown more the once per day.
Thus, we are not establishing a separate emission standard for these
periods because startup and shutdown are part of their routine
operations and, therefore, are already addressed by the standards.
Periods of startup, normal operations, and shutdown are all predictable
and routine aspects of a source's operation. We have evaluated whether
it is appropriate to have the same standards apply during startup and
shutdown as applied to normal operations.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a ``sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner * * *'' (40 CFR 63.2). EPA has determined that
malfunctions should not be viewed as a distinct operating mode and,
therefore, any emissions that occur at such times do not need to be
factored into development of CAA section 112(d) standards, which, once
promulgated, apply at all times. It is reasonable to interpret section
112(d) as not requiring EPA to account for malfunctions in setting
emissions standards. For example, we note that Section 112 uses the
concept of ``best performing'' sources in defining MACT, the level of
stringency that major source standards must meet. Applying the concept
of ``best performing'' to a source that is malfunctioning presents
significant difficulties. The goal of best performing sources is to
operate in such a way as to avoid malfunctions of their units.
Moreover, even if malfunctions were considered a distinct operating
mode, we believe it would be impracticable to take malfunctions into
account in setting CAA section 112(d) standards for major source
boilers and process heaters. As noted above, by definition,
malfunctions are sudden and unexpected events and it would be difficult
to set a standard that takes into account the myriad different types of
malfunctions that can occur across all sources in the category.
Moreover, malfunctions can vary in frequency, degree, and duration,
further complicating standard setting.
In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, EPA would
determine an appropriate response based on, among other things, the
good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
EPA would also consider whether the source's failure to comply with the
CAA section 112(d) standard was, in fact, ``sudden, infrequent, not
reasonably preventable'' and was not instead ``caused in part by poor
maintenance or careless operation.'' 40 CFR 63.2 (definition of
malfunction).
F. What are the testing and initial compliance requirements?
We are proposing that the owner or operator of a new or existing
boiler or process heater must conduct performance tests to demonstrate
compliance with all applicable emission limits. Affected units would be
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 17.
(2) Conduct initial and annual stack tests to determine compliance
with the mercury emission limits using EPA method 29 or ASTM-D6784-02
(Ontario Hydro Method).
(3) Conduct initial and annual stack tests to determine compliance
with the HCl emission limits using EPA Method 26A or EPA Method 26 (if
no entrained water droplets in the sample).
(4) Use EPA Method 19 to convert measured concentration values to
pound per million Btu values.
(5) Conduct initial and annual test to determine compliance with
the CO emission limits using either EPA Method 10 or a CO CEMS.
(6) Conduct initial and annual test to determine compliance with
the D/F emission limits using EPA Method 23.
As part of the initial compliance demonstration, we are proposing
that you monitor specified operating parameters during the initial
performance tests that you would conduct to demonstrate compliance with
the PM, mercury, D/F, and HCl emission limits. You would calculate the
average parameter values measured during each test run over the three
run performance test. The average of the three average values
(depending on the parameter measured) for each applicable parameter
would establish the site-specific operating limit. The applicable
operating parameters for which operating limits would be required to be
established are based on the emissions limits applicable to your unit
as well as the types of add-on controls on the unit. The following is a
summary of the operating limits that we are proposing to be established
for the various types of the following units:
(1) 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.
(2) For boilers and process heaters with wet scrubbers, 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 average of the three test run averages establishes your minimum
site-specific pressure drop and liquid flow rate operating levels. If
different average parameter levels are measured during the mercury, PM
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 of the scrubber effluent during the
performance test for HCl and determine the average for each test run
and the average value for the performance test. This establishes your
minimum pH operating limit.
(3) For boilers and process heaters with sorbent injection, you
would be required to measure the sorbent injection rate for each
sorbent used during the performance tests for HCl, mercury, and D/F and
calculate the average for each sorbent for each test run. The average
of the three test run averages established during the performance tests
would be your site-specific minimum sorbent injection rate operating
limit. If different sorbents and/or injection rates are used during the
mercury, HCl, and D/F tests, the average value for each sorbent becomes
your site-specific operating limit.
(4) For boilers and process heaters with fabric filters in
combination with wet scrubbers, you must measure the pH, pressure drop,
and liquid flowrate of the wet scrubber during the performance test and
calculate the average value for each test run. The minimum test run
average establishes your site-specific pH, pressure drop, and liquid
flowrate operating limits for the wet scrubber. Furthermore, the fabric
filter must be operated such that
[[Page 32014]]
the bag leak detection system alarm does not sound more than 5 percent
of the operating time during any 6-month period unless a CEMS is
installed to measure PM.
(5) For boilers and process heaters with electrostatic
precipitators (ESP) in combination with wet scrubbers, 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 fields during the mercury and PM performance
test. You would then be required to calculate the average value of
these parameters for each test run. The average of the three test run
averages would establish your site-specific minimum pH, pressure drop,
and liquid flowrate operating limit for the wet scrubber and the
minimum voltage and current operating limits for the ESP.
(6) For boilers and process heaters that choose to demonstrate
compliance with the mercury emission limit on the basis of fuel
analysis, you would be required to 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.
(7) For boilers and process heaters that choose to demonstrate
compliance with the HCl emission limit on the basis of fuel analysis,
you would be required to measure the chlorine content of the inlet fuel
that was burned during the HCl performance test. This value is your
maximum fuel inlet chlorine operating limit.
These proposed operating limits would not apply to owners or
operators of boilers or process heaters having a heat input capacity of
less than 10 million Btu per hour (MMBtu/h) or boilers or process
heaters of any size which combust natural gas or refinery gas, as
discussed in section IV.D.3 of this preamble. Instead, we are proposing
that owners or operators of such boilers and process heaters submit to
the delegated authority or EPA, as appropriate, if requested,
documentation that a tune-up meeting the requirements of the proposed
rule was conducted. We are proposing that, to comply with the work
practice standard, a tune-up procedure include the following:
(1) Inspect the burner, and clean or replace any components of the
burner as necessary,
(2) Inspect the flame pattern and make any adjustments to the
burner necessary to optimize the flame pattern consistent with the
manufacturer's specifications,
(3) Inspect the system controlling the air-to-fuel ratio, and
ensure that it is correctly calibrated and functioning properly,
(4) Minimize total emissions of CO consistent with the
manufacturer's specifications,
(5) Measure the concentration in the effluent stream of CO in
ppmvd, before and after the adjustments are made,
(6) Submit an annual report containing the concentrations of CO in
the effluent stream in ppmvd, and oxygen in percent dry basis, measured
before and after the adjustments of the boiler, a description of any
corrective actions taken as a part of the combustion adjustment, and
the type and amount of fuel used over the 12 months prior to the annual
adjustment.
Further, all owners or operators of major source facilities having
boilers and process heaters subject to this rule would be required to
submit to the delegated authority or EPA, as appropriate, documentation
that an energy assessment was performed, by qualified personnel, and
the cost-effective energy conservation measures indentified. The
procedures for an energy assessment are:
(1) Conduct a visual inspection of the boiler system.
(2) Establish operating characteristics of the facility, energy
system specifications, operating and maintenance procedures, and
unusual operating constraints,
(3) Identify major energy consuming systems,
(4) Review available architectural and engineering plans, facility
operation and maintenance procedures and logs, and fuel usage,
(5) Identify a list of major energy conservation measures,
(6) Determine the energy savings potential of the energy
conservation measures identified, and
(7) Prepare a comprehensive report detailing the ways to improve
efficiency, the cost of specific improvements, benefits, and the time
frame for recouping those investments.
G. What are the continuous compliance requirements?
To demonstrate continuous compliance with the emission limitations,
we are proposing following requirements:
(1) For units combusting coal, biomass, or residual fuel oil (i.e.,
No 4, 5 or 6 fuel oil) with heat input capacities of less than 250
million Btu per hour that do not use a wet scrubber, we are proposing
that opacity levels be maintained to less than 10 percent (daily
average) for existing and new units with applicable emission limits.
Or, if the unit is controlled with a fabric filter, instead of
continuous monitoring of 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 (unless a PM CEMS is used).
(2) For units combusting coal, biomass, or residual oil with heat
input capacities of 250 million Btu per hour or greater, we are
proposing that PM CEMS be installed and operated and that PM levels
(monthly average) be maintained below the applicable PM limit.
(3) For boilers and process heaters with wet scrubbers, we are
proposing that you monitor pressure drop and liquid flow rate of the
scrubber and maintain the 12-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 12-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, we are
proposing that you continuously monitor the sorbent injection rate and
maintain it at or above the operating limits established during the
performance tests.
(5) For boilers and process heaters having heat input capacities of
less than 250 million Btu per hour with an ESP in combination with a
wet scrubber, we are proposing that you monitor the pH, pressure drop,
and liquid flow rate of the wet scrubber and maintain the 12-hour block
averages at or above the operating limits established during the HCl
performance test and that you monitor the voltage and current of the
ESP collection plates and maintain the 12-hour block averages at or
above the operating limits established during the mercury or PM
performance test.
(6) For units that choose to comply with either the mercury
emission limit or the HCl emission limit based on fuel analysis rather
than on performance stack testing, we are proposing that you maintain
daily fuel records that demonstrate that you burned no new fuels or
fuels from a new supplier such that the mercury content or the chlorine
content of the inlet fuel was maintained at or below your maximum fuel
mercury content operating limit or your chlorine content operating
limit set during the performance stack tests. If you plan to burn a new
fuel, a fuel from a new mixture, or a new supplier's fuel that differs
from what was burned during the initial performance tests, then you
must
[[Page 32015]]
recalculate the maximum mercury input and/or the maximum chlorine input
anticipated from the new fuels based on supplier data or own fuel
analysis, using the methodology specified in Table 6 of this proposed
rule. If the results of recalculating the inputs exceed the average
content levels established during the initial test then, you must
conduct a new performance test(s) to demonstrate continuous compliance
with the applicable emission limit.
(7) For all boilers and process heaters, we are proposing that you
maintain daily records of fuel use that demonstrate that you have
burned no materials that are considered solid waste.
(8) For boilers and process heaters in any of the subcategories
with heat input capacities greater than 100 MMBtu/h, we are proposing
that you continuously monitor CO and maintain the average CO emissions
at or below the applicable limit listed in Tables 1 or 2 of this
proposed rule.
If an owner or operator would like to use a control device other
than the ones specified in this section to comply with this proposed
rule, the owner/operator should follow the requirements in 40 CFR
63.8(f), which presents the procedure for submitting a request to the
Administrator to use alternative monitoring.
H. What are the notification, recordkeeping and reporting requirements?
All new and existing sources would be required to comply with
certain requirements of the General Provisions (40 CFR part 63, subpart
A), which are identified in Table 10 of this proposed rule. The General
Provisions include specific requirements for notifications,
recordkeeping, and reporting.
Each owner or operator would be required to submit a notification
of compliance status report, as required by Sec. 63.9(h) of the
General Provisions. This proposed rule would require the owner or
operator to include in the notification of compliance status report
certifications of compliance with rule requirements.
Semiannual compliance reports, as required by Sec. 63.10(e)(3) of
subpart A, would be required only for semiannual reporting periods when
a deviation from any of the requirements in the rule occurred, or any
process changes occurred and compliance certifications were
reevaluated.
This proposed rule would require records to demonstrate compliance
with each emission limit and work practice standard. These
recordkeeping requirements are specified directly in the General
Provisions to 40 CFR part 63, and are identified in Table 10. Owners or
operators of sources with units with heat input capacity of less than
10 MMBtu/h or units combusting natural gas or refinery gas must keep
records of the dates and the results of each required boiler tune-up.
Records of either continuously monitored parameter data for a
control device if a device is used to control the emissions or CEMS
data would be required.
We are proposing that you must keep the following records:
(1) All reports and notifications submitted to comply with this
proposed rule.
(2) Continuous monitoring data as required in this proposed rule.
(3) Each instance in which you did not meet each emission limit and
each operating limit (i.e., deviations from this 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 this proposed rule, for each affected source with an
applicable HCl emission limit.
(7) Calculations and supporting information of mercury fuel input,
as required in this proposed rule, for each affected source with an
applicable mercury emission limit.
(8) A signed statement, as required in this proposed rule,
indicating that you burned no new fuel type and no new fuel mixture or
that the recalculation of chlorine input demonstrated that the new fuel
or new mixture still meets chlorine fuel input levels, for each
affected source with an applicable HCl emission limit.
(9) A signed statement, as required in this proposed rule,
indicating that you burned no new fuels and no new fuel mixture or that
the recalculation of mercury fuel input demonstrated that the new fuel
or new fuel mixture still meets the mercury fuel input levels, for each
affected source with an applicable mercury emission limit.
(10) 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 this proposed rule.
(11) A copy of your site-specific monitoring plan developed for
this proposed rule as specified in 63 CFR 63.8(e), if applicable.
We are also proposing to require that you 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.
I. Submission of Emissions Test Results to EPA
The EPA must have performance test data to conduct effective
reviews of CAA Section 112 and 129 standards, as well as for many other
purposes including compliance determinations, emissions factor
development, and annual emissions rate determinations. In conducting
these required reviews, we have found it ineffective and time consuming
not only for us but also for regulatory agencies and source owners and
operators to locate, collect, and submit emissions test data because of
varied locations for data storage and varied data storage methods. One
improvement that has occurred in recent years is the availability of
stack test reports in electronic format as a replacement for cumbersome
paper copies.
In this action, we are taking a step to improve data accessibility.
Owners and operators of boilers and process heaters will be required to
submit to an EPA electronic database an electronic copy of reports of
certain performance tests required under this rule. Data entry will be
through an electronic emissions test report structure called the
Electronic Reporting Tool (ERT) that will be used by the EPA staff as
part of the emissions testing project. The ERT was developed with input
from stack testing companies who generally collect and compile
performance test data electronically and offices within State and local
agencies which perform field test assessments. The ERT is currently
available, and access to direct data submittal to EPA's electronic
emissions database (WebFIRE) will become available by December 31,
2011.
The requirement to submit source test data electronically to EPA
will not
[[Page 32016]]
require any additional performance testing and will apply to those
performance tests conducted using test methods that are supported by
ERT. The ERT contains a specific electronic data entry form for most of
the commonly used EPA reference methods. The Web site listed at the end
of this section contains a listing of the pollutants and test methods
supported by ERT. In addition, when a facility submits performance test
data to WebFIRE, there will be no additional requirements for emissions
test data compilation. Moreover, we believe industry will benefit from
development of improved emissions factors, fewer follow-up information
requests, and better regulation development as discussed below. The
information to be reported is already required for the existing test
methods and is necessary to evaluate the conformance to the test
method.
One major advantage of submitting source test data through the ERT
is that it provides a standardized method to compile and store much of
the documentation required to be reported by this rule while clearly
stating what testing information we require. Another important benefit
of submitting these data to EPA at the time the source test is
conducted is that it will substantially reduce the effort involved in
data collection activities in the future. Specifically, because EPA
would already have adequate source category data to conduct residual
risk assessments or technology reviews, there would be fewer or less
substantial data collection requests (e.g., CAA Section 114 letters).
This results in a reduced burden on both affected facilities (in terms
of reduced manpower to respond to data collection requests) and EPA (in
terms of preparing and distributing data collection requests).
State/local/Tribal agencies may also benefit in that their review
may be more streamlined and accurate as the States will not have to re-
enter the data to assess the calculations and verify the data entry.
Finally, another benefit of submitting these data to WebFIRE
electronically is that these data will improve greatly the overall
quality of the existing and new emissions factors by supplementing the
pool of emissions test data upon which the emissions factor is based
and by ensuring that data are more representative of current industry
operational procedures. A common complaint we hear from industry and
regulators is that emissions factors are outdated or not representative
of a particular source category. Receiving and incorporating data for
most performance tests will ensure that emissions factors, when
updated, represent accurately the most current operational practices.
In summary, receiving test data already collected for other purposes
and using them in the emissions factors development program will save
industry, State/local/Tribal agencies, and EPA time and money and work
to improve the quality of emissions inventories and related regulatory
decisions.
As mentioned earlier, the electronic data base that will be used is
EPA's WebFIRE, which is a Web site accessible through EPA's Technology
Transfer Network (TTN). The WebFIRE Web site was constructed to store
emissions test data for use in developing emissions factors. A
description of the WebFIRE data base can be found at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
The ERT will be able to transmit the electronic report through
EPA's Central Data Exchange (CDX) network for storage in the WebFIRE
data base. Although ERT is not the only electronic interface that can
be used to submit source test data to the CDX for entry into WebFIRE,
it makes submittal of data very straightforward and easy. A description
of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert_tool.html.
IV. Rationale for This Proposed Rule
A. How did EPA determine which sources would be regulated under this
proposed rule?
This 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 under CAA sections 112 or
129. Therefore, we are excluding from this proposed rule any units that
are subject to regulation in another MACT standard established under
CAA section 112 or a standard established under CAA section 129.
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, this proposed rule would not regulate fossil fuel-fired
utility boilers greater than 25 megawatts, but would regulate fossil
fuel-fired units less than 25 megawatts and all utility boilers firing
a non-fossil fuel that is not a solid waste.
The scope of the process heater source category is limited to only
indirect-fired units.\3\ 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 listed source
category of units with the listed source categories of industrial
boilers and commercial/institutional boilers for purposes of developing
emission standards.
---------------------------------------------------------------------------
\3\ Indirect-fired process heaters are combustion devices in
which the combustion gases do not directly come into contact with
process materials.
---------------------------------------------------------------------------
The proposed rule would not regulate hot water heaters, as defined
in this proposed rule, because such units are not part of the listed
source categories. 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 since hot water
heaters meet the definition of a boiler as specified in the proposed
rule, because they are enclosed devices that combust fuel for the
purpose of recovery energy to heat water. However, hot water heaters
are more appropriately described as residential-type boilers, not
industrial, commercial, or institutional boilers because their output
(i.e., hot water) is intended for personal use rather than for use in
an industrial, commercial, or institutional process. Moreover, 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. However, the primary reason that we are
excluding hot water heaters is that hot water heaters are not part of
the listed source category. Consequently, we are including a definition
of hot water heaters that includes fuel, size, pressure and temperature
limitations that we believe are appropriate to distinguish between
residential-type units and industrial, commercial, or institutional
units.
The CAA allows EPA to divide source categories into subcategories
based on differences in class, type, or size. For example, differences
between given types of units can 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
[[Page 32017]]
indicates differences in unit design that distinguish different types
of boilers. Data indicate that there are significant design and
operational differences between units that burn coal, biomass, 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
data base 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, and operate on solid fuel during the remainder of
their operation. In contrast, some co-fired units are specifically
designed to fire combinations of solids, liquids, and gases. Changes to
the fuel type would generally 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. 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 retrofitting
needed to operate using a different fuel.
The design of the boiler or process heater, which is dependent in
part on the type of fuel being burned, impacts the degree of
combustion. Boilers and process heaters emit a number of different
types of HAP emissions. Organic HAP are formed from incomplete
combustion and are influenced by the design and operation of the unit.
The degree of combustion may be greatly influenced by three general
factors: Time, turbulence, and temperature. On the other hand, the
formation of fuel-dependent HAP (metals, mercury, and acid gases) is
dependent upon the composition of the fuel. 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.
We first examined the HAP emissions results to determine if
subcategorization by unit design type was warranted. We concluded that
the data were sufficient for determining that a distinguishable
difference in performance exists based on unit design type. Therefore,
because 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). Accordingly, we propose to subcategorize boilers and
process heaters based on unit design in order to account for these
differences in emissions and applicable controls.
For the fuel-dependent HAP (metals, mercury, acid gases), we
identified five basic unit types as subcategories. These are the
following: (1) Units designed to burn coal, (2) units designed to burn
biomass, (3) units designed to burn liquid fuel, (4) units designed to
burn natural gas/refinery gas, and (5) units designed to burn other
process gases. Within the basic unit types there are different designs
and combustion systems that, while having a minor effect on fuel-
related HAP emissions, have a much larger effect on organic HAP
emissions. Therefore, we decided to further subcategorize based on
these different unit designs but only in proposing standards for
organic HAP emissions. We have identified the following 11
subcategories for organic HAP:
Pulverized coal units,
Stokers designed to burn coal,
Fluidized bed units designed to burn coal,
Stokers designed to burn biomass,
Fluidized bed units designed to burn biomass,
Suspension burners/Dutch Ovens designed to burn biomass,
Fuel Cells designed to burn biomass,
Units designed to burn liquid fuel,
Units designed to burn natural gas/refinery gas,
Units designed to burn other gases, and
Metal process furnaces.
These subcategories are based on the primary fuel that the boiler
or process heater is designed to burn. We are aware that some boilers
burn a combination of fuel types or burn a different fuel type as a
backup fuel if the primary fuel supply is curtailed. However, boilers
are designed based on the primary fuel type (and perhaps to burn a
backup fuel) and can encounter operational problems if another fuel
type that was not considered in its design is fired at more than 10
percent of the heat input to the boiler. Also, in some cases, a small
amount of coal may be added to a biomass designed boiler to stabilize
the combustion when the biomass has a higher moisture content than
normal. In this case, it would not be appropriate to classify the
boiler as being in one of the ``coal'' subcategories because the boiler
design is such that it is constructed and operated to combust biomass,
and could not combust primarily coal (without significant retrofitting
or design changes). Therefore, we are proposing to define boilers and
process heaters that burn at least 10 percent coal (on an annual heat
input basis) as being in one of the coal subcategories. We are also
proposing to define boilers and process heaters that burn at least 10
percent biomass, and less than 10 percent coal (on an annual heat input
basis) as being in one of the biomass subcategories. We are proposing
to define boilers and process heaters that burn at least 10 percent
liquid fuel, and less than 10 percent solid fuel (on an annual heat
input basis) as being in the liquid subcategory. We are proposing to
define boilers and process heaters that burn at least 90 percent
natural gas and/or refinery gas (on an annual heat input basis) as
being in the Gas 1 subcategory. This would ensure that each boiler and
process heater is subject to emissions standards calculated on the
basis of the best performing units with similar design and operation.
The remaining boilers and process heaters, except for those described
below would be in the Gas 2 subcategory.
In addition, there is a certain class of natural gas-fired process
heaters that are designed and operated differently compared to typical
process heaters. A review of information gathered on process heaters
used in the metal processing industries shows that these process
heaters typically are designed with multiple burners that fire into
individual combustion chambers. These individual burners are operated
to cycle on and off to maintain the proper temperatures throughout the
various zones of the process heater. Thus, due to their design, these
process heaters rarely operate in a steady-state condition due to
burners constantly starting up and shutting down. This results in
emissions characteristics different from the process heaters used in
other industries. The process heaters used in metal processing are
natural gas-fired and include annealing furnaces, preheat furnaces,
reheat furnaces, aging furnaces, and heat treat furnaces. Therefore, we
propose to identify these metal processing process heaters (furnaces)
as a separate eleventh subcategory.
In summary, we have identified 11 subcategories of boilers and
process heaters located at major sources.\4\
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\4\ See Memorandum ``Development of Baseline Emission Factors
for Boilers and Process Heaters at Commercial, Industrial, and
Institutional Facilities'' located in the docket.
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B. How did EPA select the format for this proposed rule?
This proposed rule includes numerical emission limits for PM,
mercury, HCl, CO, and D/F. The selection of numerical emission limits
as the format for this proposed rule
[[Page 32018]]
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 control method that may not be appropriate in each case.
We are proposing numerical emission rate limits as a mass of
pollutant emitted per heat energy input to the boiler or process heater
for the fuel-related HAP. 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 \5\ and allows easy comparison between such
requirements. Additionally, this proposed rule contains an option to
monitor inlet chlorine and mercury content in the fuel to meet outlet
emission rate limits. This option can only be done on a mass basis.
---------------------------------------------------------------------------
\5\ For example, the new source performance standards for
industrial, commercial, and institutional steam generating units (40
CFR subpart Db) have emission limits for sulfur dioxide, nitrogen
oxide, and PM in terms of pounds per million Btu.
---------------------------------------------------------------------------
We are proposing outlet concentration as the format for the organic
HAP. An outlet concentration limit for organic HAP would also be
consistent with the format of other regulations.
Boilers and process heaters can emit a wide variety of compounds,
depending on the fuel burned. 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 five
categories: Mercury, non-mercury metallic HAP, inorganic HAP, non-
dioxin organic HAP, and D/F. 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. We chose to look at mercury separately from other metallic
HAP due to its different chemical characteristics and its different
control technology feasibility.
Next, EPA identified compounds that could be used as surrogates for
all the compounds in each pollutant category. For the non-mercury
metallic HAP, we chose to use PM as a surrogate. Most, if not all, non-
mercury metallic HAP emitted from combustion sources will appear on the
flue gas fly-ash. Therefore, the same control techniques that would be
used to control the fly-ash PM will control non-mercury metallic HAP.
PM 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 non-mercury
metals. Since non-mercury metallic HAP tend to be on small size
particles (i.e., fine particle enrichment), we considered using
PM2.5 as the surrogate, but we determined that PM
(filterable) was the more appropriate surrogate for two reasons. First,
the test method (OTM 27) for measuring PM2.5 is only
applicable for use in exhaust stacks without entrained water droplets.
Therefore, the test method (OTM 27) for measuring PM2.5 is
not applicable for units equipped with wet scrubbers which will likely
be necessary to achieve the proposed HCl emission limits. Second, based
on the emission data obtained during EPA's information collection
effort from units not equipped with wet scrubbers, the majority of the
filterable PM emitted from units that are well controlled for PM is
fine particulate (PM2.5). Thus, we are proposing to use PM
(filterable), instead of PM2.5, as the surrogate for non-
mercury metals.
For non-metallic inorganic HAP, EPA is proposing using HCl as a
surrogate. The emissions test information available to EPA indicate
that the primary non-metallic 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. Control technologies that reduce HCl also control other
inorganic compounds such as chlorine and other 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 control of
other inorganic HAP emissions.
For organic HAP, we considered both THC and CO as a surrogate for
non-dioxin organic HAP emitted from boilers and process heaters. CO has
generally been used as a surrogate for organic HAP because CO is a good
indicator of incomplete combustion and organic HAP are products of
incomplete combustion. However, based on concerns that CO may not be an
appropriate surrogate for D/F because, unlike other organic HAP, D/F
can be formed outside the combustion unit, we are proposing to use CO
as a surrogate for non-dioxin organic HAP. We are also proposing
separate emission limits for D/F. For non-dioxin organic HAP, using CO
as a surrogate is a reasonable approach because minimizing CO emissions
will result in minimizing non-dioxin organic HAP. Methods used for the
control of non-dioxin organic HAP emissions would be the same methods
used to control CO emissions. These emission control methods include
achieving good combustion or using an oxidation catalyst. Standards
limiting emissions of CO will also result in decreases in non-dioxin
organic HAP emissions (with the additional benefit of decreasing
volatile organic compounds (VOC) emissions). Establishing emission
limits for specific organic HAP (with the exception of D/F) would be
impractical and costly. CO, which is less expensive to test for and
monitor, is appropriate for use as a surrogate for non-dioxin organic
HAP.
The Agency recognizes that the level and distribution of organic
HAP associated with CO emissions will vary from unit to unit. For
example, the principal organic HAP emitted from coal-fired units is
benzene, which accounts for about 20 percent of the organic HAP while
the principal organic HAP emitted from biomass-fired units is
formaldehyde, which accounts for 34 percent of the organic HAP.\6\
Limiting CO as a surrogate for only non-dioxin organic HAP will
eliminate costs associated with speciating numerous compounds. The
proposed standards establish separate emission limits for D/F because
of the high toxicity associated with even low masses of these
compounds.
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\6\ Based on emission factors reported on EPA webpage ``AP 42,
Fifth Edition, Volume 1--Chapter 1: External Combustion Sources''
located at http://www.epa.gov/ttn/chief/ap42/ch01/index.html.
---------------------------------------------------------------------------
THC could also be an appropriate surrogate for non-dioxin organic
HAP because low THC also ensures good combustion efficiency and, thus,
low organic HAP. However, we believe CO is preferable because many
sources currently have CO CEMS. In addition, there are more CO emission
data available for the various subcategories than THC emission data.
C. How did EPA determine the proposed emission limitations for existing
units?
All standards established pursuant to CAA section 112(d)(2) 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, 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
[[Page 32019]]
sources for categories and subcategories with 30 or more sources or the
best performing 5 sources for subcategories with less than 30 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. 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 floors for existing units?
EPA must consider available emissions information to determine the
MACT floors. For each pollutant, we calculated the MACT floor for a
subcategory of sources by ranking all the available emissions data from
units within the subcategory from lowest emissions to highest
emissions, and then taking the numerical average of the test results
from the best performing (lowest emitting) 12 percent of sources.
We first considered 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 emission factors reported in EPA's Technology Transfer
Network, 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 (e,g., formaldehyde) would increase.\7\
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.
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\7\ See EPA webpage ``AP 42, Fifth Edition, Volume 1--Chapter 1:
External Combustion Sources'' located at http://www.epa.gov/ttn/chief/ap42/ch01/index.html.
---------------------------------------------------------------------------
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 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 boilers and process heaters 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. 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 emission levels for units in the boilers and process heaters
category.
Therefore, the MACT floor limits for each of the HAP and HAP
surrogates (PM, mercury, CO, HCl, and D/F) are calculated based on the
performance of the lowest emitting (best performing) sources in each of
the subcategories. We ranked all of the sources for which we had data
based on their emissions and identified the lowest emitting 12 percent
of the sources for each HAP.
We used the emissions data for those best performing affected
sources to determine the emission limits to be proposed, with an
accounting for variability. EPA must exercise its judgment, based on an
evaluation of the relevant factors and available data, to determine the
level of emissions control that has been achieved by the best
performing sources under variable conditions. The DC Circuit Court of
Appeals has recognized that EPA may consider variability in estimating
the degree of emission reduction achieved by best-performing sources
and in setting MACT floors. See Mossville Envt'l Action Now v. EPA, 370
F.3d 1232, 1241-42 (DC Cir 2004) (holding EPA may consider emission
variability in estimating performance achieved by best-performing
sources and may set the floor at level that best-performing source can
expect to meet ``every day and under all operating conditions'').
In determining the MACT floor limits, we first determine the floor,
which is the level achieved in practice by the average of the top 12
percent. We then assess variability of the best performers by using a
statistical formula designed to estimate a MACT floor level that is
achievable by the average of the best performing sources if the best
performing sources were able to replicate the compliance tests in our
[[Page 32020]]
data base. Specifically, the MACT floor limit is an upper prediction
limit (UPL) calculated with the Student's t-test using the TINV
function in Microsoft Excel. The Student's t-test has also been used in
other EPA rulemakings (e.g., NSPS for Hospital/Medical/Infectious Waste
Incinerators) in accounting for variability. A prediction interval for
a future observation is an interval that will, with a specified degree
of confidence, contain the next (or some other pre-specified) randomly
selected observation from a population. In other words, the prediction
interval estimates what future values will be, based upon present or
past background samples taken. Given this definition, the UPL
represents the value which we can expect the mean of 3 future
observations (3-run average) to fall below, based upon the results of
an independent sample from the same population. In other words, if we
were to randomly select a future test condition from any of these
sources (i.e., average of 3 runs), we can be 99% confident that the
reported level will fall at or below the UPL value. To calculate the
UPL, we used the average (or sample mean) and sample standard
deviation, which are two statistical measures calculated from the
sample data. The average is the central value of a data set, and the
standard deviation is the common measure of the dispersion of the data
set around the average.
We first determined the distribution of the emissions data for the
best-performing 12 percent of units within each subcategory prior to
calculating UPL values. To evaluate the distribution of the best
performing dataset, we first computed the skewness and kurtosis
statistics and then conducted the appropriate small-sample hypothesis
tests.
The skewness statistic (S) characterizes the degree of asymmetry of
a given data distribution. Normally distributed data have a skewness of
0. A skewness statistic that is greater (less) than 0 indicates that
the data are asymmetrically distributed with a right (left) tail
extending towards positive (negative) values. Further, the standard
error of the skewness statistic (SES) is given by SES = SQRT(6/N) where
N is the sample size. According to the small sample skewness hypothesis
test, if the skewness statistic (S) is greater than two times the SES,
the data distribution can be considered non-normal.
The kurtosis statistic (K) characterizes the degree of peakedness
or flatness of a given data distribution in comparison to a normal
distribution. Normally distributed data have a kurtosis of 0. A
kurtosis statistic that is greater (less) than 0 indicates a relatively
peaked (flat) distribution. Further, the standard error of the kurtosis
statistic (SEK) is given by SEK = SQRT(24/N) where N is the sample
size. According to the small sample kurtosis hypothesis test, if the
kurtosis statistic (K) is greater than two times the SEK, the data
distribution is typically considered to be non-normal.
We applied the skewness and kurtosis hypothesis tests to both the
reported test values and the lognormal values of the reported test
values. If the skewness (S) and kurtosis (K) statistics of the reported
data set were both less than twice the SES and SEK, respectively, the
dataset was classified as normally distributed. If neither of the
skewness (S) and kurtosis (K) statistics, or only one of these
statistics were less than twice the SES or SEK, respectively, then the
skewness and kurtosis hypothesis tests were conducted for the natural
log-transformed data. Then the distribution most similar to a normal
distribution was selected as the basis for calculating the UPL. If both
the reported values and the natural-log transformed reported values had
skewness (S) and kurtosis (K) statistics that were greater than twice
the SES or SEK, respectively, the normally distributed dataset was
selected as the basis of the floor to be conservative. If the results
of the skewness and kurtosis hypothesis tests were mixed for the
reported values and the natural log-transformed reported values, we
also chose the normal distribution to be conservative. We believe this
approach is more accurate and obtained more representative results than
a more simplistic normal distribution assumption.
Since the compliance with the MACT floor emission limit is based on
the average of a three run test, the UPL is calculated by:
[GRAPHIC] [TIFF OMITTED] TP04JN10.002
Where:
n = the number of test runs
m = the number of test runs in the compliance average
This calculation was performed using the following two Excel
functions:
Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) +
[STDEV(Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees of
freedom)*SQRT((1/n)+(\1/3\))], for a one-tailed t-value (with 2 x
probability), probability of 0.01, and sample size of n
Lognormal distribution: 99% UPL = EXP{AVERAGE(Natural Log Values of
Test Runs in Top 12%) + [STDEV(Natural Log Values of Test Runs in Top
12%) x TINV(2 x probability, n-1 degrees of freedom)* SQRT((1/n)+(\1/
3\))]{time} , for a one-tailed t-value (with 2 x probability),
probability of 0.01, and sample size of n
Test method measurement imprecision can also be a component of data
variability. At very low emissions levels as encountered in the data
used to support this rule, the inherent imprecision in the pollutant
measurement method has a large influence on the reliability of the data
underlying the regulatory floor or beyond-the-floor emissions limit. Of
particular concern are those data that are reported near or below a
test method's pollutant detection capability. In our guidance for
reporting pollutant emissions used to support this rule, we specified
the criteria for determining test-specific method detection levels.
Those criteria insure that there is about a 1 percent probability of an
error in deciding that the pollutant measured at the method detection
level is present when in fact it was absent. Such a probability is also
called a false positive or the alpha, Type I, error. Another view of
this probability is that one is 99 percent certain of the presence of
the pollutant measured at the method detection level. Because of matrix
effects, laboratory techniques, sample size, and other factors, method
detection levels normally vary from test to test. We requested sources
to identify (i.e., flag) data which were measured below the method
detection level and to report those values as equal to the test-
specific method detection level.
Variability of data due to measurement imprecision is inherently
and reasonably addressed in calculating the floor emissions limit when
the data base represents multiple tests for which all of the data are
measured significantly above the method detection level. That is less
true when the data base includes emissions occurring below method
detection capabilities and are reported as the method detection level
values. The data base is then truncated at the lower end of the
measurement range (i.e., no values reported below the method detection
level) and we believe that a floor emissions limit based on a truncated
data base or otherwise including values at or near the method detection
level may not adequately account for data measurement variability. We
did not adjust the calculated floor for the data used for this
proposal; although, we believe that accounting for measurement
imprecision should be an important
[[Page 32021]]
consideration in calculating the floor emissions limit. We request
comment on approaches suitable to account for measurement variability
in establishing the floor emissions limit when based on measurements at
or near the method detection level.
As noted above, the confidence level that a value measured at the
detection level is greater than zero is about 99 percent. The expected
measurement imprecision for an emissions value occurring at or near the
method detection level is about 40 to 50 percent. Pollutant measurement
imprecision decreases to a consistent relative 10 to 15 percent for
values measured at a level about three times the method detection
level.\8\ One approach that we believe could be applied to account for
measurement variability would require defining a method detection level
that is representative of the data used in establishing the floor
emissions limits and also minimizes the influence of an outlier test-
specific method detection level value. The first step in this approach
would be to identify the highest test-specific method detection level
reported in a data set that is also equal to or less than the floor
emissions limit calculated for the data set. This approach has the
advantage of relying on the data collected to develop the floor
emissions limit while to some degree minimizing the effect of a test(s)
with an inordinately high method detection level (e.g., the sample
volume was too small, the laboratory technique was insufficiently
sensitive, or the procedure for determining the detection level was
other than that specified).
---------------------------------------------------------------------------
\8\ American Society of Mechanical Engineers, Reference Method
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------
The second step would be to determine the value equal to three
times the representative method detection level and compare it to the
calculated floor emissions limit. If three times the representative
method detection level were less than the calculated floor emissions
limit, we would conclude that measurement variability is adequately
addressed and we would not adjust the calculated floor emissions limit.
If, on the other hand, the value equal to three times the
representative method detection level were greater than the calculated
floor emissions limit, we would conclude that the calculated floor
emissions limit does not account entirely for measurement variability.
We then would use the value equal to three times the method detection
level in place of the calculated floor emissions limit to ensure that
the floor emissions limit accounts for measurement variability. We
request comment on this approach.
We are requesting comment on whether there is a more appropriate
statistical approach to account for variability in the MACT floor
analyses when there are emission data from a limited number of units in
the subcategory.
However, after review of the available HAP data, including both
emission test data and fuel analyses, we determined that it was
inappropriate to use only this MACT floor approach to determine
variability and to establish emission limits for boilers and process
heaters, because this approach considers only the emissions test data.
The main problem with using only the HAP emissions test data is that
the data, which may reflect the variability of fuel-related HAP of the
best performing units, may not reflect the variability of fuel-related
HAP from the best performing units over the long term. Based on fuel-
related HAP concentrations (nine individual samples collected over a
30-day period) obtained, pursuant to letters mandating data gathering
issued under the authority of CAA section 114, fuel-related HAP levels
in the various fuels can vary significantly over time.
The first step in establishing a MACT standard is to determine the
MACT floor. A necessary step in doing so is determining the amount of
HAP emitted. In the case of fuel-related HAP emitted, this is not
necessarily a straightforward undertaking. Single stack measurements
represent a snapshot in time of a source's emissions, always raising
questions of how representative such emissions are of the source's
emissions over time. The variations in fuel-related HAP inputs directly
translate to a variability of fuel-related HAP stack emissions.
We believe that single short term stack test data (typically a few
hours) are probably not indicative of long term emissions performance,
and so are not the best indicators of performance over time. With these
facts in mind, we carefully considered alternatives other than use of
only single short-term stack test results to quantify performance for
fuel-related HAP. We decided that the most accurate method available to
us to determine long term fuel-related HAP emissions performance was to
use data on the fuel-related HAP inputs in the fuels used by the best
performing units, obtained as part of our information collection effort
under the authority of CAA section 114, on long-term fuel-related HAP
concentrations (nine individual samples collected over a 30-day period)
in each fuel, along with the fuel-related HAP concentrations during the
stack tests.
As previously discussed above, we account for variability in
setting floors, not only because variability is an element of
performance, but because it is reasonable to assess best performance
over time. Here, for example, we know that the HAP emission data from
the best performing units are short-term averages, and that the actual
HAP emissions from those sources will vary over time. If we do not
account for this variability, we would expect that even the units that
perform better than the floor on average would potentially exceed the
floor emission levels a significant part of the time which would mean
that variability was not properly taken into account. This variability
includes the day-to-day variability in the total fuel-related HAP input
to each unit and variability of the sampling and analysis methods, and
it includes the variability resulting from site-to-site differences for
the best performing units. We calculated the MACT floor based on the
UPL (upper 99th percentile) as described earlier from the average
performance of the best performing units, Students t-factor, and the
variability of the best performing units.
This approach reasonably ensures that the emission limit selected
as the MACT floor adequately represents the level of emissions actually
achieved by the average of the units in the top 12 percent, considering
ordinary operational variability of those units. 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.
A detailed discussion of the MACT floor methodology is presented in
the memorandum ``MACT Floor Analysis (2010) for the Industrial,
Commercial, and Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants--Major Source'' in the
docket.
1. Determination of MACT for the Fuel-Related HAP
In developing the proposed MACT floor for the fuel-related HAP
(non-mercury metals, acid gases, and mercury), as described earlier, we
are using PM as a surrogate for non-mercury metallic HAP and HCl as a
surrogate for the acid gases. Table 2 of this preamble presents the
number of units in each of the five subcategories, along with the
[[Page 32022]]
number of units from which we have collected emission data. Table 2
also presents for each subcategory and fuel-related HAP the number of
units comprising the best performing units (top 12 percent), the
average emission level of the top 12 percent, and the MACT floor (99
percent UPL of top 12 percent) which includes the variability across
the best performing units and the long term variability across those
units.
Table 2--Summary of MACT Floor Results for the Fuel-Related HAP for Existing Subcategories
----------------------------------------------------------------------------------------------------------------
Subcategory Parameter PM Mercury HCl
----------------------------------------------------------------------------------------------------------------
Units designed for Coal firing............ No. of sources in subcategory 578 578 578
No. of sources with data..... 366 285 318
No. in MACT floor............ 44 35 39
Avg of top 12%, lb/MMBtu..... 7.24E-03 5.95E-07 4.23E-03
99% UPL of top 12% (test 0.0179 1.64E-06 7.38E-03
runs), lb/MMBtu.
99% UPL with fuel variability ........... 2.88E-06 1.11E-02
of top 12%, lb/MMBtu.
Units designed for Biomass firing......... No. of sources in subcategory 420 420 420
No. of sources with data..... 192 91 92
No. in MACT floor............ 24 11 12
Avg of top 12%, lb/MMBtu..... 6.06E-03 3.46E-07 4.34E-03
99% UPL of top 12% (test 0.0162 7.52E-07 6.00E-03
runs), lb/MMBtu.
99% UPL with fuel variability ........... 8.88E-07 ...........
of top 12%, lb/MMBtu.
Units designed for Liquid Fuel firing..... No. of sources in subcategory 826 826 826
No. of sources with data..... 91 177 190
No. in MACT floor............ 11 22 23
Avg of top 12%, lb/MMBtu..... 1.40E-03 1.91E-06 2.59E-04
99% UPL of top 12% (test 0.00323 2.78E-06 3.26E-04
runs), lb/MMBtu.
99% UPL with fuel variability ........... 3.97E-06 8.04E-04
of top 12%, lb/MMBtu.
Units designed for other gas firing....... No. of sources in subcategory 199 199 199
No. of sources with data..... 13 8 8
No. in MACT floor............ 2 1 1
Avg of top 12%, lb/MMBtu..... 0.011 8.25E-08 1.70E-06
99% UPL of top 12% (test 0.045 1.86E-07 2.50E-06
runs), lb/MMBtu.
----------------------------------------------------------------------------------------------------------------
For three cases, the proposed new and existing source MACT floors
are almost identical because the best performing 12 percent of existing
units (for which we have emissions information) is only one or two
sources. The reason we look to the best performing 12 percent of
sources, even though we have data on fewer than 5 sources, is that
these subcategories consist of 30 or more units. CAA section
112(d)(3)(A) provides that standards for existing sources shall not be
less stringent than ``the average emission limitation achieved by the
best performing 12 percent of the existing sources (for which the
Administrator has emissions information), * * * in the category or
subcategory for categories and subcategories with 30 or more sources.''
A plain reading of the above statutory provisions is to apply the 12
percent rule in deriving the MACT floor for those categories or
subcategories with 30 or more sources. The parenthetical ``(for which
the Administrator has emissions information)'' in CAA section
112(d)(3)(A) modifies the best performing 12 percent of existing
sources, which is the clause it immediately follows.
However, in cases where there are 30 or more sources but little
emission data, this results in only a few units setting the existing
source floor with the result that the new and existing source MACT
floors are almost identical. In contrast, if these subcategories had
less than 30 sources, we would be required to use the top five best
performing sources, rather than the one or two that comprise the top 12
percent. Section 112(d)(3)(B).
We are seeking comment on whether, with the facts of this
rulemaking, we should consider reading the intent of Congress to allow
us to consider five sources rather than just one or two. First, it
seems evident that Congress was concerned that floor determinations
should reflect a minimum quantum of data: At least data from 5 sources
for source categories of less than 30 sources (assuming that data from
5 sources exist). Second, it does not appear that this concern would be
any less for subcategories with 30 or more sources. We are specifically
requesting comment on this interpretation relating to the proposed MACT
floors.\9\
---------------------------------------------------------------------------
\9\ The impact of using a minimum of five sources in the MACT
floor analyses for these subcategories and HAP are presented in the
Memorandum ``MACT Floor Analysis (2010) for the Industrial,
Commercial, and Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants--Major Sources''
located in the Docket.
---------------------------------------------------------------------------
2. Determination of MACT for Organic HAP
In developing the MACT floor for organic HAP, as described earlier,
we are using CO as a surrogate for non-dioxin organic HAP. Table 3 of
this preamble presents the number of units in each of the 11
subcategories, along with the number of units from which we have
collected emission data. Table 3 also presents for each subcategory
(for CO and D/F) the number of units comprising the best performing
units (top 12 percent), the average emission level of the top 12
percent, and the MACT floor (99 percent UPL of top 12 percent) which
includes the variability across the best performing units and the long
term variability.
We calculated the MACT floors based on the upper 99th percentile
UPL from the average performance of the best performing units and their
variances as described earlier for the fuel-related HAP.
[[Page 32023]]
Table 3--Summary of MACT Floor Results for the Organic HAP Subcategories
----------------------------------------------------------------------------------------------------------------
Subcategory Parameter CO Dioxin/Furan (TEQ)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal....................... No. of sources in 361................... 361.
subcategory.
No. of sources with data... 61.................... 14.
No. in MACT floor.......... 8..................... 2.
Avg of top 12%............. 21.4 ppm @ 3% O2...... 0.00182 ng/dscm @ 7%
O2.
99% UPL of top % (test 48.8 ppm @ 3% O2...... 0.00274 ng/dscm @ 7%
runs). O2.
Fluidized Bed--Coal................ No. of sources in 31.................... 31.
subcategory.
No. of sources with data... 17.................... 12.
No. in MACT floor.......... 3..................... 2.
Avg of top 12%............. 12.5 ppm @ 3% O2...... 0.000471 ng/dscm @ 7%
O2.
99% UPL of top % (test 21.4 ppm @ 3% O2...... 0.00168 ng/dscm @ 7%
runs). O2.
PC--Coal........................... No. of sources in 186................... 186.
subcategory.
No. of sources with data... 41.................... 10.
No. in MACT floor.......... 5..................... 2.
Avg of top 12%............. 19.2 ppm @ 3% O2...... 0.00158 ng/dscm @ 7%
O2.
99% UPL of top % (test 82.8 ppm @ 3% O2...... 0.00307 ng/dscm @ 7%
runs). O2.
Stoker--Biomass.................... No. of sources in 320................... 320.
subcategory.
No. of sources with data... 119................... 16.
No. in MACT floor.......... 15.................... 2.
Avg of top 12%............. 203 ppm @ 3% O2....... 0.000819 ng/dscm @ 7%
O2.
99% UPL of top % (test 551 ppm @ 3% O2....... 0.00339 ng/dscm @ 7%
runs). O2.
Fluidized Bed--Biomass............. No. of sources in 12.................... 12.
subcategory.
No. of sources with data... 7..................... 6.
No. in MACT floor.......... 5..................... 5.
Avg of top 12%............. 97.1 ppm @ 3% O2...... 0.00507 ng/dscm @ 7%
O2.
99% UPL of top 12% (test 245 ppm @ 3% O2....... 0.0127 ng/dscm @ 7%
runs). O2.
Suspension Burner/Dutch Oven....... No. of sources in 62.................... 62.
subcategory.
No. of sources with data... 17.................... 3.
No. in MACT floor.......... 3..................... 1.
Avg of top 12%............. 362 ppm @ 3% O2....... 0.00952 ng/dscm @ 7%
O2.
99% UPL of top 12% (test 1010 ppm @ 3% O2...... 0.0279 ng/dscm @ 7%
runs). O2.
Fuel Cell--Biomass................. No. of sources in 26.................... 26.
subcategory.
No. of sources with data... 16.................... 7.
No. in MACT floor.......... 5..................... 5.
Avg of top 12%............. 130 ppm @ 3% O2....... 0.00552 ng/dscm @ 7%
O2.
99% UPL of top 12% (test 262 ppm @ 3% O2....... 0.0148 ng/dscm @ 7%
runs). O2.
Units designed for Liquid fuel No. of sources in 826................... 826.
firing. subcategory.
No. of sources with data... 116................... 17.
No. in MACT floor.......... 14.................... 3.
Avg of top 12%............. 0.443 ppm @ 3% O2..... 0.000733 ng/dscm @ 7%
O2.
99% UPL of top 12% (test 0.911 ppm @ 3% O2..... 0.00182 ng/dscm @ 7%
runs). O2.
Units designed for other gases No. of sources in 199................... 199.
firing. subcategory.
No. of sources with data... 75.................... 5.
No. in MACT floor.......... 9..................... 1.
Avg of top 12%............. 0.0737 ppm @ 3% O2.... 0.00267 ng/dscm @ 7%
O2.
99% UPL of top 12% (test 0.134 ppm @ 3% O2..... 0.00828 ng/dscm @ 7%
runs). O2.
----------------------------------------------------------------------------------------------------------------
For organic HAP, as previously discussed above for fuel-related
HAP, we account for variability in setting floors, not only because
variability is an element of performance, but because it is reasonable
to assess best performance over time. Here, however, we know that the
organic HAP emissions will also vary over the operating range of the
unit, unlike fuel-related HAP emissions. Organic HAP are combustion-
related pollutants. That is, their levels of emissions are a function
of the combustion process. Combustion units operate most efficiently
when operated
[[Page 32024]]
at or near their design capacity. The combustion efficiency tends to
decrease as the unit's load (steam production) decreases. Most
industrial or commercial/institutional units do not continuously
operate at or near their design capacity but operate according to the
facility's demand for steam. Thus, operation at lower capacity rates
must be accounted for in determining operational variability.
As part of EPA's information collection effort, we obtained data on
organic HAP (THC and CO) from six units (two coal-fired, two biomass-
fired, and two gas-fired) that were collected using CEM over a 30-day
period. All of these units were selected to test using CEM to provide
variability information because their stack test results indicated that
they were among the best performing units.
The CEMS data shows that CO (as a surrogate for non-dioxin organic
HAP) from best performing units did not vary much when such unit is
operated at below design capacity. Therefore, even though ICI units,
due to steam demand, may operate at these low load conditions, no
additional variability due to operating load needs to be accounted for
since the average CO emission levels that include these low load
conditions are within the variability range determined by the
statistical analyses of CO emissions from the best performing units.
Thus, we are proposing to add no additional variability factor to
account for load variability to the MACT floor 99 percent UPL values
determined from the stack test data for CO emissions.
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 in each subcategory,
considering ordinary operational variability of those units. Both the
analysis of the measured emissions from units representative of the top
12 percent, and the variability analysis of those units, 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.
As was the case for the three fuel-dependent MACT floors, the
proposed new and existing source MACT floors for eight combustion-
dependent subcategories are almost identical because the best
performing 12 percent of units (for which we have emissions
information) is only one or two sources. Again, the reason we look to
the best performing 12 percent of sources is that these subcategories
consist of 30 or more units. In contrast, if these subcategories had
less than 30 sources, we would be required to use the top five best
performing sources, rather than the one or two that comprise the top 12
percent. As stated previously, we are seeking comment on whether, with
the facts of this rulemaking, we should consider reading the intent of
Congress to allow us to consider five sources rather than just one,
two, or three. We are specifically requesting comment on this
interpretation relating to the proposed MACT floors.
3. Determination of the Work Practice Standard
CAA section 112(h)(1) states that the Administrator may prescribe a
work practice standard or other requirements, consistent with the
provisions of CAA sections 112(d) or (f), in those cases where, in the
judgment of the Administrator, it is not feasible to enforce an
emission standard. CAA section 112(h)(2)(B) further defines the term
``not feasible'' in this context to apply when ``the application of
measurement technology to a particular class of sources is not
practicable due to technological and economic limitations.''
The standard reference methods for measuring emissions of mercury,
CO (as a surrogate for organic HAP), D/F, HCl (as a surrogate for acid
gases) and PM (as a surrogate for non-mercury metals) are EPA Methods
29, 10, 23, 26A and 5. These methods are reliable but relatively
expensive as a group. However, the methods are generally not able to
accurately sample small diameter (less than 12 inches) stacks. For
example, in these small diameter stacks, the conventional EPA Method 5
stack assembly blocks a significant portion of the cross-section of the
duct and, if unaccounted for, could cause inaccurate measurements. Many
existing small boilers and process heaters have stacks with diameters
less than 12 inches. The stack diameter is generally related to the
size of the unit. Units that have capacity below 10 million Btu per
hour generally have stacks with diameters less than 12 inches. Also,
many existing small units do not currently have sampling ports or a
platform for accessing the exhaust stack which would require an
expensive modification to install sampling ports and a platform.
We conducted a cost analysis \10\ to evaluate the economic impact
of the testing and monitoring costs that facilities with small units
would incur to demonstrate compliance with the proposed emission
limits. The compliance costs imposed on each facility would not only
include the costs of the stack tests and monitoring equipment but would
also include the capital costs of any installed control equipment. We
estimate that the total capital costs of installing control equipment
on the over 7,400 small boilers and process heaters to achieve the
proposed emission limits would be $6.3 billion. In addition to these
costs, additional costs would be incurred because many of these small
units do not have test ports or testing platforms installed in order to
conduct performance testing. Prior to conducting a stack test each unit
would need to construct or rent scaffolding and install test ports. EPA
estimates that these small sources would incur an additional $185
million to install test ports and rent temporary scaffolding. Many
establishments in each industry, commercial, or institutional sector
are associated with multiple (as many as a 700) small units.
---------------------------------------------------------------------------
\10\ Memorandum: Methodology for Estimating Impacts from
Industrial, Commercial, and Institutional Boilers and Process
Heaters at Major Sources of Hazardous Air Pollutant Emissions, March
23, 2010.
---------------------------------------------------------------------------
The results of the analysis indicate that the annual costs for
testing and monitoring costs alone would have a significant adverse
economic impact on these facilities. The severity of the economic
impact would depend on the size of the facility.
Based on this analysis, the Administrator has determined under CAA
section 112(h) that it is not feasible to enforce emission standards
for a particular class of existing boilers and process heaters because
of the technological and economic limitations described above. Thus, a
work practice, as discussed below, is being proposed to limit the
emission of HAP for existing boilers and process heaters having a heat
input capacity of less than 10 million Btu per hour. We are
specifically requesting comment on whether a threshold higher than 10
million Btu per hour meets the technical and economic limitations as
specified in CAA section 112(h).
For existing units, the only work practice being used that
potentially controls HAP emissions is a tune-up. Fuel dependent HAP are
typically controlled by removing them from the flue gas after
combustion. The only work practices expected to minimize fuel dependent
HAP emissions are reducing the fuel usage or fuel switching to a fuel
type with a lower HAP content. Fuel usage can be reduced by improving
the combustion efficiency of the unit, such as, by a tune-up. As
combustion efficiency decreases, fuel usage must increase to maintain
[[Page 32025]]
constant energy output. This increased fuel use results in increased
emissions.
On the other hand, organic HAP are formed from incomplete
combustion of the 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 combustion units, could be defined as the system design and
work practices expected to minimize organic HAP emissions.
We have obtained information on units that reported using GCP, as
part of the information collection effort for the NESHAP. The data that
we have suggests that units typically conduct tune-ups. We also
reviewed State regulations and permits. The work practices listed in
State regulations includes tune-ups (10 States), operator training (1
State), periodic inspections (2 States), and operation in accordance
with manufacturer specifications (1 State). Of the units with a
capacity of less than 10 MMBtu/h that responded to EPA's information
collection effort for the NESHAP, 80 percent reported conducting a
tune-up program. Ultimately, we determine that at least 6 percent of
the units in each of the subcategories are subject to a tune-up
requirement. Therefore, the proposed work practice of a tune-up \11\
program does establish the MACT floor for HAP emissions from existing
units with a heat input capacity of less than 10 MMBtu/h.
---------------------------------------------------------------------------
\11\ Tune-up procedure is specified in section 63.7540 of this
proposed rule and includes making adjustments to the burner to
optimize the flame to minimize CO emissions consistent with the
manufacturer's specifications.
---------------------------------------------------------------------------
We are also proposing a work practice standard under section 112(h)
that would require an annual tune-up for existing boilers and process
heaters combusting natural gas or refinery gas. These boilers and
process heaters are units included in the Gas 1 and metal processing
furnace subcategories. We are specifically seeking comment on whether
the application of measurement methodology to sources in this
subcategory is impracticable due to technological or economic
limitations, as specified in section 112(h)(2)(B).
This work practice standard is being proposed for several reasons.
First, the capital costs estimated for installing controls on these
boilers and process heaters to comply with MACT limits for the five HAP
groups is over $14 billion. This cost includes installation of a
combination system of a fabric filter (for PM, mercury, and D/F
control) and a wet scrubber (for HCl control). This capital cost is
higher than the estimated combined capital cost for boilers and process
heaters in all of the other subcategories. The projected control system
needed for boilers and process heaters in the other subcategories is
also a combined fabric filter/wet scrubber system.
Second, we believe that proposing emission standards for gas-fired
boilers and process heaters that result in the need to employ the same
emission control system as needed for the other fuel types would have
the negative benefit of providing a disincentive for switching to gas
as a control technique (and a pollution prevention technique) for
boilers and process heaters in the other fuel subcategories. In
addition, emission limits on gas-fired boilers and process heaters may
have the negative benefit of providing an incentive for a facility to
switch from gas (considered a ``clean'' fuel) to a ``dirtier'' but
cheaper fuel (i.e., coal). It would be inconsistent with the emissions
reductions goals of the CAA, and of section 112 in particular, to adopt
requirements that would result in an overall increase in HAP emissions.
We are soliciting comment on the extent to which natural gas facilities
would be expected to switch to a ``dirtier'' fuel if emissions limits
for such facilities are adopted.
Thus, a work practice, as discussed above for small boilers and
process heaters, is being proposed to limit the emission of HAP for
existing natural gas-fired and refinery gas-fired boilers and process
heaters.
We request comments on whether the emission limits listed in Table
4 of this preamble for the Gas 1 and Metal Process Furnace
subcategories should be promulgated. Comments should include detailed
information regarding why emission limits for these gas-fired boilers
and process heaters are appropriate.
Table 4--Summary of MACT Floor Results for the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
Dioxin/furan
Subcategory Parameter PM Mercury HCl CO (total TEQ)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing. No. of sources in 10,783............ 10,783............ 10,783............ 10,783............ 10,783.
subcategory.
No. of sources 144............... 14................ 11................ 754............... 8.
with data.
No. in MACT floor. 18................ 2................. 2................. 91................ 1.
Avg of top 12%.... 0.00388 lb/MMBtu.. 1.1E-07 lb/MMBtu.. 1.01E-04 lb/MMBtu. 1.45 ppm @ 3% 0.0026 ng/dscm @
oxygen. 7% oxygen.
99% UPL of top 12% 0.03 lb/MMBtu..... 2.0E-07 lb/MMBtu.. 0.0002 lb/MMBtu... 20 ppm @ 3% oxygen 0.01 ng/dscm @ 7%
(test runs). oxygen.
Metal Process Furnaces.......... No. of sources in 749............... 749............... 749............... 749............... 749.
subcategory.
No. of sources 9................. 7................. 9................. 15................ 7.
with data.
No. in MACT floor. 2................. 1................. 2................. 2................. 1.
Avg of top 12%.... 0.0047 lb/MMBtu... 3.3E-08 lb/MMBtu.. 1.92E-04 lb/MMBtu. 0.38 ppm @ 3% 0.0026 ng/dscm @
oxygen. 7% oxygen.
99% UPL of top 12% 0.02 lb/MMBtu..... 2.0E-07 lb/MMBtu.. 0.0004 lb/MMBtu... 2 ppm @ 3% oxygen. 0.004 ng/dscm @ 7%
(test runs). oxygen.
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 32026]]
E. How did EPA consider beyond-the-floor options for existing units?
Once the MACT floor determinations were done for each subcategory,
we 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. 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.
We could not identify better HAP emissions reduction approaches
that could achieve greater emissions reductions of HAP than the control
technology combination (fabric filter, carbon injection, scrubber, and
GCP) that we expect will be used to meet the MACT floor level of
control.
For each subcategory, fuel switching to natural gas is an option
that would reduce HAP emissions. We determined that fuel switching was
not an appropriate beyond-the-floor option. First, 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.
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 $13.5 billion compared with $3.5 billion under the
floor approach. The emission reduction associated with fuel switching
was estimated to be 4,296 tons per year for metallic HAP, 8 tons per
year for mercury, and 50,332 tons per year for inorganic HAP (HCl and
HF). The cost for fuel switching is over double the cost of the floor
approach while the emission reductions associated with fuel switching
are approximately the same. Additional detail on the calculation
procedures is provided in the memorandum ``Development (2010) 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.
We also considered the pollution prevention and energy conservation
measure of an energy assessment/audit as a beyond-the-floor option for
HAP emissions. An energy assessment provides valuable information on
improving energy efficiency. An energy assessment, or audit, is an in-
depth energy study identifying all energy conservation measures
appropriate for a facility given its operating parameters. An energy
assessment refers to a process which involves a thorough examination of
potential savings from energy efficiency improvements, pollution
prevention, and productivity improvement. It leads to the reduction of
emissions of pollutants through process changes and other efficiency
modifications. Besides reducing operating and maintenance costs,
improving energy efficiency reduces negative impacts on the environment
and results in reduced emissions and improved public health.
Improvement in energy efficiency results in decreased fuel use which
results in a corresponding decrease in emissions (both HAP and non-HAP)
from the combustion unit, but not necessarily a decrease in emissions
of all HAP emitted. The Department of Energy has conducted energy
assessments at selected manufacturing facilities and reports that
facilities can reduce fuel/energy use by 10 to 15 percent by using best
practices to increase their energy efficiency. Many best practices are
considered pollution prevention because they reduce the amount of fuel
combusted which results in a corresponding reduction in emissions from
the fuel combustion. The most common best practice is simply tuning the
boiler to the manufacturer's specification.
The one-time cost of an energy assessment ranges from $2500 to
$55,000 depending on the size of the facility. The total annualized
cost if each major source facility conducted an energy assessment is
estimated at $26 million. If a facility implemented the cost-effective
energy conservation measures identified in the energy assessment, it
would potentially result in greater HAP reduction than achieved by a
boiler tune-up alone and potentially reducing HAP emissions (HCl,
mercury, non-mercury metals, and VOC) by an additional 820 to 1,640
tons per year. In addition, the costs of any energy conservation
improvement will be offset by the cost savings in lower fuel costs.
Therefore, we decided to go beyond the MACT floor for this proposed
rule for the existing units. These proposed standards for existing
units include the requirement of a performance of an energy assessment
to identify cost-effective energy conservation measures. Since there
was insufficient information to determine if requiring implementation
of cost-effective measures were economically feasible, we are seeking
comment on this point.
In this proposed rule, we are defining a cost-effective energy
conservation measure to be any measure that has a payback (return of
investment) period of 2 years or less. This payback period was selected
based on section 325(o)(2)(B)(iii) of the Energy Policy and
Conservation Act which states that there is a presumption that an
energy conservation standard is economically justified if the increased
installed cost for a measure is less than three times the value of the
first-year energy savings resulting from the measure.
We believe that an energy assessment is an appropriate beyond-the-
floor control technology because it is one of the measures identified
in CAA section 112(d)(2). CAA section 112(d)(2) states that ``Emission
standards promulgated * * * and applicable to new or existing sources *
* * is achievable * * * through application of measures, processes,
methods, systems or techniques including, but not limited to measures
which * * * reduce the volume of, or eliminate emissions of, such
pollutants through process changes, substitution of materials or other
modifications * * *''
The purpose of an energy assessment is to identify energy
conservation measures (such as, process changes or other modifications
to the facility) that can be implemented to reduce the facility energy
demand which would result in reduced fuel use. Reduced fuel use will
result in a corresponding reduction in HAP, and non-HAP, emissions.
Thus, an energy assessment, in combination with the MACT emission
limits will result in the maximum degree of reduction in emissions as
required by 112(d)(2). Therefore, we are proposing to require all
existing sources to conduct a one-time energy assessment to identify
cost-effective energy conservation measures.
We are proposing that the energy assessment be conducted by energy
professionals and/or engineers that have expertise that cover all
energy using systems, processes, and equipment. We are aware of, at
least, two organizations that provide certification of specialists in
evaluating energy systems. We are proposing that a qualified
specialized is someone who has successfully completed the Department of
Energy's Qualified Specialist Program for all systems or a professional
engineer certified as a Certified Energy Manager by the Association of
Energy Engineers.
As part of the energy assessment, we are proposing that the
facility assess its energy management program and
[[Page 32027]]
practices using EPA's ENERGY STAR Facility Energy Management Assessment
Matrix. ENERGY STAR has a simple facility energy management assessment
tool that can be used as part of the assessment process. This tool
identifies gaps in current practices. Facilities, as part of the
requirement, would identify steps to close the management gaps. We are
also proposing that the facility develop an energy management program
according to the ENERGY STAR Guidelines for Energy Management (see
www.energystar.gov/guidelines).\12\
---------------------------------------------------------------------------
\12\ The location of the guidance is: http://www.energystar.gov/index.cfm?c=guidelines.assess_facility_energy.
---------------------------------------------------------------------------
We are specifically requesting comment on: (1) Whether our
estimates of the assessment costs are correct; (2) is there adequate
access to certified assessors; (3) are there other organizations for
certifying energy engineers; (4) are online tools adequate to inform
the facility's decision to make efficiency upgrades; (5) is the
definition of ``cost-effective'' appropriate in this context since it
refers to payback of energy saving investments without regard to the
impact on HAP reduction; (6) what rate of return should be used; and
(7) are there other guidelines for energy management beside ENERGY
STAR's that would be appropriate.
We considered proposing a beyond-the-floor requirement for certain
sources in the natural gas and refinery gas subcategory (i.e., the Gas
1 subcategory). Specifically, we considered proposing that facilities
with boilers or process heaters combusting refinery gas install and
maintain a carbon adsorber bed system \13\ to remove mercury from the
refinery gas before combustion in a boiler or process heater. Based on
data from the information collection effort, refinery gas contains
mercury and additional mercury reductions can be achieved from units
combusting refinery gas. Consequently, we analyzed the mercury
emissions reductions and additional cost of adopting this work
practice. The annualized cost of the carbon adsorber bed system to
treat the refinery gas prior to combustion is estimated to be about 1.6
billion dollars with a mercury emission reduction of 0.8 tons. The
results indicated that while additional mercury 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 requiring the installation of carbon bed
adsorbers. Therefore, we are not proposing installation of a carbon
adsorber bed system as a beyond-the-floor requirement.
---------------------------------------------------------------------------
\13\ Carbon adsorption of mercury can be accomplished by (a)
injecting dry carbon with or without other dry sorbents into the
offgas upstream of a PM control device (typically a baghouse), or
(b) using a fixed or moving bed of granular carbon through which the
offgas flows. In a typical fixed bed carbon adsorption system, the
flue gas flows through a vessel packed with a specified depth of the
carbon granules. The bed and packing are designed to limit the
linear velocity of the offgas in the bed to increase the contact
time with the carbon. Due to the increased contact times and
typically lower operating temperatures, better removal efficiencies
can be achieved than for carbon injection. At a residence time of 10
seconds in the carbon bed, virtually all of the mercury can be
removed. (Ref. NUCON INTERNATIONAL, Inc., ``Design & Performance
Characteristics of MERSORBB Mercury Adsorbents in Liquids and
Gases,'' NUCON 11B28, August 1995.)
---------------------------------------------------------------------------
F. Should EPA consider different subcategories for solid fuel boilers
and process heaters?
The boilers and process heaters source category is tremendously
heterogeneous. 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.
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. 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, the
approach for determining the MACT floor must be based on available
emissions test data. Using such an approach, we calculated the MACT
floor for a subcategory of sources by ranking the emission test results
from units within the subcategory from lowest to highest to identify
the best controlled similar source. The MACT floor limits for each of
the HAP and HAP surrogates (PM, mercury, CO, HCl, and D/F) are
calculated based on the performance (numerical average) of the lowest
emitting (best controlled) source for each pollutant in each of the
subcategories.
The MACT floor limits for new sources were calculated using the
same formula as was used for existing sources. However, as was the case
for the existing MACT floor analysis, we determined that it was
inappropriate to use only this MACT floor approach to determine
variability and to establish emission limits for new boilers and
process heaters. The main problem with using only the HAP emissions
test data is that the data may not reflect the variability of fuel-
related HAP from the best controlled similar source over the long term.
Based on our current information, fuel-related HAP levels in the
various fuels can vary significantly over time. The variations in fuel-
related HAP inputs directly translate to a variability of fuel-related
HAP stack emissions.
As previously discussed above, we account for variability of the
best-controlled source in setting floors, not only because variability
is an element of performance, but because it is reasonable to assess
best performance over time. If we do not account for this variability,
we would expect that even the best controlled similar source would
potentially exceed the floor emission levels a significant part of the
time which would mean that their variability was not properly accounted
for when setting the floor. We calculated the MACT floor based on the
UPL (upper 99th percentile) as described earlier from the average
performance of the best controlled similar source, Students t-factor,
and the total variability of the best-controlled source.
[[Page 32028]]
This approach reasonably ensures that the emission limit selected
as the MACT floor adequately represents the average level of control
actually achieved by the best controlled similar source, considering
ordinary operational variability.
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.
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 performance achieved by
the average of the best performing 12 percent 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 determined what the best controlled source has achieved 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 the best-controlled source in the
subcategory. These approaches, respectively, represent the most
reasonable way to estimate performance for purposes of establishing
MACT floors for new units, given the data available.
For fuel dependent HAP emissions (mercury and HCl), we calculated
the variability factor by looking at data on HAP variability in fuel
obtained through our 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 fuel
analyses from the best-controlled source. Once we calculated the fuel
dependent variability factors, we applied these factors to the average
measured emissions performance of the best controlled similar source to
derive the MACT floor level of control. This approach reasonably
estimates the best source's level of emissions, adjusted for
unavoidable variation in fuel characteristics which have a direct
impact on emissions.
1. Determination of MACT for the Fuel-Related HAP
In developing the MACT floor for the fuel-related HAP (PM, HCl, and
mercury), as described earlier, we are using PM as a surrogate for non-
mercury metallic HAP and HCl as a surrogate for the acid gases. Table 5
presents for each subcategory and fuel-related HAP the average emission
level of the best controlled similar source and the MACT floor (99
percent UPL) which includes the variability across the best controlled
similar source and the long term variability of that source.
Table 5--Summary of MACT Floor Results for the Fuel-Related HAP for New Sources
----------------------------------------------------------------------------------------------------------------
Mercury Lb/ HCl Lb/
Subcategory Parameter PM Lb/MMBtu MMBtu MMBtu
----------------------------------------------------------------------------------------------------------------
Units designed for Coal firing............ Avg of top performer......... 0.000396 1.18E-07 3.85E-05
99% UPL of top performer 0.000928 3.89E-07 5.21E-05
(test runs).
Units designed for Biomass firing......... Avg of top performer......... 0.00216 9.73E-08 7.85E-04
99% UPL of top performer 0.00711 1.86E-07 3.07E-03
(test runs).
Units designed for Liquid Fuel firing..... Avg of top performer......... 0.000511 5.87E-08 3.99E-04
99% UPL of top performer 0.00154 2.47E-07 9.80E-04
(test runs).
Units designed for other gas firing....... Avg of top performer......... 0.00042 8.25E-08 1.70E-06
99% UPL of top performer 0.0024 1.86E-07 2.50E-06
(test runs).
----------------------------------------------------------------------------------------------------------------
2. Determination of MACT for Organic HAP
In developing the MACT floor for organic HAP, as described earlier,
we are using CO as a surrogate for non-dioxin organic HAP. Table 6
presents for each subcategory and CO and D/F the average emission level
of the best controlled similar source and the MACT floor (99 percent
UPL) which includes the variability across the best controlled similar
source and the long term variability of that source.
Table 6--Summary of MACT Floor Results for the Organic HAP for New Sources
----------------------------------------------------------------------------------------------------------------
Dioxin/Furan
CO (ppm @ 3 (TEQ) (ng/dscm @
Subcategory Parameter percent oxygen) 7 percent
oxygen)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal................................ Avg of top performer.......... 4.29 1.52E-03
99% UPL of top performer (test 6.53 2.82E-03
runs).
Fluidized Bed--Coal......................... Avg of top performer.......... 8.26 9.05E-06
99% UPL of top performer (test *39.9 2.54E-05
runs).
PC--Coal.................................... Avg of top performer.......... 25.0 1.04E-03
99% UPL of top performer (test *97.5 1.47E-03
runs).
Stoker--Biomass............................. Avg of top performer.......... 920 1.52E-05
99% UPL of top performer (test *3730 4.86E-05
runs).
Fluidized Bed--Biomass...................... Avg of top performer.......... 25.8 2.27E-03
99% UPL of top performer (test 34.2 6.48E-03
runs).
Suspension Burner/Dutch Oven................ Avg of top performer.......... 352 9.52E-03
99% UPL of top performer (test *1050 2.79E-02
runs).
Fuel Cell--Biomass.......................... Avg of top performer.......... 110 2.42E-04
[[Page 32029]]
99% UPL of top performer (test *264 4.17E-04
runs).
Units designed for Liquid fuel firing....... Avg of top performer.......... 0.125 1.09E-03
99% UPL of top performer (test 0.125 1.52E-03
runs).
Units designed for other gases firing....... Avg of top performer.......... 0.0129 2.67E-03
99% UPL of top performer (test 0.0129 8.28E-03
runs).
----------------------------------------------------------------------------------------------------------------
* Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit
for the same subcategory.
For organic HAP, as previously discussed above for the fuel-
related, we account for variability in setting floors, not only because
variability is an element of performance, but because it is reasonable
to assess best performance over time. Here, we know that CO (as a
surrogate for non-dioxin organic HAP) emissions does not vary
significantly over the operating range of the unit. Thus, we have not
added any additional operational variability to account for operation
at lower capacity rates.
We are proposing a work practice standard under section 112(h) that
would require an annual tune-up for new boilers and process heaters
combusting natural gas or refinery gas. These boilers and process
heaters are units included in the Gas 1 and metal processing furnace
subcategories. We are specifically seeking comment on whether the
application of measurement methodology to sources in this subcategory
is impracticable due to technological or economic limitations, as
specified in section 112(h)(2)(B).
This proposal for new boilers and process heaters combusting
natural gas or refinery gas is based on the same reasons discussed
previously for existing boilers and process heaters combusting natural
gas or refinery gas. That is, we believe that proposing emission
standards for new gas-fired boilers and process heaters that result in
the need to employ the same emission control system as needed for the
other fuel types would have the negative benefit of providing a
disincentive for switching to gas as a control technique (and a
pollution prevention technique) for boilers and process heaters in the
other fuel subcategories. In addition, emission limits on gas-fired
boilers and process heaters may have the negative benefit of providing
an incentive for a facility to switch from gas (considered a ``clean''
fuel) to a ``dirtier'' but cheaper fuel (i.e., coal). It would be
inconsistent with the emissions reductions goals of the CAA, and of
section 112 in particular, to adopt requirements that would result in
an overall increase in HAP emissions. We are soliciting comment on the
extent to which new facilities would be expected to switch away from
natural gas to a ``dirtier'' fuel if emissions limits for new such
facilities are adopted.
Thus, a work practice, as discussed above for existing boilers and
process heaters combusting natural gas or refinery gas, is being
proposed to limit the emission of HAP for new natural gas-fired and
refinery gas-fired boilers and process heaters.
We request comments on whether the emission limits listed in Table
7 of this preamble for new units in the Gas 1 and Metal Process Furnace
subcategories should be promulgated. Comments should include detailed
information regarding why emission limits for these gas-fired boilers
and process heaters are appropriate.
Table 7--Summary of MACT Floor Results for New Units in the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
Dioxin/Furan
CO (ppm @ 3 (Total TEQ)
Subcategory Parameter PM Lb/MMBtu Mercury Lb/ HCl LB/MMBtu percent (ng/dscm @ 7
MMBtu oxygen) percent
oxygen)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing........... Avg of top performer........ 0.00013 9.4E-08 7.3E-05 5 0.0026
99% UPL of top (test runs) = 0.0005 2.0E-07 0.0002 20 0.01
Metal Process Furnaces.................... Avg of top performer........ 0.0065 3.3E-08 8.6E-05 0.5 0.0026
99% UPL of top (test runs) = 0.02 2.0E-07 0.0002 2 0.004
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 HAP reduction greater than the new source
floors for the subcategories.
Fuel switching to natural gas is a potential regulatory option
beyond the new source floor level of control that would reduce HAP
emissions from non-gas-fired units. 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. In addition, 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.
Thus, this potential control option may be unavailable to many sources
in practice. Limited emissions reductions in combination with the high
cost of fuel switching and considerations about the
[[Page 32030]]
availability and technical feasibility of fuel switching makes this an
unreasonable regulatory option that was not considered further.\14\
Nonair quality health, environmental impacts, and energy effects were
not significant factors. No beyond-the-floor options for gas-fired
boilers were identified.
---------------------------------------------------------------------------
\14\ Memorandum ``Development (2010) of Fuel Switching Costs and
Emission Reductions for Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for
Hazardous Air Pollutants,'' April 2010.
---------------------------------------------------------------------------
An energy assessment is a beyond-the-floor standard being proposed
for existing facilities. However, we are not proposing it as a beyond-
the-floor option for new major source facilities since we believe it
would not be cost effective because most projected new boilers or
process heaters will be installed at existing major source facility
which would have already conducted an energy assessment as required by
this proposed rule. We also believe that any new greenfield major
source facility having boilers or process heaters will be designed to
operate with energy efficiency.
Based on the analysis discussed above, EPA decided to not go beyond
the MACT floor level of control for new sources in this 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. Consideration of whether to set standards for HCl and other acid
gases under section 112(d)(4)
We are proposing to set a conventional MACT standard for HCl and,
for the reasons explained elsewhere in today's notice, are proposing
that the HCl limit also serve as a surrogate for other acid gas HAP. We
also considered whether it was appropriate to exercise our
discretionary authority to establish health-based emission standards
under section 112(d)(4) for HCl and each of the other relevant HAP acid
gases: Chlorine (Cl2), hydrogen fluoride (HF), and hydrogen
cyanide (HCN) \15\ (since if it were regulated under section 112(d)(4),
HCl may no longer be the appropriate surrogate for these other
HAPs).\16\ This section sets forth the requirements of section
112(d)(4), our analysis of the information available to us that
informed the decision on whether to exercise discretion, questions
regarding the application of 112(d)(4) and solicitation of comments,
and explains how this case relates to prior decisions EPA has made
under section 112(d)(4) with respect to HCl.
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\15\ Before considering whether to exercise her discretion under
section 112(d)(4) for a particular pollutant, the Administrator must
first conclude that a health threshold has been established for the
pollutant.
\16\ HCl can serve as a surrogate for the other acid gases in a
technology-based MACT standard, because the control technology that
would be used to control HCl would also reduce the other acid gases.
By contrast, HCl would not be an appropriate surrogate for a health-
based emission standard that is protective against the potential
adverse health effects from the other acid gases, because these
gases (e.g., HCN) can act on biological organisms in a different
manner than HCl, and each of the acid gases affects human health
with a different dose-response relationship.
---------------------------------------------------------------------------
As a general matter, section 112(d) requires MACT standards at
least as stringent as the MACT floor to be set for all HAP emitted from
major sources. However, section 112(d)(4) provides that for HAP with
established health thresholds, the Administrator has the discretionary
authority to consider such health thresholds when establishing emission
standards under section 112(d). This provision is intended to allow EPA
to establish emission standards other than conventional MACT standards,
in cases where a less stringent emission standard will still ensure
that the health threshold will not be exceeded, with an ample margin of
safety. In order to exercise this discretion, EPA must first conclude
that the HAP at issue has an established health threshold and must then
provide for an ample margin of safety when considering the health
threshold to set an emission standard.
The legislative history of section 112(d)(4) indicates that
Congress did not intend for this provision to provide a mechanism for
EPA to delay issuance of emission standards for sources of HAPs.
Finally, the legislative history also indicates that a health-based
emission limit under section 112(d)(4) should be set at the level at
which no observable effects occur, with an ample margin of safety. S.
Rep. 101-228 at 171-72.
It is clear the Administrator may exercise her discretionary
authority under 112(d)(4) only with respect to pollutants with an
health threshold. Where there is an established threshold, the
Administrator interprets section 112(d)(4) to allow her to weigh
additional factors, beyond any established health threshold, in making
a judgment whether to set a standard for a specific pollutant based on
the threshold, or instead follow the traditional path of developing a
MACT standard after determining a MACT floor. In deciding whether to
exercise her discretion for a threshold pollutant for a given source
category, the Administrator interprets section 112(d)(4) to allow her
to take into account factors such as the following: The potential for
cumulative adverse health effects due to concurrent exposure to other
HAPs with similar biological endpoints, from either the same or other
source categories, where the concentration of the threshold pollutant
emitted from the given source category is below the threshold; the
potential impacts on ecosystems of releases of the pollutant; and
reductions in criteria pollutant emissions and other co-benefits that
would be achieved via the MACT standard. Each of these factors is
directly relevant to the health and environmental outcomes at which
section 112 of the Clean Air Act is fundamentally aimed. If the
Administrator does determine that it is appropriate to set a standard
based on a health threshold, she must develop emission standards that
will ensure the public will not be exposed to levels of the pertinent
HAP in excess of the health threshold, with an ample margin of safety.
EPA has exercised its discretionary authority under section
112(d)(4) in a handful of prior actions setting emissions standards for
other major source categories, including the emissions standards issued
in 2004 for commercial and industrial boilers and process heaters,
which were vacated on other grounds by the U.S. Court of Appeals for
the D.C. Circuit. In both the Pulp and Paper MACT, 63 FR at 18765
(April 15, 1998), and Lime Manufacturing MACT, 67 FR at 78054 (December
20, 2002), EPA invoked 112(d)(4) for HCl emissions for discrete units
within the facility. In those actions, EPA concluded that HCl had an
established health threshold (in those cases it was interpreted as the
reference concentration for chronic effects, or RfC) and was not
classified as a human carcinogen. In light of the absence of evidence
of carcinogenic risk, the availability of information on non-
carcinogenic effects, and the limited potential health risk associated
with the discrete units being regulated, EPA concluded that it was
appropriate to exercise its discretion under section 112(d)(4) for HCl
under the circumstances of those actions. EPA did not set an emission
standard based on the health threshold; rather, the exercise of EPA's
discretion in those cases in effect exempted HCl from the MACT
requirement. In a more recent action, EPA decided not to propose a
health-based emission standard for HCl
[[Page 32031]]
emissions under section 112(d)(4) for Portland Cement facilities, 74 FR
at 21154 (May 6, 2009). EPA has never implemented a NESHAP that used
section 112(d)(4) with respect to HF, Cl2 or HCN.\17\
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\17\ EPA has not classified HF, chlorine gas, or HCN with
respect to carcinogenicity. However, at this time the Agency is not
aware of any data that would suggest any of these HAPs are
carcinogens.
---------------------------------------------------------------------------
Since any emission standard under section 112(d)(4) must consider
the established health threshold level, with an ample margin of safety,
in this rulemaking EPA has considered the adverse health effects of the
HAP acid gases, beginning with HCl. Research indicates that HCl is
associated with chronic respiratory toxicity. In the case of HCl, this
means that chronic inhalation of HCl can cause tissue damage in humans.
Among other things, it is corrosive to mucous membranes and can cause
damage to eyes, nose, throat, and the upper respiratory tract as well
as pulmonary edema, bronchitis, gastritis, and dermatitis. Considering
this respiratory toxicity, EPA has established a chronic reference
concentration (RfC) for the inhalation of HCl of 20 [mu]g/m\3\. An RfC
is defined as an estimate (with uncertainty spanning perhaps an order
of magnitude) of a continuous inhalation exposure to the human
population (including sensitive subgroups \18\) that is likely to be
without an appreciable risk of deleterious effects during a lifetime.
The development of the RfC for HCl reflected data only on its chronic
respiratory toxicity. It did not take into account effects associated
with acute exposure,\19\ and, in this situation, the IRIS health
assessment did not evaluate the potential carcinogenicity of HCl (on
which there are very limited studies). As a reference value for a
single pollutant, the RfC also did not reflect any potential cumulative
or synergistic effects of an individual's exposure to multiple HAPs or
to a combination of HAPs and criteria pollutants. As the RfC
calculation focused on health effects, it did not take into account the
potential environmental impacts of HCl.
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\18\ ``Sensitive subgroups'' may refer to particular life
stages, such as children or the elderly, or to those with particular
medical conditions, such as asthmatics.
\19\ California EPA considered acute toxicity and established a
1-hour reference exposure level (REL) of 2.1 mg/m\3\. An REL is the
concentration level at or below which no adverse health effects are
anticipated for a specified exposure duration. RELs are designed to
protect the most sensitive individuals in the population by the
inclusion of margins of safety.
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With respect to the potential health effects of HCl, we know the
following:
1. Chronic exposure to concentrations at or below the RfC is not
expected to cause chronic respiratory effects;
2. Little research has been conducted on its carcinogenicity. The
one occupational study of which we are aware found no evidence of
carcinogenicity;
3. There is a significant body of scientific literature addressing
the health effects of acute exposure to HCl (California Office of
Health Hazard Assessment, 2008. Acute Toxicity Summary for Hydrogen
Chloride, http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_final.pdf#page=112 EPA, 2001). However, we currently lack information
on the peak short-term emissions of HCl from boilers, which might allow
us to determine whether a chronic health-based emission standard for
HCl would ensure that acute exposures will not pose any health
concerns;
4. We are aware of no studies explicitly addressing the toxicity of
mixtures of HCl with other respiratory irritants. However, many of the
other HAPs (and criteria pollutants) emitted by boilers also are
respiratory irritants, and in the absence of information on
interactions, EPA assumes an additive cumulative effect (Supplementary
Guidance for Conducting Health Risk Assessment of Chemical Mixtures.
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=20533). The fact
that boilers can be located among a wide variety of industrial
facilities makes predicting and assessing all possible mixtures of HCl
and other emitted air pollutants difficult, if not impossible.
In addition to potential health impacts, the Administrator also has
evaluated the potential for environmental impacts when considering
whether to exercise her discretion under section 112(d)(4). The
legislative history states that employing a section 112(d)(4) standard
rather than a conventional MACT standard ``shall not result in adverse
environmental effects which would otherwise be reduced or eliminated.''
S. Rep. 101-228 at 171. When HCl gas encounters water in the
atmosphere, it forms an acidic solution of hydrochloric acid. In areas
where the deposition of acids derived from emissions of sulfur and
nitrogen oxides are causing aquatic and/or terrestrial acidification,
with accompanying ecological impacts, the deposition of hydrochloric
acid could exacerbate these impacts. Being mindful of the legislative
history, it is appropriate to consider potential adverse environmental
effects in addition to adverse health effects when setting an emission
standard for HCl under section 112(d)(4).
Because the statute requires an ample margin of safety, it would be
reasonable to set any section 112(d)(4) emission standard for a
pollutant with a health threshold at a level that at least assures
that, for the sources in the controlled category or subcategory,
persons exposed to emissions of the pollutant would not experience the
adverse health effects on which the threshold is based. In the case of
this proposed rulemaking, we have concluded that we do not have
sufficient information at this time to establish what the health-based
emission standards would be for HCl or the other acid gases. Public
comments are invited on our information and conclusion.
When Congress established the technology-based MACT program in the
1990 Clean Air Act Amendments, it recognized the challenges involved in
evaluating health risk. Determining an emission standard that will
protect the public health with an ample margin of safety is complex, in
part because of the limited data available on cumulative impacts. In
order to assess the feasibility of health-based standards in this rule,
the agency believes it would need additional facility-specific
emissions information. Such information would enable us to develop
model plants for the eleven subcategories considered in the proposed
rule and allow us to conduct the dispersion modeling necessary to
establish health-based emission limits. These limits would need to be
established to ensure that exposure is below the health threshold for
sources in the subcategory, and account for the possibility of multiple
exposures from co-located sources as well as potential short-term
increases in emissions for these sources and their short-term impacts.
Currently, the Agency has very limited information on facility-specific
emissions, plant configurations, and overall fence-line characteristics
for this large and diverse source category. This information is a
precondition to establishing health-based emission standards that
provide an ample margin of safety. To this end, the Agency is
requesting information on these factors from the regulated community
and others to allow us to evaluate the appropriateness and viability of
health-based emission limits.
EPA specifically requests comment on the following issues.
Additional information on these issues is important to implement
section 112(d)(4) in a reasonable and appropriate manner, if we were to
establish emissions standards under that provision. First,
[[Page 32032]]
EPA requests comment on whether it would be appropriate to establish
section 112(d)(4) standards for each acid gas described above, or
whether EPA could set a single 112(d)(4) standard for one of the acid
gases as a surrogate for the other acid gases. Commenters who believe a
surrogate would be appropriate should also address the mechanism that
should be used to determine the appropriate surrogate. In order to set
individual standards under section 112(d)(4) for each acid gas, we
would need to be able to conclude that each has an appropriate health
threshold, that there is no scientific evidence that they are
carcinogenic, and that the emission standard for each uses the best
available science to consider the possibility of toxicologic
interactions with the other emitted gases. Alternatively, if we were to
establish a health-based emission standard for one of the acid gases as
a surrogate for the others, in addition to the above considerations, we
would need to demonstrate, based on a knowledge of the effectiveness of
scrubbers for controlling each of the acid gases, that the surrogate
emission standard effectively ensures that ambient levels of each of
the other acid gases do not exceed their respective chronic health
thresholds.
EPA also solicits comments on whether there would be an additive
effect if individual section 112(d)(4) standards are established for
each acid gas, and if so, how we would simulate that effect. Individual
acid gas standards under section 112(d)(4) would likely be established
using the hazard quotient (HQ) approach, under which we would develop
the ratio of the maximum ambient level to the chronic threshold.
However, this approach would not by itself account for potential
toxicologic interactions. Since all of the acid gases are respiratory
irritants, one way to account for potential toxicologic interactions of
these pollutants would be the use of the hazard index (HI) approach, as
described in EPA's ``Guideline for the Health Risk Assessment of
Chemical Mixtures.'' EPA requests comment on that approach, and on
whether there are any other approaches to address such additive
effects.
Additionally, EPA requests comment on whether we should consider
the affected sources (boilers) by themselves, or whether we should
consider all HAP emissions at the facility when developing a 112(d)(4)
standard. Given that section 112(d)(4) requires an ``ample margin of
safety,'' EPA believes it should consider all reasonable circumstances
in order to ensure such a margin. Since boilers are, in many cases,
located at industrial sites with significant additional sources of HAP
(e.g., petroleum refineries, furniture manufacturers, etc.), EPA
requests comment on how we should consider the potential interactions
of acid gases with other emitted respiratory irritants at these
locations if we were to develop emission limits under section
112(d)(4). Commenters are requested to provide any actual data that is
available to make this type of demonstration. If no data are available,
we request comment on whether such a demonstration could be made using
a bounding calculation.
EPA also requests comment on whether we should consider HAP
emissions from neighboring facilities, and, if so, what the geographic
scope of such consideration should be (e.g., 1 km, 3 km, etc.). We note
that consideration of emissions from nearby facilities is a more
difficult task than consideration of facility-wide emissions, since it
requires information on all potential HAP emissions near all of the
locations with boilers. Therefore, we request comment on whether such
emissions should be considered in setting section 112(d)(4) emissions
standards, and if so, how they should be considered. For example, the
consideration could be limited in geographic scope (e.g., a radius of 3
km), or could be based on ``average'' or ``high-end'' ambient levels of
respiratory irritants seen in recent monitoring data or modeled
estimates, since site-specific data might not be available on all
respiratory irritants.
Further, EPA requests comment on how to appropriately simulate all
reasonable facility/exposure situations (e.g., using worst-case
facility emissions coupled with worst-case population proximity,
average emissions and population, or 90th percentile emissions and
population). Such a simulation could be based on a sequential
examination of the facilities with the highest-emitting boilers on-site
using site-specific data, or it could use screening or bounding
methodologies with high-end or worst-case exposure assumptions to
remove facilities from a more site-specific examination. We request
comment on these and other approaches.
Finally, we considered the fact that setting conventional MACT
standards for HCl as well as PM (as a surrogate for metals including
manganese) would result in significant reductions in emissions of other
pollutants, most notably SO2, non-condensable PM, and other
non-HAP acid gases (e.g., hydrogen bromide) and would likely also
result in additional reductions in emissions of mercury and other HAP
metals (e.g., selenium). The additional reductions of SO2
alone attributable to the proposed MACT standard for HCl are estimated
to be 340,000 tons per year in the third year following promulgation of
the proposed HCl standard. These are substantial reductions with
substantial public health benefits. Although MACT standards may
directly address only HAPs, not criteria pollutants, Congress did
recognize, in the legislative history to section 112(d)(4), that MACT
standards would have the collateral benefit of controlling criteria
pollutants as well and viewed this as an important benefit of the air
toxics program.\20\ Therefore, even where EPA concludes a HAP has a
health threshold, the Agency may consider such benefits as a factor in
determining whether to exercise its discretion under section 112(d)(4).
---------------------------------------------------------------------------
\20\ See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172
---------------------------------------------------------------------------
Given the limitations of the currently available information (i.e.,
the HAP mix where boilers are located, and the cumulative health
impacts from co-located sources), the environmental effects of HCl, and
the significant co-benefits of setting a conventional MACT standard for
HCl, the Administrator is proposing not to exercise her discretion to
use section 112(d)(4).
This conclusion is not contrary to EPA's prior decisions where we
found it appropriate to exercise the discretion to invoke the authority
in section 112(d)(4) for HCl, since the circumstances in this case
differ from previous considerations. Boilers and process heaters differ
from the other source categories for which EPA has exercised its
authority under section 112(d)(4) in ways that affect consideration of
any health threshold for HCl. Commercial and industrial boilers and
process heaters are much more likely to be co-located with multiple
other sources of HAPs than are pulp and paper mills and lime
manufacturing facilities. In addition, boilers and process heaters are
often located at facilities in heavily populated urban areas where many
other sources of HAPs exist. These factors make an analysis of the
health impact of emissions from these sources on the exposed population
significantly more complex than for many other source categories, and
therefore make it more difficult to establish an ample margin of
safety.
Given the particular complexities of this source category (the
location of boilers and process heaters near other significant sources
of HAP emissions
[[Page 32033]]
and the use of HCl as a surrogate for other HAPs), we solicit comment
on all of the conclusions in this section, including the way the agency
has used 112(d)(4) previously, and in particular whether it would be
feasible and appropriate to establish such a standard and, if so, the
methodology by which it could be established.
K. How did we select the compliance requirements?
We are proposing testing, monitoring, notification, and
recordkeeping requirements that are adequate to assure continuous
compliance with the requirement of this proposed rule. These
requirements are described in detail in sections IV.K to IV.N. We
selected these requirements based upon our determination of the
information necessary to ensure that the emission standards and work
practices are being followed and that emission control devices and
equipment are maintained and operated properly. These proposed
requirements ensure compliance with this proposed rule without imposing
a significant additional burden for facilities that must implement
them.
We are proposing that compliance with the emission limits for PM,
HCl, mercury, CO, and D/F be demonstrated by an initial performance
test. To ensure continuous compliance with the proposed PM, HCl, and
mercury emission limits, this proposed rule would require continuous
parameter monitoring of control devices and recordkeeping.
Additionally, this proposed rule would require annual performance tests
to ensure, on an ongoing basis, that the air pollution control device
is operating properly and its performance has not deteriorated. If
initial compliance with the mercury and/or HCl emission limits are
demonstrated by a fuel analysis performance test, this proposed rule
would require fuel analyses monthly, with compliance determined based
on an annual average.
We evaluated the feasibility and cost of applying PM CEMS to
boilers and process heaters. CEMS have been used in Europe to monitor
PM emissions from a variety of industrial sources. Several electric
utility companies in the United States have now installed or are
planning to install PM CEMS. In recognition of the fact that PM CEMS
are commercially available, EPA developed and promulgated Performance
Specifications (PS) for PM CEMS (69 FR 1786, January 12, 2004). PS for
PM CEMS are established under PS-11 in appendix B to 40 CFR part 60 for
evaluating the acceptability of a PM CEM used for determining
compliance with the emission standards on a continuous basis. For PM
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
that requiring PM CEMS for units with heat input capacity greater or
equal to 250 MMBtu/hr and combusting either coal, biomass, or oil is a
reasonable monitoring option. We are requesting comment on the
application of PM CEMS to boilers and process heaters, and the use of
data from such systems for compliance determinations under this
proposed rule.
We reviewed cost information for CO CEMS to make the determination
on whether to require CO CEMS or conducting annual CO testing to
demonstrate continuous compliance with the CO emission limit. In
evaluating the available cost information, we determined that requiring
CO CEMS for units with heat input capacities greater or equal to 100
MMBtu/hr is reasonable. This proposed rule would require units with
heat input capacities less than 100 MMBtu/hr to conduct initial and
annual performance (stack) tests.
The majority of test methods that this proposed rule would require
for the performance stack tests have been required under many other EPA
standards. The only applicable voluntary consensus standard identified
is ASTM Method D6784-02 (Ontario Hydro). The majority of emissions
tests upon which the proposed emission limits are based were conducted
using these test methods.
When a performance test is conducted, we are proposing that
parameter operating limits be determined during the tests. Performance
tests to demonstrate compliance with any applicable emission limits are
either stack tests or fuel analysis or a combination of both.
To ensure continuous compliance with the proposed emission limits
and/or operating limits, this 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 flowrate 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 4-hour block
averages during the compliance test, and demonstrate continuous
compliance by monitoring 12-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.
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 fuel input
option, you must keep records of the calculations supporting your
determination of the chlorine content in the fuel.
If a source elected to demonstrate compliance with the HCl or
mercury limit by using fuel which has a statistically lower pollutant
content than the emission limit, we are proposing that the source's
operating limit is the emission limit of the applicable pollutant.
Under this option, a source is not required to conduct performance
stack tests. If a source demonstrates compliance with the HCl or
mercury limit by using fuel with a statistically higher pollutant
content than the applicable emission limit, but performance tests
demonstrate that the source can meet the emission limits, then the
source's operating limits are the operating limits of the control
device (if used) and the fuel pollutant content of the fuel type/
mixture burned.
This proposed rule would specify the testing methodology and
procedures and the initial and continuous compliance requirements to be
used when complying with the fuel analysis options. Fuel analysis tests
for total chloride, gross calorific value, mercury, sample collection,
and sample
[[Page 32034]]
preparation are included in this proposed rule.
If you elect to comply based on fuel analysis, you will be required
to statistically analyze, using the z-test, the data to determine the
90th percentile confidence level. It is the 90th percentile confidence
level that is required to be used to determine compliance with the
applicable emission limit. The statistical approach is required to
assist in ensuring continuous compliance by statistically accounting
for the inherent variability in the fuel type.
We are proposing that a source be required to recalculate the fuel
pollutant content only if it burns a new fuel type or fuel mixture and
conduct another performance test if the results of recalculating the
fuel pollutant content are higher than the level established during the
initial performance test.
For boilers and process heaters with heat input capacities greater
or equal to 100 MMBtu/hr, we are proposing that CO be continuously
monitored to demonstrate that average CO emissions, on a 30-day rolling
average, are at or below the proposed CO limit.
For boilers and process heaters with heat input capacities between
10 and 100 MMBtu/hr, we are proposing that a performance stack test of
CO emissions be conducted to demonstrate compliance with the CO
emission limit.
L. What alternative compliance provisions are being proposed?
We are proposing that owners and operators of existing affected
sources may demonstrate compliance by emissions averaging for units at
the affected source that are within a single subcategory.
As part of the EPA's general policy of encouraging the use of
flexible compliance approaches where they can be properly monitored and
enforced, we are including emissions averaging in this proposed rule.
Emissions averaging can provide sources the flexibility to comply in
the least costly manner while still maintaining regulation that is
workable and enforceable. Emissions averaging would not be applicable
to new sources and could only be used between boilers and process
heaters in the same subcategory at a particular affected source. Also,
owners or operators of existing sources subject to the Industrial
Boiler NSPS (40 CFR part 60, subparts Db and Dc) would be required to
continue to meet the PM emission standard of that NSPS regardless of
whether or not they are using emissions averaging.
Emissions averaging would allow owners and operators of an affected
source to demonstrate that the source complies with the proposed
emission limits by averaging the emissions from an individual affected
unit that is emitting above the proposed emission limits with other
affected units at the same facility that are emitting below the
proposed emission limits.
This proposed rule includes an emissions averaging compliance
alternative because emissions averaging represents an equivalent, more
flexible, and less costly alternative to controlling certain emission
points to MACT levels. We have concluded that a limited form of
averaging could be implemented that would not lessen the stringency of
the MACT floor limits and would provide flexibility in compliance, cost
and energy savings to owners and operators. We also recognize that we
must ensure that any emissions averaging option can be implemented and
enforced, will be clear to sources, and most importantly, will be no
less stringent than unit by unit implementation of the MACT floor
limits.
EPA has concluded that it is permissible to establish within a
NESHAP a unified compliance regimen that permits averaging within an
affected source across individual affected units subject to the
standard under certain conditions. Averaging across affected units is
permitted only if it can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of a contiguous
major source that is subject to the NESHAP will not be greater under
the averaging mechanism than it could be if each individual affected
unit complied separately with the applicable standard. Under this test,
the practical outcome of averaging is equivalent to compliance with the
MACT floor limits by each discrete unit, and the statutory requirement
that the MACT standard reflect the maximum achievable emissions
reductions is, therefore, fully effectuated.
In past rulemakings, EPA has generally imposed certain limits on
the scope and nature of emissions averaging programs. These limits
include: (1) No averaging between different types of pollutants, (2) no
averaging between sources that are not part of the same affected
source, (3) no averaging between individual sources within a single
major source if the individual sources are not subject to the same
NESHAP, and (4) no averaging between existing sources and new sources.
This proposed rule would fully satisfy each of these criteria.
First, emissions averaging would only be permitted between individual
sources at a single existing affected source, and would only be
permitted between individual sources subject to the boiler and process
heater NESHAP. Further, emissions averaging would not be permitted
between two or more different affected sources. Finally, new sources
could not use emissions averaging. Accordingly, we have concluded that
the averaging of emissions across affected units is consistent with the
CAA. In addition, the proposed rule would require each facility that
intends to utilize emission averaging to submit an emission averaging
plan, which provides additional assurance that the necessary criteria
will be followed. In this emission averaging plan, the facility must
include the identification of (1) all units in the averaging group, (2)
the control technology installed, (3) the process parameter that will
be monitored, (4) the specific control technology or pollution
prevention measure to be used, (5) the test plan for the measurement of
the HAP being averaged, and (6) the operating parameters to be
monitored for each control device. Upon receipt, the regulatory
authority would not be able to approve an emission averaging plan
containing averaging between emissions of different types of pollutants
or between sources in different subcategories.
This proposed rule would also exclude new affected sources from the
emissions averaging provision. EPA believes emissions averaging is not
appropriate for new sources because it is most cost effective to
integrate state-of-the-art controls into equipment design and to
install the technology during construction of new sources. One reason
we allow emissions averaging is to give existing sources flexibility to
achieve compliance at diverse points with varying degrees of add-on
control already in place in the most cost-effective and technically
reasonable fashion. This flexibility is not needed for new sources
because they can be designed and constructed with compliance in mind.
With concern about the equivalency of emissions reductions from
averaging and non-averaging in mind, we are also proposing under the
emission averaging provision caps on the current emissions from each of
the sources in the averaging group. The emissions for each unit in the
averaging group would be capped at the emission level being achieved on
the effective date of the final rule. These caps would ensure that
emissions do not increase above the emission levels that sources
currently are designed, operated, and maintained to achieve. In the
absence of performance tests, in documenting these
[[Page 32035]]
caps, these sources will document the type, design, and operating
specification of control devices installed on the effective date of the
final rule to ensure that existing controls are not removed or operated
less efficiently. By including this provision in this proposed rule, we
would further ensure that emission averaging results in environmental
benefits equivalent to or better than without emission averaging.
In addition, we are proposing that a discount factor of ten percent
would be applied when emissions averaging is used. This discount factor
will further ensure that averaging will be at least as stringent as the
MACT floor limits in the absence of averaging. The EPA is soliciting
comment on use of a discount factor and whether ten percent is the
appropriate discount factor. The emissions averaging provision would
not apply to individual units if the unit shares a common stack with
units in other subcategories, because in that circumstance it is not
possible to distinguish the emissions from each individual unit.
The emissions averaging provisions in this proposed rule are based
in part on the emissions averaging provisions in the Hazardous Organic
NESHAP (HON). The legal basis and rational for the HON emissions
averaging provisions were provided in the preamble to the final HON (59
FR 19425, April 22, 1994).
M. 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 this 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.
N. How did EPA determine the required records and reports for this
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, this 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 would require additional recordkeeping if you chose to comply
with the chlorine or mercury fuel input option. You would need to keep
records of the calculations and supporting information used to develop
the chlorine or mercury fuel input operating limit.
O. How does this proposed rule affect permits?
The CAA requires that sources subject to this 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 this proposed
rule. If you are in the last 2 years of your operating permit, you will
need to incorporate this proposed rule into the next renewal of your
permit.
P. Alternate Standard for Consideration
As discussed above, EPA is proposing a definition of non-hazardous
solid waste under RCRA in a concurrent notice. The proposed CAA section
112(d) standards for boilers and process heaters were developed
considering that proposed definition of solid waste. Therefore, the
emission limits presented in Tables 1 through 5 above are based on
subcategories established considering sources that are ICI boilers and
process heaters under the proposed definition of solid waste under
RCRA. However, the RCRA proposal also identifies and solicits comment
on an alternative approach for defining solid waste, under which more
units would be considered solid waste incineration units than under the
proposed definition. As such, the alternative approach for defining
solid waste under RCRA would result in a different, smaller population
of units being covered by Boiler MACT. Consistent with EPA's
solicitation of comment on an alternative proposed definition of solid
waste under RCRA, we calculated MACT floors using emission rates for
units that would be ICI boilers and process heaters under that
alternative definition, using the same statistical procedures that were
used to calculate the standards that are being proposed. Table 6
reflects that calculation of MACT floor limits for the existing source
subcategories that would be changed by the alternative definition of
solid waste identified in the concurrent RCRA proposal, compared to the
proposed definition of solid waste in that proposal. The MACT floor
limits for the remaining existing source subcategories (Gas 1, Gas 2,
and Liquid) would not change under the alternative definition of solid
waste on which EPA is soliciting comment in the concurrent RCRA
proposal, and are therefore not included in Table 8 because the MACT
floor limits for those subcategories would be the same under the
alternative definition of solid waste as under the proposed definition.
Table 8--Existing MACT Floor Limits Using The ``Alternative Approach'' Under Consideration and Comment in the
Concurrently Proposed RCRA Rule
[Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
Dioxins/
Particulate Hydrogen Carbon monoxide Furans (total
Subcategory matter (PM) chloride (HCl) Mercury (Hg) (CO) (ppm @ 3% TEQ) (ng/dscm)
oxygen) @ 7% O2
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker.......... 0.03 0.02 4.0E-06 40 0.003
Existing--Coal Fluidized Bed... 0.03 0.02 4.0E-06 50 0.008
Existing--Pulverized Coal...... 0.03 0.02 4.0E-06 90 0.004
[[Page 32036]]
Existing--Biomass Stoker....... 0.02 0.03 5.0E-07 180 0.00005
Existing--Biomass Fluidized Bed 0.02 0.03 5.0E-07 10,650 0.1
Existing--Biomass Suspension 0.02 0.03 5.0E-07 1,060 0.3
Burner/Dutch Oven.............
Existing--Biomass Fuel Cells... 0.02 0.03 5.0E-07 460 0.02
----------------------------------------------------------------------------------------------------------------
Comparing the emissions limits in Table 1 (based on the proposed
definition of solid waste) with those in Table 8 (based on the
alternative definition of solid waste), the MACT emission limits for PM
and mercury for the biomass subcategories would be less stringent if
they are based on the alternative definition of solid waste while the
HCl emission limits for the coal and biomass subcategories would be
more stringent if they are based on the alternative definition.
The potential emissions reductions if the MACT floor limits are
calculated based on the alternative definition of solid waste would be
generally lower than the potential emissions reductions for MACT floors
based on the proposed definition of solid waste, because 280 fewer
boilers and process heaters would be subject to the boiler and process
heater MACT standards under the alternative definition. These units
would instead be considered CISWI units under the alternative
definition of solid waste. For example, mercury emissions reduction
would be 7 tons per year based on the alternative definition of solid
waste (compared to 8 tons per year based on the proposed definition)
and HCl emissions reduction would be 5,100 tons per year based on the
alternative definition (compared to 37,000 tons per year based on the
proposed definition). Most (181) of the 280 units that would be
considered CISWI units under the alternative definition of solid waste
proposed under RCRA are biomass-fired boilers or process heaters, with
the others being in the coal and liquid fuel subcategories.
The resulting total national cost impact for existing boilers and
process heaters of the proposed emission limits based on the
alternative definition of solid waste would be 8.0 billion dollars in
capital expenditures and 2.4 billion dollars per year in total annual
costs. This compares to $9.5 billion in capital costs and $2.9 billion
in annual costs under the proposed definition of solid waste in the
RCRA proposed rule. Table 9 of this preamble shows the capital and
annual cost impacts for each subcategory under the alternative
definition of solid waste. Costs include testing and monitoring costs,
but not recordkeeping and reporting costs.
Table 9--Summary of Capital and Annual Costs for Existing Sources Under the Alternative Solid Waste Definition
----------------------------------------------------------------------------------------------------------------
Estimated/ projected Capital Annualized
Source Subcategory number of affected costs cost
units (10\6\$) (10\6\$/yr)
----------------------------------------------------------------------------------------------------------------
Existing Units...................... Coal units............. 525.................... 3,861 1,508
Biomass units.......... 239.................... 1,250 317
Liquid units........... 791.................... 1,352 417
Gas (NG/RG) units...... 11,524................. 75 259
Gas (other) units...... 196.................... 1,476 434
Energy Assessment................... ALL.................... 1,551 facilities....... ........... 24.9
----------------------------------------------------------------------------------------------------------------
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 (2010)'' in the Docket.
We are soliciting public comments on the emission limits listed in
Table 6 of this preamble, consistent with EPA's solicitation of
comments on the alternative definition of solid waste concurrently
proposed under RCRA. As explained above, the MACT floor limits proposed
today are based on the proposed definition of solid waste under RCRA.
However, because EPA is seeking comment on an alternative definition of
solid waste under RCRA, the Agency believes it is necessary to also
solicit comment on what the MACT floor limits would be based on the
universe of sources that would be subject to the boiler and process
heater MACT under that alternative definition.
V. Impacts of the Proposed Rule
A. What are the air impacts?
Table 10 of this preamble illustrates, for each basic fuel
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 selected HAP (i.e., HCl, HF, mercury, metals, and VOC)
will be reduced by 43,000 tons per year for existing units and 15 tons
per year for new units. Emissions of HCl will be reduced by 37,000 tons
per year for existing units and 9 tons per year for new units.
Emissions of mercury will be reduced by 8 tons per year for existing
units and 2.6 pounds per year for new units. Emissions of filterable PM
will be reduced by 50,100 tons per year for existing units and 130 tons
per year for new units. Emissions of non-mercury
[[Page 32037]]
metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt,
lead, manganese, nickel, and selenium) will be reduced by 3,200 tons
per year for existing units and will be reduced by 0.6 ton per year for
new units. In addition, emissions of SO2 are estimated to be
reduced by 340,000 tons per year for existing sources and 500 tons per
year for new sources. Emissions of dioxin/furans, on a total mass
basis, will be reduced by 722 grams per year for existing units and 1
gram per year for new units. 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
(2010)'' in the docket.
Table 10--Summary of Emissions Reductions for Existing and New Sources
[Tons/yr]
----------------------------------------------------------------------------------------------------------------
Non
Source Subcategory HCl PM mercury Mercury VOC
metals \a\
----------------------------------------------------------------------------------------------------------------
Existing Units............... Coal units...... 35,450 17,000 770 7.1 490
Biomass units... 520 22,500 230 0.2 760
Liquid units.... 840 10,400 2,200 0.00005 290
Gas 1 (NG/RG) 9 130 1.2 0.01 72
units.
Gas 2 (other) 220 0 0 0.2 170
units.
New Units.................... Coal units...... 0 0 0 0 0
Biomass units... 0 0 0 0 0
Liquid units.... 9 130 0.6 0.0007 3
Gas 1 units..... 0.01 0.1 0.001 0.000008 0.01
Gas 2 units..... 1 4 0.01 0.0006 1
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, 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
installing wet scrubbers to meet the emission limits for HCl would be
2,400 million gallons per year for existing sources and 200,000 gallons
per year for new sources. In addition to the increased water usage, an
additional 730 million gallons per year of wastewater would be produced
for existing sources and 140,000 gallons per year for new sources. The
annual costs of treating the additional wastewater are $4.0 million for
existing sources and $774 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 81,000 tons per year for existing
sources and 149,800 tons per year for new sources. Solid waste is
generated from flyash and dust captured in PM and mercury controls as
well as from spent carbon that is injected into exhaust streams or used
to filter gas streams. The costs of handling the additional solid waste
generated are $3.4 million for existing sources and $6.3 million 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 (2010)'' in the
Docket.
C. What are the energy impacts?
The EPA expects an increase of approximately 2.995 million kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. Of this amount, 2,944 million kWh would be from existing sources
and 11 million kWh are estimated from new sources. The increase results
from the electricity required to operate control devices, such as wet
scrubbers, electrostatic precipitators, and fabric filters which are
expected to be installed to meet the proposed rule. Additionally, the
EPA expects work practice standards such as boilers tune-ups and
combustion controls will improve the efficiency of boilers, resulting
in an estimated fuel savings of 42 trillion BTU each year from existing
sources and an additional 100,000 million BTU each year. This fuel
savings estimate includes only those fuel savings resulting from gas,
liquid, and coal fuels and it is based on the assumption that the work
practice standards will achieve 1 percent improvement in efficiency.
D. What are the control costs?
To estimate the national cost impacts of the proposed rule for
existing sources, we developed average baseline emission factors for
each fuel type/control device combination based on the emission data
obtained and contained in the Boiler MACT emission database. If a unit
reported emission data, we assigned its unit-specific emission data as
its baseline emissions. For units that did not report emission data, we
assigned the appropriate emission factors to each existing unit in the
inventory database, based on the average emission factors for boilers
with similar fuel, design, and control devices. We then compared each
unit's baseline emission factors to the proposed MACT floor emission
limit to determine if control devices were needed to meet the emission
limits. The control analysis considered fabric filters, carbon bed
adsorbers, and activated carbon injection to be the primary control
devices for mercury control, electrostatic precipitators for units
meeting mercury limits but requiring additional control to meet the PM
limits, wet scrubbers to meet the HCl limits, tune-ups, replacement
burners, and combustion controls for CO and organic HAP control, and
carbon injection for dioxin/furan control. We identified where one
control device could achieve reductions in multiple pollutants, for
example a fabric filter was expected to achieve both PM and mercury
control in order to avoid overestimating the costs. We also included
costs for testing and monitoring requirements contained in the proposed
rule. The resulting total national cost impact of the proposed rule is
9.5 billion dollars in capital expenditures and 3.2 billion dollars per
year in total annual costs. Considering estimated fuel savings
resulting from work practice standards and combustion controls, the
total annualized costs are reduced to 2.9 billion dollars. The total
capital and annual costs include costs for control devices, work
practices, testing and monitoring. Table 11 of this preamble shows the
capital and annual
[[Page 32038]]
cost impacts for each subcategory. Costs include testing and monitoring
costs, but not recordkeeping and reporting costs.
Table 11--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
Annualized
Estimated/ Testing and cost (10\6\$/
projected Capital monitoring yr)
Source Subcategory number of costs annualized (considering
affected (10\6\$) costs fuel
units (10\6\$/yr) savings)
----------------------------------------------------------------------------------------------------------------
Existing Units..................... Coal units........... 578 4,468 62.4 1,619
Biomass units........ 420 2,003 35.5 609
Liquid units......... 826 1,389 27.4 419
Gas (NG/RG) units.... 11,532 75 0 (260)
Gas (other) units.... 199 1,554 10.4 459
Energy Assessment.................. ALL.................. ........... ........... ............ 26
New Units.......................... Coal units........... 0 0 0 0
Biomass units........ 0 0 0 0
Liquid units......... 11 12 0.5 6.1
Gas (NG/RG) units.... 33 0.2 0 0.01
Gas (other) units.... 2 5.5 0.14 1.7
----------------------------------------------------------------------------------------------------------------
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 3rd year is 17 million dollars in capital expenditures and
6.2 million dollars per year in total annual costs, when considering a
1 percent fuel savings.
Potential control device cost savings and increased recordkeeping
and reporting costs associated with the emissions averaging provisions
in the proposed rule are not accounted for in either the capital or
annualized cost estimates.
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 (2010)'' in the Docket.
E. What are the economic impacts?
The economic impact analysis (EIA) that is included in the RIA
shows that the expected prices for industrial sectors could be 0.01
percent higher and domestic production may fall by about 0.01 percent.
Because of higher domestic prices imports may rise by 0.01 percent. In
addition, impacts to affected energy markets show that prices may rise
by 0.04 percent.
Social costs are estimated to also be $2.9 billion in 2008 dollars.
This is estimated to be made up of a $0.8 billion loss in domestic
consumer surplus, a $2.5 billion loss in domestic producer surplus, a
$0.1 billion increase in rest of the world surplus, and a $0.4 billion
in net fuel savings not modeled in a way that can be used to attribute
it to consumers and producers.
EPA performed a screening analysis for impacts on small entities by
comparing compliance costs to sales/revenues (e.g., sales and revenue
tests). EPA's analysis found the tests were typically higher than 3
percent for small entities included in the screening analysis. EPA has
prepared an Initial Regulatory Flexibility Analysis (IRFA) that
discusses alternative regulatory or policy options that minimize the
rule's small entity impacts. It includes key information about key
results from the Small Business Advocacy Review (SBAR) panel.
Precise job effect estimates cannot be estimated with certainty.
Morgenstern et al. (2002) identify three economic mechanisms by which
pollution abatement activities can indirectly influence jobs:
Higher production costs raise market prices, higher prices
reduce consumption, and employment within an industry falls (``demand
effect'');
Pollution abatement activities require additional labor
services to produce the same level of output (``cost effect''); and
Post regulation production technologies may be more or
less labor intensive (i.e., more/less labor is required per dollar of
output) (``factor-shift effect'').
Several empirical studies, including Morgenstern et al. (2002),
suggest the net employment decline is zero or economically small (e.g.,
Cole and Elliot, 2007; Berman and Bui, 2001). However, others show the
question has not been resolved in the literature (Henderson, 1996;
Greenstone, 2002). Morgenstern's paper uses a six-year panel (U.S.
Census data for plant-level prices, inputs (including labor), outputs,
and environmental expenditures) to econometrically estimate the
production technologies and industry-level demand elasticities. Their
identification strategy leverages repeat plant-level observations over
time and uses plant-level and year fixed effects (e.g., plant and time
dummy variables). After estimating their model, Morgenstern show and
compute the change in employment associated with an additional $1
million ($1987) in environmental spending. Their estimates covers four
manufacturing industries (pulp and paper, plastics, petroleum, and
steel) and Morgenstern, et al. present results separately for the cost,
factor shift, and demand effects, as well as the net effect. They also
estimate and report an industry-wide average parameter that combines
the four industry-wide estimates and weighting them by each industry's
share of environmental expenditures.
EPA has most often estimated employment changes associated with
plant closures due to environmental regulation or changes in output for
the regulated industry (EPA, 1999a; EPA, 2000). This analysis goes
beyond what EPA has typically done in two ways. First, because the
multimarket model provides estimates for changes in output for sectors
not directly regulated, we were able to estimate a more comprehensive
``demand effect.'' Secondly, parameters estimated in the Morgenstern
paper were used to estimate all three effects (``demand,'' ``cost,''
and ``factor shift''). This transfer of results from the Morgenstern
study is uncertain but avoids ignoring the ``cost effect'' and the
``factor-shift effect.''
We calculated ``demand effect'' employment changes by assuming that
the number of jobs changes proportionally with multi-market model's
simulated output changes. These results were calculated for all
[[Page 32039]]
sectors in the EPA model that show a change in output. The total job
losses are estimated to be approximately 6,000.
We also calculated a similar ``demand effect'' estimate that used
the Morgenstern paper. To do this, we multiplied the point estimate for
the total demand effect (-3.56 jobs per million ($1987) of
environmental compliance expenditure) by the total environmental
compliance expenditures used in the partial equilibrium model. For
example, the job loss estimate is approximately 7,000 jobs (-3.56 x
$3.5 billion x 0.60).\21\
---------------------------------------------------------------------------
\21\ Since Morgenstern's analysis reports environmental
expenditures in $1987, we make an inflation adjustment the
engineering cost analysis using GDP implicit price deflator (64.76/
108.48) = 0.60).
---------------------------------------------------------------------------
We also present the results of using the Morgenstern paper to
estimate employment ``cost'' and ``factor-shift'' effects (Table 1).
Although using the Morgenstern parameters to estimate these ``cost''
and ``factor-shift'' employment changes is uncertain, it is helpful to
compare the potential job gains from these effects to the job losses
associated with the ``demand'' effect. Table 1 shows that using the
Morgenstern point estimates of parameters to estimate the ``cost'' and
``factor shift'' employment gains may be greater than the employment
losses using either of the two ways of estimating ``demand'' employment
losses. The 95 percent confidence intervals are shown for all of the
estimates based on the Morgenstern parameters. As shown, at the 95%
confidence level, we cannot be certain if net employment changes are
positive or negative.
Although the Morgenstern paper provides additional information
about the potential job effects of environmental protection programs,
there are several qualifications EPA considered as part of the
analysis. First, EPA has used the weighted average parameter estimates
for a narrow set of manufacturing industries (pulp and paper, plastics,
petroleum, and steel). Absent other data and estimates, this approach
seems reasonable and the estimates come from a respected peer-reviewed
source. However, EPA acknowledges the proposed rule covers a broader
set of industries not considered in original empirical study. By
transferring the estimates to other industrial sectors, we make the
assumption that estimates are similar in size. In addition, EPA assumes
also that Morgenstern et al.'s estimates derived from the 1979-1991
still applicable for policy taking place in 2013, almost 20 years
later. Second, the multi-market model only considers near term
employment effects in a U.S. economy where production technologies are
fixed. As a result, the modeling system places more emphasis on the
short term ``demand effect'' whereas the Morgenstern paper emphasizes
other important long term responses. For example, positive job gains
associated with ``factor shift effects'' are more plausible when
production choices become more flexible over time and industries can
substitute labor for other production inputs. Third, the Morgenstern
paper estimates rely on sector demand elasticities that are different
from the demand elasticity parameters used in the multi-market model.
As a result, the demand effects are not directly comparable with the
demand effects estimated by the multi-market model. Fourth, Morgenstern
identifies the industry average as economically and statistically
insignificant effect (i.e., the point estimates are small, measured
imprecisely, and not distinguishable from zero.) EPA acknowledges this
fact and has reported the 95 percent confidence intervals in Table 1.
Fifth, Morgenstern's methodology assumes large plants bear most of the
regulatory costs. By transferring the estimates, EPA assumes a similar
distribution of regulatory costs by plant size and that the regulatory
burden does not disproportionately fall on smaller plants.
Table 12--Employment Changes: 2013
------------------------------------------------------------------------
Estimation method 1,000 Jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets) (demand -5
effect only).............................................
Literature-based estimate (net effect [A + B + C below]).. +3
(-6 to +12)
A. Literature-based estimate: Demand effect........... -7
(-15 to +1)
B. Literature-based estimate: Cost effect............. +5
(+2 to +8)
C. Literature-based estimate: Factor shift effect..... +5
(0 to +10)
------------------------------------------------------------------------
Note: Totals may not add due to independent rounding. 95 percent
confidence intervals for literature-based estimates are shown in
parenthesis.
F. What are the social costs and benefits of this proposed rule?
We estimate the monetized benefits of this proposed regulatory
action to be $17 billion to $41 billion (2008$, 3 percent discount
rate) in the implementation year (2013). The monetized benefits of the
proposed regulatory action at a 7 percent discount rate are $15 billion
to $37 billion (2008$). Using alternate relationships between
PM2.5 and premature mortality supplied by experts, higher
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\22\ A summary of the
monetized benefits estimates at discount rates of 3 percent and 7
percent is in Table 13 of this preamble.
---------------------------------------------------------------------------
\22\ Roman et al., 2008. Expert Judgment Assessment of the
Mortality Impact of Changes in Ambient Fine Particulate Matter in
the U.S. Environ. Sci. Technol., 42, 7, 2268--2274.
[[Page 32040]]
Table 13--Summary of the Monetized Benefits Estimates for the Proposed Boiler MACT for Major Sources in 2013
[Billions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
Estimated
emission
reductions Total monetized benefits Total monetized benefits
(tons per (3% discount rate) (7% discount rate)
year)
----------------------------------------------------------------------------------------------------------------
PM2.5.................................... 29,020 $6.6 to $16................ $6.0 to $15.
PM2.5 Precursors
SO2.................................. 339,996 $10 to $25................. $9.1 to $22.
VOC.................................. 1,786 $0.002 to $0.005........... $0.002 to $0.005.
----------------------------------------------------------------------
Total............................ ........... $17 to $41................. $15 to $37.
----------------------------------------------------------------------------------------------------------------
\1\All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers
may not sum across rows. All fine particles are assumed to have equivalent health effects, but the benefit-per-
ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form
PM2.5. Benefits from reducing hazardous air pollutants (HAPs) are not included.
These benefits estimates represent the total monetized human health
benefits for populations exposed to less PM2.5 in 2013 from
controls installed to reduce air pollutants in order to meet these
standards. These estimates are calculated as the sum of the monetized
value of avoided premature mortality and morbidity associated with
reducing a ton of PM2.5 and PM2.5 precursor
emissions. To estimate human health benefits derived from reducing
PM2.5 and PM2.5 precursor emissions, we utilized
the general approach and methodology on the laid out in Fann et al.
(2009).\23\
---------------------------------------------------------------------------
\23\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The influence
of location, source, and emission type in estimates of the human
health benefits of reducing a ton of air pollution.'' Air Qual Atmos
Health (2009) 2:169-176.
---------------------------------------------------------------------------
To generate the benefit-per-ton estimates, we used a model to
convert emissions of direct PM2.5 and PM2.5
precursors into changes in ambient PM2.5 levels and another
model to estimate the changes in human health associated with that
change in air quality. Finally, the monetized health benefits were
divided by the emission reductions to create the benefit-per-ton
estimates. Even though we assume that all fine particles have
equivalent health effects, the benefit-per-ton estimates vary between
precursors because each ton of precursor reduced has a different
propensity to form PM2.5. For example, SOX has a
lower benefit-per-ton estimate than direct PM2.5 because it
does not form as much PM2.5, thus the exposure would be
lower, and the monetized health benefits would be lower.
For context, it is important to note that the magnitude of the PM
benefits is largely driven by the concentration response function for
premature mortality. Experts have advised EPA to consider a variety of
assumptions, including estimates based both on empirical
(epidemiological) studies and judgments elicited from scientific
experts, to characterize the uncertainty in the relationship between
PM2.5 concentrations and premature mortality. For this
proposed rule we cite two key empirical studies, one based on the
American Cancer Society cohort study \24\ and the extended Six Cities
cohort study.\25\ In the RIA for this proposed rule, which is available
in the docket, we also include benefits estimates derived from expert
judgments and other assumptions.
---------------------------------------------------------------------------
\24\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary
Mortality, and Long-term Exposure to Fine Particulate Air
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
\25\ Laden et al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------
This analysis does not include the type of detailed uncertainty
assessment found in the 2006 PM2.5 NAAQS RIA because we lack
the necessary air quality input and monitoring data to run the benefits
model. However, the 2006 PM2.5 NAAQS benefits analysis \26\
provides an indication of the sensitivity of our results to various
assumptions.
---------------------------------------------------------------------------
\26\ U.S. Environmental Protection Agency, 2006. Final
Regulatory Impact Analysis: PM2.5 NAAQS. Prepared by
Office of Air and Radiation. October. Available on the Internet at
http://www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------
It should be emphasized that the monetized benefits estimates
provided above do not include benefits from several important benefit
categories, including reducing other air pollutants, ecosystem effects,
and visibility impairment. The benefits from reducing carbon monoxide
and hazardous air pollutants have not been monetized in this analysis,
including reducing 330,000 tons of carbon monoxide, 37,000 tons of HCl,
1,000 tons of HF each year, 7.5 tons of mercury, 3,200 tons of other
metals, and 720 grams of dioxins/furans each year. Although we do not
have sufficient information or modeling available to provide monetized
estimates for this rulemaking, we include a qualitative assessment of
the health effects of these air pollutants in the Regulatory Impact
Analysis (RIA) for this proposed rule, which is available in the
docket.
The social costs of this proposed rulemaking are estimated to be
$2.9 billion (2008$) in the implementation year, and the monetized
benefits are $17 billion to $41 billion (2008$, 3 percent discount
rate) for that same year. The benefits at a 7 percent discount rate are
$15 billion to $37 billion (2008$). Thus, net benefits of this
rulemaking are estimated at $14 billion to $38 billion (2008$, 3
percent discount rate) and $12 billion to $34 billion (2008$, 7 percent
discount rate). EPA believes that the benefits of the proposed rule are
likely to exceed the costs even when taking into account the
uncertainties in the cost and benefit estimates. A summary of the
monetized benefits, social costs, and net benefits at discount rates of
3 percent and 7 percent is in Table 14 of this preamble.
[[Page 32041]]
Table 14--Summary of the Monetized Benefits, Social Costs, and Net
Benefits for the Boiler MACT (Major Sources) in 2013
[Millions of 2008$] \1\
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\.... $17 to $41........ $15 to $37.
------------------------------------------------------------------------
Total Social Costs \3\.......... $2.9.............. $2.9.
------------------------------------------------------------------------
Net Benefits.................... $14 to $38........ $12 to $34.
------------------------------------------------------------------------
Non-monetized Benefits.......... 340,000 tons of carbon monoxide.
37,000 tons of HCl.
1,000 tons of HF.
7.5 tons of mercury.
3,200 tons of other metals.
720 grams of dioxins/furans.
Health effects from NO2 and SO2
exposure.
Ecosystem effects.
Visibility impairment.
sProposed Option with Alternate Solid Waste Definition
------------------------------------------------------------------------
Total Monetized Benefits \2\.... $3.1 to $7.7...... $2.8 to $6.9.
------------------------------------------------------------------------
Total Social Costs \3\.......... $2.2.............. $2.2.
------------------------------------------------------------------------
Net Benefits.................... $0.93 to $5.5..... $0.64 to $4.7.
------------------------------------------------------------------------
Non-monetized Benefits.......... 280,000 tons of carbon monoxide.
5,100 tons of HCl.
1,100 tons of HF.
7.1 tons of mercury.
1,600 tons of other metals.
290 grams of dioxins/furans.
Health effects from NO2 and SO2
exposure.
------------------------------------------------------------------------
Ecosystem effects.
------------------------------------------------------------------------
Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
rounded to two significant figures.
\2\ The total monetized benefits reflect the human health benefits
associated with reducing exposure to PM2.5 through reductions of
directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is
important to note that the monetized benefits include many but not all
health effects associated with PM2.5 exposure.
\3\ The methodology used to estimate social costs for one year in the
multimarket model using surplus changes results in the same social
costs for both discount rates.
For more information on the benefits analysis, please refer to the
RIA for this rulemaking, which is available in the docket.
VI. Public Participation and Requests for Comment
We request comment on all aspects of this proposed rule.
In 2004 we published a final rule for boilers and process heaters
located at major source facilities (69 FR 55218, September 13, 2004).
The final rule was vacated and remanded by the Court on June 19, 2007.
We are reissuing our proposal, in response to the Court's decisions, in
this notice. We received many comments on that vacated rule during its
rulemaking and have attempted to take all those comments into account
in this action. This proposal includes a variety of changes from the
vacated rule, mostly centered on emission limits for the various HAP
and subcategories.
During this rulemaking, we conducted outreach to small entities and
convened a Small Business Advocacy Review (SBAR) Panel to obtain advice
and recommendation of representatives of the small entities that
potentially would be subject to the requirements of this proposed rule.
As part of the SBAR Panel process we conducted outreach with
representatives from various small entities that would be affected by
this proposed rule. We met with these small entity representatives
(SERs) to discuss the potential rulemaking approaches and potential
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials
included background on the rulemaking, possible regulatory approaches,
preliminary cost and economic impacts, and possible rulemaking
alternatives. We met with SERs from the industries that will be
impacted directly by this proposed rule to discuss the outreach
materials and receive feedback on the approaches and alternatives
detailed in the outreach packet. The Panel received written comments
from the SERs following the meeting in response to discussions at the
meeting and the questions posed to the SERs by the Agency. The SERs
were specifically asked to provide comment on regulatory alternatives
that could help to minimize the rule's impact on small businesses.
[[Page 32042]]
VII. Relationship of This Proposed Action to Section 112(c)(6) of the
CAA
Section 112(c)(6) of the CAA requires EPA to identify categories of
sources of seven specified pollutants to assure that sources accounting
for not less than 90 percent of the aggregate emissions of each such
pollutant are subject to standards under CAA Section 112(d)(2) or
112(d)(4). EPA has identified ``Industrial Coal Combustion,''
``Industrial Oil Combustion,'' Industrial Wood/Wood Residue
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source
categories that emits two of the seven CAA Section 112(c)(6)
pollutants: POM and mercury. (The POM emitted is composed of 16
polyaromatic hydrocarbons and extractable organic matter.) In the
Federal Register notice Source Category Listing for Section 112(d)(2)
Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838,
17849, Table 2 (1998), EPA identified ``Industrial Coal Combustion,''
``Industrial Oil Combustion,'' ``Industrial Wood/Wood Residue
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source
category ``subject to regulation'' for purposes of CAA Section
112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that
these units emit.
Specifically, as byproducts of combustion, the formation of POM is
effectively reduced by the combustion and post-combustion practices
required to comply with the CAA Section 112 standards. Any POM that do
form during combustion are further controlled by the various post-
combustion controls. The add-on PM control systems (either fabric
filter or wet scrubber) and activated carbon injection in the fabric
filter-based systems further reduce emissions of these organic
pollutants, and also reduce mercury emissions, as is evidenced by
performance data. Specifically, the emission tests obtained at
currently operating units show that the proposed MACT regulations will
reduce mercury emissions by about 86 percent. It is, therefore,
reasonable to conclude that POM emissions will be substantially
controlled. Thus, while this proposed rule does not identify specific
numerical emission limits for POM, emissions of POM are, for the
reasons noted below, nonetheless ``subject to regulation'' for purposes
of Section 112(c)(6) of the CAA.
In lieu of establishing numerical emissions limits for pollutants
such as POM, we regulate surrogate substances. While we have not
identified specific numerical limits for POM, we believe CO serves as
an effective surrogate for this HAP, because CO, like POM, is formed as
a byproduct of combustion.
Consequently, we have concluded that the emissions limits for CO
function as a surrogate for control of POM, such that it is not
necessary to propose numerical emissions limits for POM with respect to
boilers and process heaters to satisfy CAA Section 112(c)(6).
To further address POM and mercury emissions, this proposed rule
also includes an energy assessment provision that encourages
modifications to the facility to reduce energy demand that lead to
these emissions.
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is an ``economically significant regulatory action'' because it
is likely to 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.
Accordingly, EPA submitted this action to the Office of Management
and Budget (OMB) for review under EO 12866 and any changes in response
to OMB recommendations have been documented in the docket for this
action. For more information on the costs and benefits for this rule,
please refer to Table 14 of this preamble.
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.
This 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. Thus, Executive Order 13132 does
not apply to this 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 solicited comment
on this 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.'' This proposed rule does not have
tribal implications, as specified in Executive Order 13175 (65 FR
67249, November 9, 2000). It will not have substantial direct effects
on tribal governments, on the relationship between the Federal
government and Indian tribes, or on the distribution of power and
responsibilities between the Federal government and Indian tribes, as
specified in Executive Order 13175. This proposed rule imposes
requirements on owners and operators of specified area sources and not
tribal governments. We do not know of any industrial, commercial, or
institutional boilers owned or operated by Indian tribal governments.
However, if there are any, the effect of this 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 this proposed rule. EPA specifically
solicits additional comment on this 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 EPA has 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 this planned rule on children, and explain why this
planned regulation is preferable to other potentially effective
[[Page 32043]]
and reasonably feasible alternatives considered by the Agency.
This proposed rule is not subject to Executive Order 13045 because
the Agency does not believe the environmental health risks or safety
risks addressed by this action present a disproportionate risk to
children. The reason for this determination is that this proposed rule
is based solely on technology performance.
The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to this
proposed rule.
E. Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows us to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
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 this 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 this 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 $2.9 billion (2008 dollars).
It is estimated that 3 years after implementation of the proposed
rule, HAPs would be reduced by thousands of tons, including reductions
in hydrochloric acid, hydrogen fluoride, metallic HAP including
mercury, and several other organic HAP from boilers and process
heaters. Studies have determined a relationship between exposure to
these HAP and the onset of cancer, however, the Agency is unable to
provide a monetized estimate of the HAP benefits at this time. In
addition, there are significant reductions in PM2.5 and in
SO2 that would occur, including 29 thousand tons of
PM2.5 and 340 thousand tons of SO2. These
reductions occur within 3 years after the implementation of the
proposed regulation and are expected to continue throughout the life of
the affected sources. The major health effect associated with reducing
PM2.5 and PM2.5 precursors (such as
SO2) is a reduction in premature mortality. Other health
effects associated with PM2.5 emission reductions include
avoiding cases of chronic bronchitis, heart attacks, 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 PM2.5 and SO2 emissions reductions. For
SO2 and PM2.5, 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 visibility effects). Our estimates of the monetized benefits in
2013 associated with the implementation of the proposed alternative is
a range from $17 billion (2008 dollars) to $41 billion (2008 dollars)
when using a 3 percent discount rate (or from $15 billion (2008
dollars) to $37 billion (2008 dollars) when using a 7 percent discount
rate). This estimate, at a 3 percent discount rate, is about $14
billion (2008 dollars) to $38 billion (2008 dollars) higher than the
estimated social costs shown earlier in this section. The general
approach used 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
[[Page 32044]]
(e.g., urban, rural), or particular industry segments. See the results
of the ``Economic Impact Analysis of the Proposed Industrial Boilers
and Process Heaters NESHAP,'' 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 a small impact on
prices and output, 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 small.
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.
Because an initial screening analysis for impact on small entities
indicated a likely significant impact for substantial numbers, EPA
convened a SBAR Panel to obtain advice and recommendation of
representatives of the small entities that potentially would be subject
to the requirements of this rule.
(a) Panel Process and Panel Outreach
As required by section 609(b) of the RFA, as amended by SBREFA, EPA
also has conducted outreach to small entities and on January 22, 2009
EPA's Small Business Advocacy Chairperson convened a Panel under
section 609(b) of the RFA. In addition to the Chair, the Panel
consisted of the Director of the Sector Policies and Programs Division
within EPA's Office of Air and Radiation, the Chief Counsel for
Advocacy of the Small Business Administration, and the Administrator of
the Office of Information and Regulatory Affairs within the Office of
Management and Budget.
As part of the SBAR Panel process we conducted outreach with
representatives from 14 various small entities that would be affected
by this rule. The small entity representatives (SERs) included
associations representing schools, churches, hotels/motels, wood
product facilities and manufacturers of home furnishings. We met with
these SERs to discuss the potential rulemaking approaches and potential
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials
included background on the rulemaking, possible regulatory approaches,
preliminary cost and economic impacts, and possible rulemaking
alternatives. The Panel met with SERs from the industries that will be
impacted directly by this rule on February 10, 2009 to discuss the
outreach materials and receive feedback on the approaches and
alternatives detailed in the outreach packet. (EPA also met with SERs
on November 13, 2008 for an initial outreach meeting.) The Panel
received written comments from the SERs following the meeting in
response to discussions at the meeting and the questions posed to the
SERs by the Agency. The SERs were specifically asked to provide comment
on regulatory alternatives that could help to minimize the rule's
impact on small businesses.
(1) Panel Recommendations for Small Business Flexibilities
The Panel recommended that EPA consider and seek comment on a wide
range of regulatory alternatives to mitigate the impacts of the
rulemaking on small businesses, including those flexibility options
described below. The following section summarizes the SBAR Panel
recommendations. EPA has proposed provisions consistent with four of
the Panel's recommendations.
Consistent with the RFA/SBREFA requirements, the Panel evaluated
the assembled materials and small-entity comments on issues related to
elements of the IRFA. A copy of the Final Panel Report (including all
comments received from SERs in response to the Panel's outreach meeting
as well as summaries of both outreach meetings that were held with the
SERs is included in the docket for this proposed rule. A summary of the
Panel
[[Page 32045]]
recommendations is detailed below. As noted above, this proposal
includes proposed provisions for all but one of the Panel
recommendations.
(a) Work Practice Standards
The panel recommended that EPA consider requiring annual tune-ups,
including standardized criteria outlining proper tune-up methods
targeted at smaller boiler operators. The panel further recommended
that EPA take comment on the efficacy of energy assessments/audits at
improving combustion efficiency and the cost of performing the
assessments, especially to smaller boiler operators.
A work practice standard, instead of MACT emission limits, may be
proposed if it can be justified under section 112(h) of the CAA, that
is, it is impracticable to enforce the emission standards due to
technical or economic limitations. Work practice standards could reduce
fuel use and improve combustion efficiency which would result in
reduced emissions.
In general, SERs commented that a regulatory approach to improve
combustion efficiency, such as work practice standards, would have
positive impacts with respect to the environment and energy use and
save on compliance costs. The SERs were concerned with work practice
standards that would require energy assessments and implementation of
assessment findings. The basis of these concerns rested upon the
uncertainty that there is no guarantee that there are available funds
to implement a particular assessment's findings.
(b) Subcategorization
The Panel recommended that EPA allow subcategorizations suggested
by the SERs, unless EPA finds that a subcategorization is inconsistent
with the Clean Air Act.
SERs commented that subcategorization is a key concept that could
ensure that like boilers are compared with similar boilers so that MACT
floors are more reasonable and could be achieved by all units within a
subcategory using appropriate emission reduction strategies. SERs
commented that EPA should subcategorize based on fuel type, boiler
type, duty cycle, and location.
(c) Health Based Compliance Alternatives (HBCA)
The Panel recommended that EPA adopt the HBCA as a regulatory
flexibility option for the Boiler MACT rulemaking. The panel
recognized, however, that EPA has concerns about its legal authority to
provide an HBCA under the Clean Air Act, and EPA may ultimately
determine that this flexibility is inconsistent with the Clean Air Act.
SERs commented that adopting an HBCA would perhaps be the most
important step EPA could take to mitigate the serious financial harm
the Boiler MACT would otherwise inflict on small entities using solid
fuels nationwide and, therefore, HBCA should be a critical component of
any future rule to lessen impact on small entities.
(d) Emissions Averaging
The Panel recommended that EPA consider a provision for emission
averaging and long averaging times for the proposed emission limits.
SERs commented that a measure EPA should consider to lessen the
regulatory burden of complying with Boiler MACT is to allow emissions
averaging at sources with multiple regulated units. SERs commented that
another approach that can aide small entity compliance is to set longer
averaging times (i.e., 30-days or more) rather than looking at a mere
3-run (hour) average for performance. Given the inherent variability in
boiler performance, an annual or quarterly averaging period for all HAP
would prevent a single spike in emissions from throwing a unit into
non-compliance.
(e) Compliance Costs
The Panel recommended that EPA carefully weigh the potential burden
of compliance requirements and consider for small entities options such
as, emission averaging within facility, reduced monitoring/testing
requirements, or allowing more time for compliance.
SERs noted that recordkeeping activities, as written in the vacated
boiler MACT, would be especially challenging for small entities that do
not have a dedicated environmental affairs department.
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.
2028.05).
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 $87.6 million. This includes 208,832
labor hours per year at a total labor cost of $19.8 million per year,
and total non-labor capital costs of $67.8 million per year. This
estimate includes initial and annual performance test, conducting and
documenting an energy assessment, conducting and documenting a tune-up,
semiannual excess emission reports, maintenance inspections, developing
a monitoring plan, notifications, and recordkeeping. Monitoring,
testing, tune-up and energy assessment costs and cost 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 93,648 hours per year at a
total labor cost of $4.9 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
[[Page 32046]]
numbers for our regulations are listed in 40 CFR part 9 and 48 CFR
chapter 15.
To comment on EPA's need for this information, the accuracy of the
provided burden estimates, and any suggested methods for minimizing
respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this action, which
includes this ICR, under Docket ID number EPA-HQ-OAR-2002-0058. Submit
any comments related to the ICR to EPA and OMB. See ADDRESSES section
at the beginning of this preamble for where to submit comments to EPA.
Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street, NW.,
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after June 4, 2010, a comment to OMB is best assured of having its full
effect if OMB receives it by July 6, 2010. The final rule will respond
to any OMB or public comments on the information collection
requirements contained in this proposal.
H. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to the 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. 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 Flowrate 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
[[Page 32047]]
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 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.
[[Page 32048]]
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.
We estimate a 0.14% price increase for the energy sector and a
0.07% percentage change in production. We estimate a 0.18% increase in
energy imports. 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.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice (EJ). Its main
provision directs Federal agencies, to the greatest extent practicable
and permitted by law, to make environmental justice part of their
mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental
effects of their programs, policies, and activities on minority
populations, low-income, and Tribal populations in the United States.
This proposed action establishes national emission standards for
new and existing industrial, commercial, institutional boilers and
process heaters that combust non-waste materials (i.e. natural gas,
process gas, fuel oil, biomass, and coal) and that are located at a
major source. The EPA estimates that there are approximately 13,555
units located at 1,608 facilities covered by this rule.
The proposed rule will reduce emissions of all the listed HAP that
come from boilers and process heaters. This includes metals (mercury,
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and
selenium), organics (POM, acetaldehyde, acrolein, benzene, dioxins,
ethylene dichloride, formaldehyde, and PCB), hydrochloric acid, and
hydrofluoric acid. Adverse health effects from these pollutants include
cancer, irritation of the lungs, skin, and mucus membranes; effects on
the central nervous system, damage to the kidneys, and other acute
health disorders. The rule will also result in substantial reductions
of criteria pollutants such as carbon monoxide (CO), nitrogen oxides
(NOX), particulate matter (PM), and sulfur dioxide
(SO2). Sulfur dioxide and NO2 are precursors for
the formation of PM2.5 and ozone. Reducing these emissions
will reduce ozone and PM2.5 formation and associated health
effects, such as adult premature mortality, chronic and acute
bronchitis, asthma, and other respiratory and cardiovascular diseases.
(Please refer to the RIA contained in the docket for this rulemaking.)
Pursuant to E.O. 12898 EPA has undertaken to determine the
aggregate demographic makeup of the communities near affected sources.
This analysis used ``proximity-to-a-source'' to identify the
populations considered to be living near affected sources, such that
they have notable exposures to current emissions from these sources. In
this approach EPA reviewed the distributions of different socio-
demographic groups in the locations of the expected emission reductions
from this rule. The review identified those census blocks within a
circular distance of 3 miles of affected sources and determined the
demographic and socio-economic composition (e.g. race, income,
education, etc) of these census blocks. The radius of 3 miles (or
approximately 5 kilometers) has been used in other demographic analyses
focused on areas around potential sources.27 28 29 30 In
addition, air modeling experience has shown that beyond 3 miles the
influence of an individual source of emissions can generally be
considered to be small, both in absolute terms and relative to the
influence of other sources (assuming there are other sources in the
area, as is typical in urban areas).
---------------------------------------------------------------------------
\27\ U.S. GAO (Government Accountability Office). Demographics
of People Living Near Waste Facilities. Washington DC: Government
Printing Office; 1995.
\28\ Mohai P, Saha R. ``Reassessing Racial and Socio-economic
Disparities in Environmental Justice Research''. Demography.
2006;43(2): 383-399.
\29\ Mennis J. ``Using Geographic Information Systems to Create
and Analyze Statistical Surfaces of Populations and Risk for
Environmental Justice Analysis''. Social Science Quarterly,
2002;83(1):281-297.
\30\ Bullard RD, Mohai P, Wright B, Saha R, et al. Toxic Waste
and Race at Twenty 1987-2007. United Church of Christ. March, 2007.
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EPA's demographic analysis showed that major source boilers are
located in areas where minorities' share of the population living
within a three-mile buffer is higher than the national average. For
these same areas, the percent of the population below the poverty line
is also higher than the national average.\31\ Based on the fact that
the rule does not allow emission increases, the EPA has determined that
the proposed rule will not have disproportionately high and adverse
human health or environmental effects on minority, low-income, or
Tribal populations. However, to the extent that any minority, low
income, or Tribal subpopulation is disproportionately impacted by the
current emissions as a result of the proximity of their homes to these
sources, that subpopulation also
[[Page 32049]]
stands to see increased environmental and health benefit from the
emissions reductions called for by this rule.
---------------------------------------------------------------------------
\31\ The results of the demographic analysis are presented in
``Review of Environmental Justice Impacts'', April 2010, a copy of
which is available in the docket.
---------------------------------------------------------------------------
EPA defines ``Environmental Justice'' to include meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and polices. To promote
meaningful involvement, EPA has developed a communication and outreach
strategy to ensure that interested communities have access to this
proposed rule, are aware of its content, and have an opportunity to
comment during the comment period. During the comment period, EPA will
publicize the rulemaking via EJ newsletters, Tribal newsletters, EJ
listservs, and the Internet, including the Office of Policy, Economics,
and Innovation's (OPEI) Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/). EPA will also provide general
rulemaking fact sheets (e.g., why is this important for my community)
for EJ community groups and conduct conference calls with interested
communities. In addition, state and federal permitting requirements
will provide state and local governments and members of affected
communities the opportunity to provide comments on the permit
conditions associated with permitting the sources affected by this
rulemaking.
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.
Dated: April 29, 2010.
Lisa P. Jackson,
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 revising subpart DDDDD to read as follows:
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Major Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters
Sec.
What This Subpart Covers
63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this subpart?
63.7491 Are any boilers or process heaters not subject to this
subpart?
63.7495 When do I have to comply with this subpart?
Emission Limitations and Work Practice Standards
63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limitations, work practice standards, and
operating limits must I meet?
General Compliance Requirements
63.7505 What are my general requirements for complying with this
subpart?
Testing, Fuel Analyses, and Initial Compliance Requirements
63.7510 What are my initial compliance requirements and by what date
must I conduct them?
63.7515 When must I conduct subsequent performance tests or fuel
analyses?
63.7520 What stack tests and procedures must I use for the
performance tests?
63.7521 What fuel analyses and procedures must I use for the
performance tests?
63.7522 Can I use emission averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission
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?
63.7541 How do I demonstrate continuous compliance under the
emission averaging provision?
Notifications, Reports, and Records
63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?
Other Requirements and Information
63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?
Tables to Subpart DDDDD of Part 63
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or
Reconstructed Boilers and Process Heaters
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing
Boilers and Process Heaters (Units with heat input capacity of 10
million Btu per hour or greater)
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters
Table 5 to Subpart DDDDD of Part 63--Performance Testing
Requirements
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous
Compliance
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD
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 (HAP) emitted from
industrial, commercial, and institutional boilers and process heaters
located at major sources of HAP. 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 as
defined in Sec. 63.7575 that is located at, or is part of, a major
source of HAP as defined in Sec. 63.2 or Sec. 63.761 (40 CFR part 63,
subpart HH, National Emission Standards for Hazardous Air Pollutants
from Oil and Natural Gas Production Facilities), except as specified in
Sec. 63.7491.
Sec. 63.7490 What is the affected source of this subpart?
(a) This subpart applies to new, reconstructed, and existing
affected sources as described in paragraphs (a)(1) and (2) of this
section.
(1) The affected source of this subpart is the collection of all
existing industrial, commercial, and institutional boilers and process
heaters within a subcategory located at a major source as defined in
Sec. 63.7575.
(2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler or
process heater located at a major source as defined in Sec. 63.7575.
(b) A boiler or process heater is new if you commence construction
of the boiler or process heater after June 4, 2010, and you meet the
applicability
[[Page 32050]]
criteria at the time you commence construction.
(c) A boiler or process heater is reconstructed if you meet the
reconstruction criteria as defined in Sec. 63.2, you commence
reconstruction after June 4, 2010, and you meet the applicability
criteria at the time you commence reconstruction.
(d) A boiler or process heater is existing if it is not new or
reconstructed.
Sec. 63.7491 Are any boilers or process heaters not subject to this
subpart?
The types of boilers and process heaters listed in paragraphs (a)
through (j) of this section are not subject to this subpart.
(a) An electric utility steam generating unit.
(b) A recovery boiler or furnace covered by 40 CFR part 63, subpart
MM.
(c) A boiler or process heater that is used specifically for
research and development. This does not include units that provide heat
or steam to a process at a research and development facility.
(d) A hot water heater as defined in this subpart.
(e) A refining kettle covered by 40 CFR part 63, subpart X.
(f) An ethylene cracking furnace covered by 40 CFR part 63, subpart
YY.
(g) Blast furnace stoves as described in the EPA document, entitled
``National Emission Standards for Hazardous Air Pollutants (NESHAP) for
Integrated Iron and Steel Plants--Background Information for Proposed
Standards,'' (EPA-453/R-01-005).
(h) Any boiler or process heater specifically listed as an affected
source in another standard(s) under 40 CFR part 63.
(i) Temporary boilers as defined in this subpart.
(j) Blast furnace gas fuel-fired boilers and process heaters as
defined in this subpart.
Sec. 63.7495 When do I have to comply with this subpart?
(a) If you have a new or reconstructed boiler or process heater,
you must comply with this subpart by [DATE THE FINAL RULE IS PUBLISHED
IN THE FEDERAL REGISTER] or upon startup of your boiler or process
heater, whichever is later.
(b) If you have an existing boiler or process heater, you must
comply with this subpart no later than [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 source must be in compliance with this subpart upon startup.
(2) Any existing boiler or process heater at the existing source
must be in compliance with this subpart within 3 years after the source
becomes a major source.
(d) You must meet the notification requirements in Sec. 63.7545
according to the schedule in Sec. 63.7545 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.
Emission Limitations and Work Practice Standards
Sec. 63.7499 What are the subcategories of boilers and process
heaters?
(a) The subcategories of boilers and process heaters are:
(1) Pulverized coal units,
(2) Stokers designed to burn coal,
(3) Fluidized bed units designed to burn coal,
(4) Stokers designed to burn biomass,
(5) Fluidized bed units designed to burn biomass,
(6) Suspension burners/Dutch Ovens designed to burn biomass,
(7) Fuel Cells designed to burn biomass,
(8) Units designed to burn liquid fuel,
(9) Units designed to burn natural gas/refinery gas,
(10) Units designed to burn other gases, and
(11) Metal process furnaces.
(b) Each subcategory is defined in Sec. 63.7575.
Sec. 63.7500 What emission limits, work practice standards, and
operating limits must I meet?
(a) You must meet the requirements in paragraphs (a)(1) and (2) of
this section. You must meet these requirements at all times.
(1) You must meet each emission limit and work practice standard in
Table 1 through 3 to this subpart that applies to your boiler or
process heater, for each boiler or process heater at your source,
except as provided under Sec. 63.7522.
(2) You must meet each operating limit in Table 4 to this subpart
that applies to your boiler or process heater. If you use a control
device or combination of control devices not covered in Table 4 to this
subpart, or you wish to establish and monitor an alternative operating
limit and alternative monitoring parameters, you must apply to the
United States Environmental Protection Agency (EPA) Administrator for
approval of alternative monitoring under Sec. 63.8(f).
(b) As provided in Sec. 63.6(g), EPA may approve use of an
alternative to the work practice standards in this section.
General Compliance Requirements
Sec. 63.7505 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limits and
operating limits in this subpart. These limits apply to you at all
times.
(b) At all times you must operate and maintain any affected source,
including associated air pollution control equipment and monitoring
equipment, in a manner consistent with safety and good air pollution
control practices for minimizing emissions. The general duty to
minimize emissions does not require you to make any further efforts to
reduce emissions if levels required by this standard have been
achieved. Determination of whether such operation and maintenance
procedures are being used will be based on information available to the
Administrator which may include, but is not limited to, monitoring
results, review of operation and maintenance procedures, review of
operation and maintenance records, and inspection of the source.
(c) You can demonstrate compliance with the applicable emission
limit for HCl or mercury using fuel analysis if the emission rate
calculated according to Sec. 63.7530(d) is less than the applicable
emission limit. Otherwise, you must demonstrate compliance for HCl or
mercury using performance stack testing. You must demonstrate
compliance with all other applicable limits using performance stack
testing, or the continuous monitoring system (CMS) where applicable.
(d) If you demonstrate compliance with any applicable emission
limit through performance stack testing, you must develop a site-
specific monitoring plan according to the requirements in paragraphs
(d)(1) through (4) of this section. This requirement also applies to
you if you petition the EPA Administrator for alternative monitoring
parameters under Sec. 63.8(f).
(1) For each CMS required in this section, you must develop, and
submit to the permitting authority for approval upon request, a site-
specific monitoring plan that addresses paragraphs (d)(1)(i) through
(iii) of this section. You must submit this site-specific monitoring
plan, if requested, at least 60 days before
[[Page 32051]]
your initial performance evaluation of your CMS.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations).
(2) In your site-specific monitoring plan, you must also address
paragraphs (d)(2)(i) through (iii) of this section.
(i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 63.8(c)(1)(i) and (ii), (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.
Testing, Fuel Analyses, and Initial Compliance Requirements
Sec. 63.7510 What are my initial compliance requirements and by what
date must I conduct them?
(a) For affected sources that elect to demonstrate compliance with
any of the emission limits of this subpart through performance stack
testing, your initial compliance requirements include conducting
performance stack tests according to Sec. 63.7520 and Table 5 to this
subpart, conducting a fuel analysis for each type of fuel burned in
your boiler or process heater according to Sec. 63.7521 and Table 6 to
this subpart, establishing operating limits according to Sec. 63.7530
and Table 7 to this subpart, and conducting CMS performance evaluations
according to Sec. 63.7525. For affected sources that burn a single
type of fuel, you are exempted from the initial compliance requirements
of conducting a fuel analysis for each type of fuel burned in your
boiler or process heater according to Sec. 63.7521 and Table 6 to this
subpart.
(b) For affected sources that elect to demonstrate compliance with
the emission limits for HCl or mercury through fuel analysis, your
initial compliance requirement is to conduct a fuel analysis for each
type of fuel burned in your boiler or process heater according to Sec.
63.7521 and Table 6 to this subpart and establish operating limits
according to Sec. 63.7530 and Table 8 to this subpart.
(c) If your boiler or process heater has a heat input capacity less
than 100 MMBtu per hour, your initial compliance demonstration for CO
is conducting a performance stack test for CO according to Table 5 to
this subpart. If your boiler or process heater has a heat input
capacity of 100 MMBtu per hour or greater, your initial compliance
demonstration for CO is conducting a performance evaluation of your
continuous emission monitoring system for CO according to Sec.
63.7525(a).
(d) If your boiler or process heater has a heat input capacity of
250 MMBtu per hour or greater and combusts coal, biomass, or residual
oil, your initial compliance demonstration for PM is conducting a
performance evaluation of your continuous emission monitoring system
for PM according to Sec. 63.7525(b).
(e) For existing affected sources, you must demonstrate initial
compliance no later than 180 days after the compliance date that is
specified for your source in Sec. 63.7495 and according to the
applicable provisions in Sec. 63.7(a)(2) as cited in Table 10 to this
subpart.
(f) If your new or reconstructed affected source commenced
construction or reconstruction between June 4, 2010 and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
demonstrate initial compliance with either the proposed emission limits
or the promulgated emission limits no later than 180 days after [DATE
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or
within 180 days after startup of the source, whichever is later,
according to Sec. 63.7(a)(2)(ix).
(g) If your new or reconstructed affected source commenced
construction or reconstruction between June 4, 2010, and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], and you
chose to comply with the proposed emission limits when demonstrating
initial compliance, you must conduct a second compliance demonstration
for the promulgated emission limits within 3 years after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within
3 years after startup of the affected source, whichever is later.
(h) If your new or reconstructed affected source commences
construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial
compliance with the promulgated emission limits no later than 180 days
after startup of the source.
Sec. 63.7515 When must I conduct subsequent performance tests or fuel
analyses?
(a) You must conduct all applicable performance tests according to
Sec. 63.7520 on an annual basis, unless you follow the requirements
listed in paragraphs (b) through (e) of this section. Annual
performance tests must be completed between 10 and 12 months after the
previous performance test, unless you follow the requirements listed in
paragraphs (b) through (e) of this section.
(b) You can conduct performance stack tests less often for a given
pollutant if your performance stack tests for the pollutant for at
least 3 consecutive years show that your emissions are at or below 75
percent of the emission limit, and if there are no changes in the
operation of the affected source or air pollution control equipment
that could increase emissions. In this case, you do not have to conduct
a performance test for that pollutant for the next 2 years. You must
conduct a performance test during the third year and no more than 36
months after the previous performance test. This reduced testing option
does not apply to performance stack tests for dioxin/furan. If you
elect to demonstrate compliance using emission averaging under Sec.
63.7522, you must continue to conduct performance stack tests annually.
(c) If your boiler or process heater continues to meet the emission
limit for the pollutant, you may choose to conduct performance stack
tests for the pollutant every third year if your emissions are at or
below 75 percent of the emission limit, and if there are no changes in
the operation of the affected source or air pollution control equipment
that could increase emissions, but each such performance test must be
conducted no more than 36 months after the previous performance test.
This reduced testing option does not apply to performance stack tests
for dioxin/furan. If you elect to demonstrate compliance using emission
averaging under Sec. 63.7522, you must continue to conduct performance
stack tests annually.
[[Page 32052]]
(d) If a performance test shows emissions exceeded 75 percent of
the emission limit, you must conduct annual performance tests for that
pollutant until all performance tests over a consecutive 3-year period
show compliance.
(e) If you are required to meet an applicable work practice
standard, you must conduct annual performance tune-ups according to
Sec. 63.7520. Each annual tune-up must be conducted between 10 and 12
months after the previous tune-up.
(f) If you demonstrate compliance with the mercury or HCl based on
fuel analysis, you must conduct a monthly fuel analysis according to
Sec. 63.7521 for each type of fuel burned. If you burn a new type of
fuel, you must conduct a fuel analysis before burning the new type of
fuel in your boiler or process heater. You must still meet all
applicable continuous compliance requirements in Sec. 63.7540.
(g) You must report the results of performance tests (stack test
and fuel analyses) within 60 days after the completion of the
performance tests. This report must also verify that the operating
limits for your affected source have not changed or provide
documentation of revised operating parameters established according to
Sec. 63.7530 and Table 7 to this subpart, as applicable. The reports
for all subsequent performance tests must include all applicable
information required in Sec. 63.7550.
Sec. 63.7520 What stack tests and procedures must I use for the
performance tests?
(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 according to the
requirements in Table 5 to this subpart.
(c) You must conduct each performance stack test under the specific
conditions listed in Tables 5 and 7 to this subpart. You must conduct
performance stack tests at the maximum normal operating load while
burning the type of fuel or mixture of fuels that has the highest
content of chlorine and mercury, and you must demonstrate initial
compliance and establish your operating limits based on these tests.
These requirements could result in the need to conduct more than one
performance test.
(d) 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 4 hours.
(e) To determine compliance with the emission limits, you must use
the F[dash]Factor methodology and equations in sections 12.2 and 12.3
of EPA Method 19 of appendix A to part 60 of this chapter to convert
the measured particulate matter concentrations, the measured HCl
concentrations, and the measured mercury concentrations that result
from the initial performance test to pounds per million Btu heat input
emission rates using F-factors.
Sec. 63.7521 What fuel analyses and procedures must I use for the
performance tests?
(a) You must conduct performance fuel analysis tests according to
the procedures in paragraphs (b) through (e) of this section and Table
6 to this subpart, as applicable.
(b) You must develop and submit a site-specific fuel analysis plan
to the EPA Administrator for review and approval according to the
following procedures and requirements in paragraphs (b)(1) and (2) of
this section.
(1) You must submit the fuel analysis plan no later than 60 days
before the date that you intend to demonstrate compliance.
(2) You must include the information contained in paragraphs
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all fuel types anticipated to be burned
in each boiler or process heater.
(ii) For each fuel type, the notification of whether you or a fuel
supplier will be conducting the fuel analysis.
(iii) For each fuel type, a detailed description of the sample
location and specific procedures to be used for collecting and
preparing the composite samples if your procedures are different from
paragraph (c) or (d) of this section. Samples should be collected at a
location that most accurately represents the fuel type, where possible,
at a point prior to mixing with other dissimilar fuel types.
(iv) For each fuel type, the analytical methods from Table 6, with
the expected minimum detection levels, to be used for the measurement
of chlorine or mercury.
(v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that you are
proposing to use. Methods in Table 6 shall be used until the requested
alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
(c) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in paragraph (c)(1) or (2)
of this section.
(1) If sampling from a belt (or screw) feeder, collect fuel samples
according to paragraphs (c)(1)(i) and (ii) of this section.
(i) Stop the belt and withdraw a 6-inch wide sample from the full
cross-section of the stopped belt to obtain a minimum two pounds of
sample. You must collect all the material (fines and coarse) in the
full cross-section. You must transfer the sample to a clean plastic
bag.
(ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal 1-hour intervals during the
testing period.
(2) If sampling from a fuel pile or truck, you must collect fuel
samples according to paragraphs (c)(2)(i) through (iii) of this
section.
(i) For each composite sample, you must select a minimum of five
sampling locations uniformly spaced over the surface of the pile.
(ii) At each sampling site, you must dig into the pile to a depth
of 18 inches. You must insert a clean flat square shovel into the hole
and withdraw a sample, making sure that large pieces do not fall off
during sampling.
(iii) You must transfer all samples to a clean plastic bag for
further processing.
(d) You must prepare each composite sample according to the
procedures in paragraphs (d)(1) through (7) of this section.
(1) You must thoroughly mix and pour the entire composite sample
over a clean plastic sheet.
(2) You must break sample pieces larger than 3 inches into smaller
sizes.
(3) You must make a pie shape with the entire composite sample and
subdivide it into four equal parts.
(4) You must separate one of the quarter samples as the first
subset.
(5) If this subset is too large for grinding, you must repeat the
procedure in paragraph (d)(3) of this section with the quarter sample
and obtain a one-quarter subset from this sample.
(6) You must grind the sample in a mill.
(7) You must use the procedure in paragraph (d)(3) of this section
to obtain a one-quarter subsample for analysis. If the quarter sample
is too large, subdivide it further using the same procedure.
(e) You must determine the concentration of pollutants in the fuel
(mercury and/or chlorine) in units of
[[Page 32053]]
pounds per million Btu of each composite sample for each fuel type
according to the procedures in Table 6 to this subpart.
Sec. 63.7522 Can I use emission averaging to comply with this
subpart?
(a) As an alternative to meeting the requirements of Sec. 63.7500
for particulate matter, HCl, or mercury on a boiler or process heater-
specific basis, if you have more than one existing boiler or process
heater in any subcategory located at your facility, you may demonstrate
compliance by emission averaging, if your averaged emissions are within
90 percent of the applicable emission limit, according to the
procedures in this section.
(b) Separate stack requirements. For a group of two or more
existing boilers or process heaters in the same subcategory that each
vent to a separate stack, you may average particulate matter, HCl, and
mercury emissions to demonstrate compliance with the limits in Table 2
to this subpart if you satisfy the requirements in paragraphs (c), (d),
(e), (f), and (g) of this section.
(c) For each existing boiler or process heater in the averaging
group, the emission rate achieved during the initial compliance test
for the HAP being averaged must not exceed the emission level that was
being achieved on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER] or the control technology employed during the
initial compliance test must not be less effective for the HAP being
averaged than the control technology employed on [THE DATE 30 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] .
(d) The averaged emissions rate from the existing boilers and
process heaters participating in the emissions averaging option must be
in compliance with the limits in Table 2 to this subpart at all times
following the compliance date specified in Sec. 63.7495.
(e) You must demonstrate initial compliance according to paragraph
(e)(1) or (2) of this section.
(1) You must use Equation 1 of this section to demonstrate that the
particulate matter, HCl, and mercury emissions from all existing units
participating in the emissions averaging option do not exceed the
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.003
Where:
Ave Weighted Emissions = Average weighted emissions for particulate
matter, HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate (as calculated according to Table 5 to this
subpart for particulate matter, HCl, or mercury or by fuel analysis
for HCl or mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of
million Btu per hour.
n = Number of units participating in the emissions averaging option.
0.90 = Required discount factor.
(2) If you are not capable of monitoring heat input, and the boiler
generates steam, you may use Equation 2 of this section as an
alternative to using Equation 1 of this section to demonstrate that the
particulate matter, HCl, and mercury emissions from all existing units
participating in the emissions averaging option do not exceed the
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.004
Where:
Ave Weighted Emissions = Average weighted emission level for PM,
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this
subpart for particulate matter, HCl, or mercury or by fuel analysis
for HCl or mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated for unit, i.
0.90 = Required discount factor.
(f) You must demonstrate compliance on a monthly basis determined
at the end of every month (12 times per year) according to paragraphs
(f)(1) through (3) of this section. The first monthly period begins on
the compliance date specified in Sec. 63.7495.
(1) For each calendar month, you must use Equation 3 of this
section to calculate the monthly average weighted emission rate using
the actual heat capacity for each existing unit participating in the
emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.005
Where:
Ave Weighted Emissions = monthly average weighted emission level for
particulate matter, HCl, or mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate, (as calculated during the most recent compliance
test, (as calculated according to Table 5 to this subpart for
particulate matter, HCl, or mercury or by fuel analysis for HCl or
mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Hb = The average heat input for each calendar month of boiler, i, in
units of million Btu.
n = Number of units participating in the emissions averaging option.
[[Page 32054]]
0.90 = Required discount factor.
(2) If you are not capable of monitoring heat input, you may use
Equation 4 of this section as an alternative to using Equation 3 of
this section to calculate the monthly weighted emission rate using the
actual steam generation from the units participating in the emissions
averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.006
Where:
Ave Weighted Emissions = monthly average weighted emission level for
PM, HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate, (as calculated during the most recent compliance
test (as calculated according to Table 5 to this subpart for
particulate matter, HCl, or mercury or by fuel analysis for HCl or
mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Sa = Actual steam generation for each calendar month by boiler, i,
in units of pounds.
Cf = Conversion factor, as calculated during the most recent
compliance test, in units of million Btu of heat input per pounds of
steam generated for unit, i.
0.90 = Required discount factor.
(3) Until 12 monthly weighted average emission rates have been
accumulated, calculate and report only the monthly average weighted
emission rate determined under paragraph (f)(1) or (2) of this section.
After 12 monthly weighted average emission rates have been accumulated,
for each subsequent calendar month, use Equation 5 of this section to
calculate the 12-month rolling average of the monthly weighted average
emission rates for the current month and the previous 11 months.
[GRAPHIC] [TIFF OMITTED] TP04JN10.007
Where:
Eavg = 12-month rolling average emission rate, (pounds per million
Btu heat input)
ERi = Monthly weighted average, for month ``i'', (pounds per million
Btu heat input)(as calculated by (f)(1) or (2))
(g) You must develop, and submit to the applicable regulatory
authority for review and approval upon request, an implementation plan
for emission averaging according to the following procedures and
requirements in paragraphs (g)(1) through (4).
(1) You must submit the implementation plan no later than 180 days
before the date that the facility intends to demonstrate compliance
using the emission averaging option.
(2) You must include the information contained in paragraphs
(g)(2)(i) through (vii) of this section in your implementation plan for
all emission sources included in an emissions average:
(i) The identification of all existing boilers and process heaters
in the averaging group, including for each either the applicable HAP
emission level or the control technology installed as of [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] and the
date on which you are requesting emission averaging to commence;
(ii) The process parameter (heat input or steam generated) that
will be monitored for each averaging group;
(iii) The specific control technology or pollution prevention
measure to be used for each emission boiler or process heater in the
averaging group and the date of its installation or application. If the
pollution prevention measure reduces or eliminates emissions from
multiple boilers or process heaters, the owner or operator must
identify each boiler or process heater;
(iv) The test plan for the measurement of particulate matter, HCl,
or mercury emissions in accordance with the requirements in Sec.
63.7520;
(v) The operating parameters to be monitored for each control
system or device consistent with 63.7500 and Table 4, and a description
of how the operating limits will be determined;
(vi) If you request to monitor an alternative operating parameter
pursuant to Sec. 63.7525, you must also include:
(A) A description of the parameter(s) to be monitored and an
explanation of the criteria used to select the parameter(s); and
(B) A description of the methods and procedures that will be used
to demonstrate that the parameter indicates proper operation of the
control device; the frequency and content of monitoring, reporting, and
recordkeeping requirements; and a demonstration, to the satisfaction of
the applicable regulatory authority, that the proposed monitoring
frequency is sufficient to represent control device operating
conditions; and
(vii) A demonstration that compliance with each of the applicable
emission limit(s) will be achieved under representative operating
conditions.
(3) The regulatory authority shall review and approve or disapprove
the plan according to the following criteria:
(i) Whether the content of the plan includes all of the information
specified in paragraph (g)(2) of this section; and
(ii) Whether the plan presents sufficient information to determine
that compliance will be achieved and maintained.
(4) The applicable regulatory authority shall not approve an
emission averaging implementation plan containing any of the following
provisions:
(i) Any averaging between emissions of differing pollutants or
between differing sources; or
(ii) The inclusion of any emission source other than an existing
unit in the same subcategory.
(h) Common stack requirements. For a group of two or more existing
affected units, each of which vents through a single common stack, you
may average particulate matter, HCl and mercury emissions to
demonstrate compliance with the limits in Table 2 to this subpart if
you satisfy the requirements in paragraph (i) or (j) of this section.
(i) For a group of two or more existing units in the same
subcategory, each of which vents through a common emissions control
system to a common stack, that does not receive emissions from units in
other subcategories or categories, you may treat such averaging group
as a single existing unit for
[[Page 32055]]
purposes of this subpart and comply with the requirements of this
subpart as if the group were a single unit.
(j) For all other groups of units subject to paragraph (h) of this
section, the owner or operator may elect to:
(1) Conduct performance tests according to procedures specified in
Sec. 63.7520 in the common stack if affected units from other
subcategories vent to the common stack. The emission limits that the
group must comply with are determined by the use of equation 6.
[GRAPHIC] [TIFF OMITTED] TP04JN10.008
Where:
En = HAP emission limit, lb/MMBtu, ppm, or ng/dscm;
ELi = Appropriate emission limit from Table 2 to this
subpart for unit i, in units of lb/MMBtu, ppm or ng/dscm;
Hi = Heat input from unit i, MMBtu;
(2) Conduct performance tests according to procedures specified in
Sec. 63.7520 in the common stack. If affected units from nonaffected
units vent to the common stack, the units from nonaffected units must
be shut down or vented to a different stack during the performance
test); and
(3) Meet the applicable operating limit specified in Sec. 63.7540
and Table 8 to this subpart for each emissions control system (except
that, if each unit venting to the common stack has an applicable
opacity operating limit, then a single continuous opacity monitoring
system may be located in the common stack instead of in each duct to
the common stack).
(k) Combination requirements. The common stack of a group of two or
more existing boilers or process heaters in the same subcategory
subject to paragraph (h) of this section may be treated as a separate
stack for purposes of paragraph (b) of this section and included in an
emissions averaging group subject to paragraph (b) of this section.
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If your boiler or process heater has a heat input capacity of
100 MMBtu per hour or greater, you must install, operate, and maintain
a continuous emission monitoring system (CEMS) for CO and oxygen
according to the procedures in paragraphs (a)(1) through (6) of this
section by the compliance date specified in Sec. 63.7495. The CO and
oxygen shall be monitored at the same location at the outlet of the
boiler or process heater.
(1) Each CEMS must be installed, operated, and maintained according
to the applicable procedures under Performance Specification (PS) 3 or
4A of 40 CFR part 60, appendix B, and according to the site-specific
monitoring plan developed according to Sec. 63.7505(d).
(2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec. 63.8 and according to PS 4A of
40 CFR part 60, appendix B.
(3) Each CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period.
(4) The CEMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must calculate and record a 30-day rolling average emission
rate on a daily basis. A new 30-day rolling average emission rate is
calculated as the average of all of the hourly CO emission data for the
preceding 30 operating days.
(6) For purposes of calculating data averages, you must use all the
data collected during all periods in assessing compliance. Any period
for which the monitoring system is out of control and data are not
available for required calculations constitutes a deviation from the
monitoring requirements.
(b) If your boiler or process heater has a heat input capacity of
250 MMBtu per hour or greater and combusts coal, biomass, or residual
oil, you must install, certify, maintain, and operate a CEMS measuring
PM emissions discharged to the atmosphere and record the output of the
system as specified in paragraphs (b)(1) through (b)(6) of this
section.
(1) Each CEMS shall be installed, certified, operated, and
maintained according to the requirements in Sec. 63.7540(a)(8).
(2) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of a new unit or within
180 days of the compliance date for an existing unit, as specified
under Sec. 63.7495 of this subpart.
(3) Compliance with the applicable emissions limit shall be
determined based on the 24-hour daily (block) average of the hourly
arithmetic average emissions concentrations using the continuous
monitoring system outlet data. The 24-hour block arithmetic average
emission concentration shall be calculated using EPA Reference Method
19 of appendix A of 40 CFR part 60.
(4) Obtain valid CEMS hourly averages for all operating hours on a
30-day rolling average basis. At least two data points per hour shall
be used to calculate each 1-hour arithmetic average.
(5) The 1-hour arithmetic averages required shall be expressed in
lb/MMBtu and shall be used to calculate the boiler operating day daily
arithmetic average emissions.
(6) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of 40 CFR part 60 to provide, as necessary, valid emissions data for
all operating hours per 30-day rolling average.
(c) If you have an applicable opacity operating limit, you must
install, operate, certify and maintain each continuous opacity
monitoring system (COMS) according to the procedures in paragraphs
(c)(1) through (7) of this section by the compliance date specified in
Sec. 63.7495.
(1) Each COMS must be installed, operated, and maintained according
to PS 1 of 40 CFR part 60, appendix B.
(2) You must conduct a performance evaluation of each COMS
according to the requirements in Sec. 63.8 and according to PS 1 of 40
CFR part 60, appendix B.
(3) As specified in Sec. 63.8(c)(4)(i), each COMS must complete a
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
(4) The COMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
COMS according to the requirements in Sec. 63.8(d). At a minimum, the
monitoring plan must include a daily calibration drift assessment, a
quarterly performance audit, and an annual zero alignment audit of each
COMS.
(6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). You must 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. Any 6-minute 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.
(7) You must determine and record all the 6-minute averages (and 1-
hour block
[[Page 32056]]
averages as applicable) collected for periods during which the COMS is
not out of control.
(d) If you have an operating limit that requires the use of a CMS,
you must install, operate, and maintain each continuous parameter
monitoring system (CPMS) according to the procedures in paragraphs
(d)(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 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 15-minute 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) You must determine the 3-hour block average of all recorded
readings, except as provided in paragraph (c)(3) of this section.
(5) You must record the results of each inspection, calibration,
and validation check.
(e) If you have an operating limit that requires the use of a flow
measurement device, you must meet the requirements in paragraphs (d)
and (e)(1) through (4) of this section.
(1) You must locate the flow sensor and other necessary equipment
in a position that provides a representative flow.
(2) You must use a flow sensor with a measurement sensitivity of 2
percent of the flow rate.
(3) You must reduce swirling flow or abnormal velocity
distributions due to upstream and downstream disturbances.
(4) You must conduct a flow sensor calibration check at least
semiannually.
(f) If you have an operating limit that requires the use of a
pressure measurement device, you must meet the requirements in
paragraphs (d) and (f)(1) through (6) of this section.
(1) Locate the pressure sensor(s) in a position that provides a
representative measurement of the pressure.
(2) Minimize or eliminate pulsating pressure, vibration, and
internal and external corrosion.
(3) Use a gauge with a minimum tolerance of 1.27 centimeters of
water or a transducer with a minimum tolerance of 1 percent of the
pressure range.
(4) Check pressure tap pluggage daily.
(5) Using a manometer, you must check gauge calibration quarterly
and transducer calibration monthly.
(6) Conduct calibration checks any time the sensor exceeds the
manufacturer's specified maximum operating pressure range or install a
new pressure sensor.
(g) If you have an operating limit that requires the use of a pH
measurement device, you must meet the requirements in paragraphs (d)
and (g)(1) through (3) of this section.
(1) Locate the pH sensor in a position that provides a
representative measurement of scrubber effluent pH.
(2) Ensure the sample is properly mixed and representative of the
fluid to be measured.
(3) Check the pH meter's calibration on at least two points every 8
hours of process operation.
(h) If you have an operating limit that requires the use of
equipment to monitor voltage and secondary amperage (or total power
input) of an electrostatic precipitator (ESP), you must use voltage and
secondary current monitoring equipment to measure voltage and secondary
current to the ESP.
(i) If you have an operating limit that requires the use of
equipment to monitor sorbent injection rate (e.g., weigh belt, weigh
hopper, or hopper flow measurement device), you must meet the
requirements in paragraphs (c) and (i)(1) through (3) of this section.
(1) Locate the device in a position(s) that provides a
representative measurement of the total sorbent injection rate.
(2) Install and calibrate the device in accordance with
manufacturer's procedures and specifications.
(3) At least annually, calibrate the device in accordance with the
manufacturer's procedures and specifications.
(j) If you elect to use a fabric filter bag leak detection system
to comply with the requirements of this subpart, you must install,
calibrate, maintain, and continuously operate a bag leak detection
system as specified in paragraphs (j)(1) through (8) of this section.
(1) You must install and operate a bag leak detection system for
each exhaust stack of the fabric filter.
(2) Each bag leak detection system must be installed, operated,
calibrated, and maintained in a manner consistent with the
manufacturer's written specifications and recommendations and in
accordance with the guidance provided in EPA-454/R-98-015, September
1997.
(3) The bag leak detection system must be certified by the
manufacturer to be capable of detecting particulate matter emissions at
concentrations of 10 milligrams per actual cubic meter or less.
(4) The bag leak detection system sensor must provide output of
relative or absolute particulate matter loadings.
(5) The bag leak detection system must be equipped with a device to
continuously record the output signal from the sensor.
(6) The bag leak detection system must be equipped with an alarm
system that will sound automatically when an increase in relative
particulate matter emissions over a preset level is detected. The alarm
must be located where it is easily heard by plant operating personnel.
(7) For positive pressure fabric filter systems that do not duct
all compartments of cells to a common stack, a bag leak detection
system must be installed in each baghouse compartment or cell.
(8) Where multiple bag leak detectors are required, the system's
instrumentation and alarm may be shared among detectors.
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limits and work practice standards?
(a) You must demonstrate initial compliance with each emission
limit that applies to you by conducting initial performance tests
(performance stack tests and fuel analyses) and establishing operating
limits, as applicable, according to Sec. 63.7520, paragraph (c) of
this section, and Tables 5 and 7 to this subpart.
(b) If you demonstrate compliance through performance stack
testing, you must establish each site-specific operating limit in Table
2 to this subpart that applies to you according to the requirements in
Sec. 63.7520, Table 7 to this subpart, and paragraph (c)(4) of this
section, as applicable. You must also
[[Page 32057]]
conduct fuel analyses according to Sec. 63.7521 and establish maximum
fuel pollutant input levels according to paragraphs (c)(1) through (3)
of this section, as applicable.
(1) You must establish the maximum chlorine fuel input
(Cinput) during the initial performance testing according to
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
chlorine.
(ii) During the performance testing for HCl, you must determine the
fraction of the total heat input for each fuel type burned
(Qi) based on the fuel mixture that has the highest content
of chlorine, and the average chlorine concentration of each fuel type
burned (Ci).
(iii) You must establish a maximum chlorine input level using
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.009
Where:
Clinput = Maximum amount of chlorine entering the boiler
or process heater through fuels burned in units of pounds per
million Btu.
Ci = Arithmetic average concentration of chlorine in fuel
type, i, analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest content of chlorine.
If you do not burn multiple fuel types during the performance
testing, it is not necessary to determine the value of this term.
Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
(2) You must establish the maximum mercury fuel input level
(Mercuryinput) during the initial performance testing using
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
mercury.
(ii) During the compliance demonstration for mercury, you must
determine the fraction of total heat input for each fuel burned
(Qi) based on the fuel mixture that has the highest content
of mercury, and the average mercury concentration of each fuel type
burned (HGi).
(iii) You must establish a maximum mercury input level using
Equation 8 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.010
Where:
Mercuryinput = Maximum amount of mercury entering the
boiler or process heater through fuels burned in units of pounds per
million Btu.
HGi = Arithmetic average concentration of mercury in fuel
type, i, analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest mercury content. If
you do not burn multiple fuel types during the performance test, it
is not necessary to determine the value of this term. Insert a value
of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of mercury.
(3) You must establish parameter operating limits according to
paragraphs (c)(4)(i) through (iv) of this section.
(i) For a wet scrubber, you must establish the minimum scrubber
effluent pH, liquid flowrate, and pressure drop as defined in Sec.
63.7575, as your operating limits during the three-run performance
test. If you use a wet scrubber and you conduct separate performance
tests for particulate matter, HCl, and mercury emissions, you must
establish one set of minimum scrubber effluent pH, liquid flowrate, and
pressure drop operating limits. The minimum scrubber effluent pH
operating limit must be established during the HCl performance test. If
you conduct multiple performance tests, you must set the minimum liquid
flowrate and pressure drop operating limits at the highest minimum
values established during the performance tests.
(ii) For an electrostatic precipitator, you must establish the
minimum voltage and secondary current (or total power input), as
defined in Sec. 63.7575, as your operating limits during the three-run
performance test.
(iii) For a dry scrubber, you must establish the minimum sorbent
injection rate for each sorbent, as defined in Sec. 63.7575, as your
operating limit during the three-run performance test.
(iv) The operating limit for boilers or process heaters with fabric
filters that choose to demonstrate continuous compliance through bag
leak detection systems is that a bag leak detection system be installed
according to the requirements in Sec. 63.7525, and that each fabric
filter must be operated such that the bag leak detection system alarm
does not sound more than 5 percent of the operating time during a 6-
month period.
(c) If you elect to demonstrate compliance with an applicable
emission limit through fuel analysis, you must conduct fuel analyses
according to Sec. 63.7521 and follow the procedures in paragraphs
(c)(1) through (5) of this section.
(1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your boiler or process heater that would
result in the maximum emission rates of the pollutants that you elect
to demonstrate compliance through fuel analysis.
(2) You must determine the 90th percentile confidence level fuel
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided z-statistic test described in Equation 9 of
this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.011
Where:
P90 = 90th percentile confidence level pollutant
concentration, in pounds per million Btu.
mean = Arithmetic average of the fuel pollutant concentration in the
fuel samples analyzed according to Sec. 63.7521, in units of pounds
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel
samples analyzed according to Sec. 63.7521, in units of pounds per
million Btu.
t = t distribution critical value for 90th percentile (0.1)
probability for the appropriate degrees of freedom (number of
samples minus one) as obtained from a Distribution Critical Value
Table.
(3) To demonstrate compliance with the applicable emission limit
for HCl, the HCl emission rate that you calculate for your boiler or
process heater using Equation 10 of this section must not exceed the
applicable emission limit for HCl.
[[Page 32058]]
[GRAPHIC] [TIFF OMITTED] TP04JN10.012
Where:
HCl = HCl emission rate from the boiler or process heater in units
of pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of
chlorine in fuel type, i, in units of pounds per million Btu as
calculated according to Equation 8 of this section.
Qi= Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest content of chlorine.
If you do not burn multiple fuel types, it is not necessary to
determine the value of this term. Insert a value of ``1'' for
Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.
(4) To demonstrate compliance with the applicable emission limit
for mercury, the mercury emission rate that you calculate for your
boiler or process heater using Equation 11 of this section must not
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TP04JN10.013
Where:
Mercury = Mercury emission rate from the boiler or process heater in
units of pounds per million Btu.
HGi90 = 90th percentile confidence level concentration of
mercury in fuel, i, in units of pounds per million Btu as calculated
according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest mercury content. If
you do not burn multiple fuel types, it is not necessary to
determine the value of this term. Insert a value of ``1'' for
Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest mercury content.
(d) If you own or operate an existing unit with a heat input
capacity of 10 million Btu per hour or less, you must submit a signed
statement in the Notification of Compliance Status report that
indicates that you conducted a tune-up of the unit.
(e) You must submit the energy assessment report, along with a
signed certification that the assessment is an accurate depiction of
your facility.
(f) You must submit the Notification of Compliance Status
containing the results of the initial compliance demonstration
according to the requirements in Sec. 63.7545(e).
Continuous Compliance Requirements
Sec. 63.7535 How do I monitor and collect data to demonstrate
continuous compliance?
(a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec. 63.7505(d).
(b) Except for monitor malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must monitor continuously (or collect data at all required
intervals) at all times that the affected source is operating.
(c) You may not use data recorded during monitoring malfunctions,
associated repairs, or required quality assurance or control activities
in data averages and calculations used to report emission or operating
levels. You must use all the data collected during all other periods in
assessing the operation of the control device and associated control
system.
Sec. 63.7540 How do I demonstrate continuous compliance with the
emission limits and work practice standards?
(a) You must demonstrate continuous compliance with each emission
limit, operating limit, and work practice standard in Tables 1 through
3 to this subpart that applies to you according to the methods
specified in Table 8 to this subpart and paragraphs (a)(1) through (10)
of this section.
(1) Following the date on which the initial performance test is
completed or is required to be completed under Sec. Sec. 63.7 and
63.7510, whichever date comes first, you must not operate above any of
the applicable maximum operating limits or below any of the applicable
minimum operating limits listed in Table 4 to this subpart at any
times. Operation above the established maximum or below the established
minimum operating limits shall constitute a deviation of established
operating limits. Operating limits must be confirmed or reestablished
during performance tests.
(2) As specified in Sec. 63.7550(c), you must keep records of the
type and amount of all fuels burned in each boiler or process heater
during the reporting period to demonstrate that all fuel types and
mixtures of fuels burned would either result in lower emissions of HCl
and mercury, than the applicable emission limit for each pollutant (if
you demonstrate compliance through fuel analysis), or result in lower
fuel input of chlorine and mercury than the maximum values calculated
during the last performance tests (if you demonstrate compliance
through performance stack testing).
(3) If you demonstrate compliance with an applicable HCl emission
limit through fuel analysis and you plan to burn a new type of fuel,
you must recalculate the HCl emission rate using Equation 9 of Sec.
63.7530 according to paragraphs (a)(3)(i) through (iii) of this
section.
(i) You must determine the chlorine concentration for any new fuel
type in units of pounds per million Btu, based on supplier data or your
own fuel analysis, according to the provisions in your site-specific
fuel analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of chlorine.
(iii) Recalculate the HCl emission rate from your boiler or process
heater under these new conditions using Equation 9 of Sec. 63.7530.
The recalculated HCl emission rate must be less than the applicable
emission limit.
(4) If you demonstrate compliance with an applicable HCl emission
limit through performance testing and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum
chlorine input using Equation 5 of Sec. 63.7530. If the results of
recalculating the maximum chlorine input using Equation 5 of Sec.
63.7530 are higher than the maximum chlorine input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the HCl emissions do not exceed the emission limit. You must also
establish new operating limits based on this performance test according
to the procedures in Sec. 63.7530(c).
(5) If you demonstrate compliance with an applicable mercury
emission limit through fuel analysis, and you plan to burn a new type
of fuel, you must recalculate the mercury emission rate using Equation
11 of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(7)(i) through (iii) of this section.
(i) You must determine the mercury concentration for any new fuel
type in
[[Page 32059]]
units of pounds per million Btu, based on supplier data or your own
fuel analysis, according to the provisions in your site-specific fuel
analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of mercury.
(iii) Recalculate the mercury emission rate from your boiler or
process heater under these new conditions using Equation 11 of Sec.
63.7530. The recalculated mercury emission rate must be less than the
applicable emission limit.
(6) If you demonstrate compliance with an applicable mercury
emission limit through performance testing, and you plan to burn a new
type of fuel or a new mixture of fuels, you must recalculate the
maximum mercury input using Equation 7 of Sec. 63.7530. If the results
of recalculating the maximum mercury input using Equation 7 of Sec.
63.7530 are higher than the maximum mercury input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the mercury emissions do not exceed the emission limit. You must
also establish new operating limits based on this performance test
according to the procedures in Sec. 63.7530(c).
(7) If your unit is controlled with a fabric filter, and you
demonstrate continuous compliance using a bag leak detection system,
you must initiate corrective action within 1 hour of a bag leak
detection system alarm and complete corrective actions as soon as
practical, and operate and maintain the fabric filter system such that
the alarm does not sound more than 5 percent of the operating time
during a 6-month period. You must also keep records of the date, time,
and duration of each alarm, the time corrective action was initiated
and completed, and a brief description of the cause of the alarm and
the corrective action taken. You must also record the percent of the
operating time during each 6-month period that the alarm sounds. In
calculating this operating time percentage, if inspection of the fabric
filter demonstrates that no corrective action is required, no alarm
time is counted. If corrective action is required, each alarm shall be
counted as a minimum of 1 hour. If you take longer than 1 hour to
initiate corrective action, the alarm time shall be counted as the
actual amount of time taken to initiate corrective action.
(8) If you are required to install a CEMS according to Sec.
63.7525(a), then you must meet the requirements in paragraphs (a)(8)(i)
through (iii) of this section.
(i) You must continuously monitor CO according to Sec. Sec.
63.7525(a) and 63.7535.
(ii) Maintain a CO emission level below or at your applicable CO
standard in Tables 1 or 2 to this subpart at all times.
(iii) Keep records of CO levels according to Sec. 63.7555(b).
(9) The owner or operator of an affected source using a CEMS
measuring PM emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (a)(9)(i) through (a)(9)(iv) of this section.
(i) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec. 60.13 of 40
CFR, Performance Specification 11 in appendix B of 40 CFR part 60, and
procedure 2 in appendix F of 40 CFR part 60.
(ii) During each PM correlation testing run of the CEMS required by
Performance Specification 11 in appendix B of 40 CFR part 60, PM and O2
(or CO2) data shall be collected concurrently (or within a 30- to 60-
minute period) by both the CEMS and conducting performance tests using
Method 5 or 5B of appendix A-3 of 40 CFR part 60 or Method 17 of
appendix A-6 of 40 CFR part 60.
(iii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F
of 40 CFR part 60. Relative Response Audits must be performed annually
and Response Correlation Audits must be performed every 3 years.
(iv) After December 31, 2011, within 60 days after the date of
completing each performance evaluation conducted to demonstrate
compliance with this subpart, the owner or operator of the affected
facility must submit the test data to EPA by successfully entering the
data electronically into EPA's WebFIRE database through EPA's Central
Data Exchange. The owner or operator of an affected facility shall
enter the test data into EPA's data base using the Electronic Reporting
Tool (ERT) or other compatible electronic spreadsheet.
(10) If your boiler or process heater is in either the Gas 1 (NG/
RG) or Metal Process Furnace subcategories and have a heat input
capacity of 10 million Btu per hour or greater, you must conduct a
tune-up of the boiler or process heater annually to demonstrate
continuous compliance as specified in paragraphs (a)(10)(i) through
(a)(10)(vi) of this section.
(i) Inspect the burner, and clean or replace any components of the
burner as necessary;
(ii) Inspect the flame pattern and make any adjustments to the
burner necessary to optimize the flame pattern consistent with the
manufacturer's specifications;
(iii) Inspect the system controlling the air-to-fuel ratio, and
ensure that it is correctly calibrated and functioning properly;
(iv) Minimize total emissions of CO consistent with the
manufacturer's specifications;
(v) Measure the concentration in the effluent stream of CO in parts
per million, by volume, dry basis (ppmvd), before and after the
adjustments are made; and
(vi) Maintain on-site and submit, if requested by the
Administrator, an annual report containing the information in
paragraphs (a)(10)(vi)(A) through (C) of this section,
(A) The concentrations of CO in the effluent stream in ppmvd, and
oxygen in percent dry basis, measured before and after the adjustments
of the boiler;
(B) A description of any corrective actions taken as a part of the
combustion adjustment; and
(C) The type and amount of fuel used over the 12 months prior to
the annual adjustment.
(11) If your boiler or process heater has a heat input capacity of
less than 10 million Btu per hour, you must conduct a tune-up of the
boiler or process heater biennially to demonstrate continuous
compliance as specified in paragraphs (a)(10)(i) through (a)(10)(vi) of
this section.
(b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 through 4 to this
subpart that apply to you. These instances are deviations from the
emission limits in this subpart. These deviations must be reported
according to the requirements in Sec. 63.7550.
Sec. 63.7541 How do I demonstrate continuous compliance under the
emission averaging provision?
(a) Following the compliance date, the owner or operator must
demonstrate compliance with this subpart on a continuous basis by
meeting the requirements of paragraphs (a)(1) through (5) of this
section.
(1) For each calendar month, demonstrate compliance with the
average weighted emissions limit for the existing units participating
in the
[[Page 32060]]
emissions averaging option as determined in Sec. 63.7522(f) and (g);
(2) You must maintain the applicable opacity limit according to
paragraphs (a)(2)(i) through (ii) of this section.
(i) For each existing unit participating in the emissions averaging
option that is equipped with a dry control system and not vented to a
common stack, maintain opacity at or below the applicable limit.
(ii) For each group of units participating in the emissions
averaging option where each unit in the group is equipped with a dry
control system and vented to a common stack that does not receive
emissions from nonaffected units, maintain opacity at or below the
applicable limit at the common stack;
(3) For each existing unit participating in the emissions averaging
option that is equipped with a wet scrubber, maintain the 3-hour
average parameter values at or below the operating limits established
during the most recent performance test; and
(4) For each existing unit participating in the emissions averaging
option that has an approved alternative operating plan, maintain the 3-
hour average parameter values at or below the operating limits
established in the most recent performance test.
(5) For each existing unit participating in the emissions averaging
option venting to a common stack configuration containing affected
units from other subcategories, maintain the appropriate operating
limit for each unit as specified in Table 4 to this subpart that
applies.
(b) Any instance where the owner or operator fails to comply with
the continuous monitoring requirements in paragraphs (a)(1) through (5)
of this section is a deviation.
Notification, Reports, and Records
Sec. 63.7545 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec. Sec. 63.7(b)
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply
to you by the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you startup your affected
source before [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], you must submit an Initial Notification not later
than 120 days after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER].
(c) As specified in Sec. 63.9(b)(4) and (b)(5), if you startup
your new or reconstructed affected source on or after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
submit an Initial Notification not later than 15 days after the actual
date of startup of the affected source.
(d) If you are required to conduct a performance test you must
submit a Notification of Intent to conduct a performance test at least
30 days before the performance test is scheduled to begin.
(e) If you are required to conduct an initial compliance
demonstration as specified in Sec. 63.7530(a), you must submit a
Notification of Compliance Status according to Sec. 63.9(h)(2)(ii).
For each initial compliance demonstration, you must submit the
Notification of Compliance Status, including all performance test
results and fuel analyses, before the close of business on the 60th day
following the completion of the performance test and/or other initial
compliance demonstrations according to Sec. 63.10(d)(2). The
Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(1) through (9) of this section,
as applicable.
(1) A description of the affected source(s) including
identification of which subcategory the source is in, the design
capacity of the source, a description of the add-on controls used on
the source, description of the fuel(s) burned, including whether the
fuel(s) were determined by you or EPA through a petition process to be
a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from
discarded non-hazardous secondary materials within the meaning of 40
CFR 241.3, and justification for the selection of fuel(s) burned during
the performance test.
(2) Summary of the results of all performance tests (stack tests
and fuel analyses) and calculations conducted to demonstrate initial
compliance including all established operating limits.
(3) A summary of the CO emissions monitoring data and the maximum
CO emission levels recorded during the performance test to show that
you have met any applicable emission standard in Table 1 or 2 to this
subpart.
(4) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance stack testing
or fuel analysis.
(5) Identification of whether you plan to demonstrate compliance by
emissions averaging.
(6) A signed certification that you have met all applicable
emission limits and work practice standards.
(7) If you had a deviation from any emission limit, work practice
standard, or operating limit, 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.
(f) If you operate a natural gas-fired boiler or process heater
that is subject to this subpart, and you intend to use a fuel other
than natural gas or equivalent to fire the affected unit, you must
submit a notification of alternative fuel use within 48 hours of the
declaration of a period of natural gas curtailment or supply
interruption, as defined in Sec. 63.7575. The notification must
include the information specified in paragraphs (f)(1) through (5) of
this section.
(1) Company name and address.
(2) Identification of the affected unit.
(3) Reason you are unable to use natural gas or equivalent fuel,
including the date when the natural gas curtailment was declared or the
natural gas supply interruption began.
(4) Type of alternative fuel that you intend to use.
(5) Dates when the alternative fuel use is expected to begin and
end.
Sec. 63.7550 What reports must I submit and when?
(a) You must submit each report in Table 9 to this subpart that
applies to you.
(b) Unless the EPA Administrator has approved a different schedule
for submission of reports under Sec. 63.10(a), you must submit each
report by the date in Table 9 to this subpart and according to the
requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.7495 and ending on June 30 or December 31, whichever date is the
first date that occurs at least 180 days after the compliance date that
is specified for your source in Sec. 63.7495.
(2) The first compliance report must be postmarked or delivered no
later than July 31 or January 31, whichever date is the first date
following the end of the first calendar half after the compliance date
that is specified for your source in Sec. 63.7495.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or
delivered no later than July 31 or January 31, whichever date is the
first date following the end of the semiannual reporting period.
[[Page 32061]]
(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 (9) of this section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name,
title, and signature, certifying the truth, accuracy, and completeness
of the content of the report.
(3) Date of report and beginning and ending dates of the reporting
period.
(4) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the semiannual reporting
period, including, but not limited to, a description of the fuel,
whether the fuel has received a non-waste determination by EPA or your
basis for concluding that the fuel is not a waste, and the total fuel
usage amount with units of measure.
(5) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable. If you are conducting stack tests once every
three years consistent with Sec. 63.7515(b) or (c), the date of the
last three stack tests, a comparison of the emission level you achieved
in the last three stack tests to the 90 percent emission limit
threshold required in Sec. 63.7515(b) or (c), and a statement as to
whether there have been any operational changes since the last stack
test that could increase emissions.
(6) A signed statement indicating that you burned no new types of
fuel. Or, if you did burn a new type of fuel, you must submit the
calculation of chlorine input, using Equation 5 of Sec. 63.7530, that
demonstrates that your source is still within its maximum chlorine
input level established during the previous performance testing (for
sources that demonstrate compliance through performance testing) or you
must submit the calculation of HCl emission rate using Equation 9 of
Sec. 63.7530 that demonstrates that your source is still meeting the
emission limit for HCl emissions (for boilers or process heaters that
demonstrate compliance through fuel analysis). If you burned a new type
of fuel, you must submit the calculation of mercury input, using
Equation 7 of Sec. 63.7530, that demonstrates that your source is
still within its maximum mercury input level established during the
previous performance testing (for sources that demonstrate compliance
through performance testing), or you must submit the calculation of
mercury emission rate using Equation 11 of Sec. 63.7530 that
demonstrates that your source is still meeting the emission limit for
mercury emissions (for boilers or process heaters that demonstrate
compliance through fuel analysis).
(7) If you wish to burn a new type of fuel and you cannot
demonstrate compliance with the maximum chlorine input operating limit
using Equation 5 of Sec. 63.7530 or the maximum mercury input
operating limit using Equation 7 of Sec. 63.7530, you must include in
the compliance report a statement indicating the intent to conduct a
new performance test within 60 days of starting to burn the new fuel.
(8) If there are no deviations from any emission limits or
operating limits in this subpart that apply to you, a statement that
there were no deviations from the emission limits or operating limits
during the reporting period.
(9) If there were no deviations from the monitoring requirements
including no periods during which the CMSs, including CEMS, COMS, and
CPMS, were out of control as specified in Sec. 63.8(c)(7), a statement
that there were no deviations and no periods during which the CMS were
out of control during the reporting period.
(d) For each deviation from an emission limit or operating limit in
this subpart that occurs at an affected source where you are not using
a CMS to comply with that emission limit or operating limit, the
compliance report must additionally contain the information required in
paragraphs (d)(1) through (4) of this section.
(1) The total operating time of each affected source during the
reporting period.
(2) A description of the deviation and which emission limit or
operating limit from which you deviated.
(3) Information on the number, duration, and cause of deviations
(including unknown cause), as applicable, and the corrective action
taken.
(4) A copy of the test report if the annual performance test showed
a deviation from the emission limits.
(e) For each deviation from an emission limit, operating limit, and
monitoring requirement in this subpart occurring at an affected source
where you are using a CMS to comply with that emission limit or
operating limit, you must include the information required in
paragraphs (e) (1) through (12) of this section. This includes any
deviations from your site-specific monitoring plan as required in Sec.
63.7505(d).
(1) The date and time that each deviation 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) An analysis 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 CMSs downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
(8) An identification of each parameter that was monitored at the
affected source for which there was a deviation.
(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
[[Page 32062]]
emission limit, operating limit, or work practice requirement in this
subpart, submission of the compliance report satisfies any obligation
to report the same deviations in the semiannual monitoring report.
However, submission of a compliance report does not otherwise affect
any obligation the affected source may have to report deviations from
permit requirements to the permit authority.
(g) In addition to the information required in Sec. 63.9(h)(2),
your notification must include the following certification(s) of
compliance, as applicable, and signed by a responsible official:
(1) ``This facility complies with the requirements in Sec.
63.7540(a)(10) to conduct an annual tune-up of the unit''.
(2) ``This facility has had an energy assessment performed
according to Sec. 63.7530(e).''
(3) ``No secondary materials that are solid waste were combusted in
any affected unit.''
(h) After December 31, 2011, within 60 days after the date of
completing each performance evaluation conducted to demonstrate
compliance with this subpart, the owner or operator of the affected
facility must submit the test data to EPA by entering the data
electronically into EPA's WebFIRE data base through EPA's Central Data
Exchange. The owner or operator of an affected facility shall enter the
test data into EPA's data base using the Electronic Reporting Tool or
other compatible electronic spreadsheet. Only performance evaluation
data collected using methods compatible with ERT are subject to this
requirement to be submitted electronically into EPA's WebFIRE database.
Sec. 63.7555 What records must I keep?
(a) You must keep records according to paragraphs (a)(1) and (2) 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) Records of performance stack tests, fuel analyses, or other
compliance demonstrations, performance evaluations, and opacity
observations as required in Sec. 63.10(b)(2)(viii).
(b) For each CEMS, CPMS, and COMS, you must keep records according
to paragraphs (b)(1) through (5) of this section.
(1) Records described in Sec. 63.10(b)(2)(vi) through (xi).
(2) Monitoring data for continuous opacity monitoring system during
a performance evaluation as required in Sec. 63.6(h)(7)(i) and (ii).
(3) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(4) Request for alternatives to relative accuracy test for CEMS as
required in Sec. 63.8(f)(6)(i).
(5) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 8 to this subpart
including records of all monitoring data and calculated averages for
applicable operating limits such as opacity, pressure drop, and pH to
show continuous compliance with each emission limit and operating limit
that applies to you.
(d) For each boiler or process heater subject to an emission limit,
you must also keep the records in paragraphs (d)(1) through (5) of this
section.
(1) You must keep records of monthly fuel use by each boiler or
process heater, including the type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous secondary materials that have been
determined not to be solid waste pursuant to 40 CFR 41.3(b)(1), you
must keep a record which documents how the secondary material meets
each of the legitimacy criteria. If you combust a fuel that has been
processed from a discarded non-hazardous secondary material pursuant to
40 CFR 241.3(b)(2), you must keep records as to how the operations that
produced the fuel satisfies the definition of processing in 40 CFR
241.2. If the fuel received a non-waste determination pursuant to the
petition process submitted under 40 CFR 241.3(c), you must keep a
record which documents how the fuel satisfies the requirements of the
petition process.
(3) You must keep records of monthly hours of operation by each
boiler or process heater. This requirement applies only to limited-use
boilers and process heaters.
(4) A copy of all calculations and supporting documentation of
maximum chlorine fuel input, using Equation 5 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the HCl emission
limit, for sources that demonstrate compliance through performance
testing. For sources that demonstrate compliance through fuel analysis,
a copy of all calculations and supporting documentation of HCl emission
rates, using Equation 9 of Sec. 63.7530, that were done to demonstrate
compliance with the HCl emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum chlorine fuel input or HCl emission rates. You can use the
results from one fuel analysis for multiple boilers and process heaters
provided they are all burning the same fuel type. However, you must
calculate chlorine fuel input, or HCl emission rate, for each boiler
and process heater.
(5) A copy of all calculations and supporting documentation of
maximum mercury fuel input, using Equation 7 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the mercury
emission limit for sources that demonstrate compliance through
performance testing. For sources that demonstrate compliance through
fuel analysis, a copy of all calculations and supporting documentation
of mercury emission rates, using Equation 11 of Sec. 63.7530, that
were done to demonstrate compliance with the mercury emission limit.
Supporting documentation should include results of any fuel analyses
and basis for the estimates of maximum mercury fuel input or mercury
emission rates. You can use the results from one fuel analysis for
multiple boilers and process heaters provided they are all burning the
same fuel type. However, you must calculate mercury fuel input, or
mercury emission rates, for each boiler and process heater.
(6) If consistent with Sec. 63.7555(b) and (c), you choose to
stack test less frequently than annually, you must keep annual records
that document that your emissions in the previous stack test(s) were
less than 90 percent of the applicable emission limit, and document
that there was no change in source operations including fuel
composition and operation of air pollution control equipment that would
cause emissions of the relevant pollutant to increase within the past
year.
(7) If you operate a gaseous fuel unit that is subject to the
emission limits specified in Table 1 or 2 to this subpart, and you
intend to use a fuel other than natural gas or equivalent to fire the
affected unit, you must keep records of the information required by the
notification under Sec. 63.7550, and records of the total hours per
calendar year that liquid fuel is burned.
(e) If you elect to average emissions consistent with Sec.
63.7522, you must additionally keep a copy of the emission averaging
implementation plan required in Sec. 63.7522(g), all calculations
required
[[Page 32063]]
under Sec. 63.7522, including daily records of heat input or steam
generation, as applicable, and monitoring records consistent with Sec.
63.7541.
Sec. 63.7560 In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 63.10(b)(1). You can keep
the records off site for the remaining 3 years.
Other Requirements and Information
Sec. 63.7565 What parts of the General Provisions apply to me?
Table 10 to this subpart shows which parts of the General
Provisions in Sec. Sec. 63.1 through 63.15 apply to you.
Sec. 63.7570 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by U.S. EPA, or a
delegated authority such as your State, local, or tribal agency. If the
EPA Administrator has delegated authority to your State, local, or
tribal agency, then that agency (as well as the U.S. EPA) has the
authority to implement and enforce this subpart. You should contact
your EPA Regional Office to find out if this subpart is delegated to
your State, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities listed in paragraphs (b)(1) through (5) of
this section are retained by the EPA Administrator and are not
transferred to the State, local, or tribal agency, however, the U.S.
EPA retains oversight of this subpart and can take enforcement actions,
as appropriate.
(1) Approval of alternatives to the non-opacity emission limits and
work practice standards in Sec. 63.7500(a) and (b) under Sec.
63.6(g).
(2) Approval of alternative opacity emission limits in Sec.
63.7500(a) under Sec. 63.6(h)(9).
(3) Approval of major change to test methods in Table 5 to this
subpart under Sec. 63.7(e)(2)(ii) and (f) and as defined in Sec.
63.90, and alternative analytical methods requested under
63.7521(b)(2).
(4) Approval of major change to monitoring under Sec. 63.8(f) and
as defined in Sec. 63.90, and approval of alternative operating
parameters under 63.7500(a)(2) and 63.7522(g)(2).
(5) Approval of major change to recordkeeping and reporting under
Sec. 63.10(e) 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 (CAA),
in Sec. 63.2 (the General Provisions), and in this section as follows:
Bag leak detection system means a group of instruments that are
capable of monitoring particulate matter loadings in the exhaust of a
fabric filter (i.e., baghouse) in order to detect bag failures. A bag
leak detection system includes, but is not limited to, an instrument
that operates on electrodynamic, triboelectric, light scattering, light
transmittance, or other principle to monitor relative particulate
matter loadings.
Biomass fuel means but is not limited to, wood residue, and wood
products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust,
sanderdust, chips, scraps, slabs, millings, and shavings); animal
manure, including litter and other bedding materials; 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. This definition of biomass fuel is not intended to
suggest that these materials are or are not solid waste.
Blast furnace gas fuel-fired boiler or process heater means an
industrial/commercial/institutional boiler or process heater that
receives 90 percent or more of its total heat input (based on an annual
average) from blast furnace gas.
Boiler means an enclosed device using controlled flame combustion
and having the primary purpose of recovering thermal energy in the form
of steam or hot water. A device combusting solid waste, as defined in
40 CFR 241.3, is not a boiler. Waste heat boilers are excluded from
this definition.
Boiler system means the boiler and associated components, such as,
the feedwater system, the combustion air system, the fuel system
(including burners), blowdown system, combustion control system, and
energy consuming systems.
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials in ASTM D388-991.\1\, ``Standard Specification for
Classification of Coals by Rank'' \1\ (incorporated by reference, see
Sec. 63.14(b)), coal refuse, and petroleum coke. Synthetic fuels
derived from coal for the purpose of creating useful heat including,
but not limited to, solvent-refined coal, coal-oil mixtures, and coal-
water mixtures, for the purposes of this subpart. Coal derived gases
are excluded from this definition.
Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and
a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
Commercial/institutional boiler means a boiler used in commercial
establishments or institutional establishments such as medical centers,
research centers, institutions of higher education, hotels, and
laundries to provide electricity, steam, and/or hot water.
Common stack means the exhaust of emissions from two or more
affected units through a single flue.
Cost-effective energy conservation measure means a measure that is
implemented to improve the energy efficiency of the boiler or facility
that has a payback (return of investment) period of two years or less.
Deviation. (1) Deviation means any instance in which an affected
source subject to this subpart, or an owner or operator of such a
source:
(i) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard; or
(ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
(2) A deviation is not always a violation. The determination of
whether a deviation constitutes a violation of the standard is up to
the discretion of the entity responsible for enforcement of the
standards.
Distillate oil means fuel oils, including recycled oils, that
comply with the specifications for fuel oil numbers 1 and 2, as defined
by the American Society for Testing and Materials in ASTM D396-02a,
``Standard Specifications for Fuel Oils'' \1\ (incorporated by
reference, see Sec. 63.14(b)).
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react
[[Page 32064]]
with and neutralize acid gas in the exhaust stream forming a dry powder
material. Sorbent injection systems in fluidized bed boilers and
process heaters are included in this definition.
Dutch oven means a unit having a refractory-walled cell connected
to a conventional boiler setting. Fuel materials are introduced through
an opening in the roof of the Dutch oven and burn in a pile on its
floor.
Electric utility steam generating unit means a fossil fuel-fired
combustion unit of more than 25 megawatts that serves a generator that
produces electricity for sale. A fossil fuel-fired unit that
cogenerates steam and electricity and supplies more than one-third of
its potential electric output capacity and more than 25 megawatts
electrical output to any utility power distribution system for sale is
considered an electric utility steam generating unit.
Electrostatic precipitator means an add-on air pollution control
device used to capture particulate matter by charging the particles
using an electrostatic field, collecting the particles using a grounded
collecting surface, and transporting the particles into a hopper.
Energy assessment means an in-depth assessment of a facility to
identify immediate and long-term opportunities to save energy, focusing
on the steam and process heating systems which involves a thorough
examination of potential savings from energy efficiency improvements,
waste minimization and pollution prevention, and productivity
improvement.
Equivalent means the following only as this term is used in Table 6
to subpart DDDDD:
(1) An equivalent sample collection procedure means a published
voluntary consensus standard or practice (VCS) or EPA method that
includes collection of a minimum of three composite fuel samples, with
each composite consisting of a minimum of three increments collected at
approximately equal intervals over the test period.
(2) An equivalent sample compositing procedure means a published
VCS or EPA method to systematically mix and obtain a representative
subsample (part) of the composite sample.
(3) An equivalent sample preparation procedure means a published
VCS or EPA method that: Clearly states that the standard, practice or
method is appropriate for the pollutant and the fuel matrix; or is
cited as an appropriate sample preparation standard, practice or method
for the pollutant in the chosen VCS or EPA determinative or analytical
method.
(4) An equivalent procedure for determining heat content means a
published VCS or EPA method to obtain gross calorific (or higher
heating) value.
(5) An equivalent procedure for determining fuel moisture content
means a published VCS or EPA method to obtain moisture content. If the
sample analysis plan calls for determining metals (especially the
mercury, selenium, or arsenic) using an aliquot of the dried sample,
then the drying temperature must be modified to prevent vaporizing
these metals. On the other hand, if metals analysis is done on an ``as
received'' basis, a separate aliquot can be dried to determine moisture
content and the metals concentration mathematically adjusted to a dry
basis.
(6) An equivalent pollutant (mercury) determinative or analytical
procedure means a published VCS or EPA method that clearly states that
the standard, practice, or method is appropriate for the pollutant and
the fuel matrix and has a published detection limit equal to or lower
than the methods listed in Table 6 to subpart DDDDD for the same
purpose.
Fabric filter means an add-on air pollution control device used to
capture particulate matter by filtering gas streams through filter
media, also known as a baghouse.
Federally enforceable means all limitations and conditions that are
enforceable by the EPA Administrator, including the requirements of 40
CFR parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
Fuel type means each category of fuels that share a common name or
classification. Examples include, but are not limited to, bituminous
coal, subbituminous coal, lignite, anthracite, biomass, residual oil.
Individual fuel types received from different suppliers are not
considered new fuel types.
Fluidized bed boiler means a boiler utilizing a fluidized bed
combustion process.
Fluidized bed combustion means a process where a fuel is burned in
a bed of granulated particles which are maintained in a mobile
suspension by the forward flow of air and combustion products.
Fuel cell means a boiler type in which the fuel is dropped onto
suspended fixed grates and is fired in a pile. The refractory-lined
fuel cell uses combustion air preheating and positioning of secondary
and tertiary air injection ports to improve boiler efficiency.
Gaseous fuel includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast
furnace gas is exempted from this definition.
Heat input means heat derived from combustion of fuel in a boiler
or process heater and does not include the heat input from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources such as gas turbines, internal combustion engines, kilns, etc.
Hot water heater means a closed vessel with a capacity of no more
than 120 U.S. gallons in which water is heated by combustion of gaseous
or liquid fuel and is withdrawn for use external to the vessel at
pressures not exceeding 160 psig, including the apparatus by which the
heat is generated and all controls and devices necessary to prevent
water temperatures from exceeding 210 [deg] F (99 [deg] C).
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam, hot water,
and/or electricity.
Liquid fuel includes, but is not limited to, distillate oil,
residual oil, on-spec used oil, and biodiesel.
Liquid fuel subcategory includes any boiler or process heater of
any design that burns more than 10 percent liquid fuel and less than 10
percent solid fuel, on an annual heat input basis.
Metal process furnaces include natural gas-fired annealing
furnaces, preheat furnaces, reheat furnaces, aging furnaces, and heat
treat furnaces.
Minimum pressure drop means 90 percent of the test average pressure
drop measured according to Table 7 to this subpart during the most
recent performance test demonstrating compliance with the applicable
emission limit.
Minimum scrubber effluent pH means 90 percent of the test average
effluent pH measured at the outlet of the wet scrubber according to
Table 7 to this subpart during the most recent performance test
demonstrating compliance with the applicable hydrogen chloride emission
limit.
Minimum scrubber flow rate means 90 percent of the test average
flow rate measured according to Table 7 to this subpart during the most
recent performance test demonstrating compliance with the applicable
emission limit.
Minimum sorbent injection rate means 90 percent of the test average
sorbent (or activated carbon) injection rate for each sorbent measured
according to Table 7 to this subpart during the most recent performance
test
[[Page 32065]]
demonstrating compliance with the applicable emission limits.
Minimum voltage or amperage means 90 percent of the test average
voltage or amperage to the electrostatic precipitator measured
according to Table 7 to this subpart during the most recent performance
test demonstrating compliance with the applicable emission limits.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society for
Testing and Materials in ASTM D1835-03a, ``Standard Specification for
Liquid Petroleum Gases'' (incorporated by reference, see Sec.
63.14(b)).
Opacity means the degree to which emissions reduce the transmission
of light and obscure the view of an object in the background.
Particulate matter means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an alternative method.
Period of natural gas curtailment or supply interruption means a
period of time during which the supply of natural gas to an affected
facility is halted for reasons beyond the control of the facility. An
increase in the cost or unit price of natural gas does not constitute a
period of natural gas curtailment or supply interruption.
Process heater means an enclosed device using controlled flame,
that is not a boiler, and the unit's primary purpose is to transfer
heat indirectly to a process material (liquid, gas, or solid) or to a
heat transfer material for use in a process unit, instead of generating
steam. Process heaters are devices in which the combustion gases do not
directly come into contact with process materials. A device combusting
solid waste, as defined in 40 CFR 241.3, is not a process heater.
Process heaters do not include units used for comfort heat or space
heat, food preparation for on-site consumption, or autoclaves.
Pulverized coal boiler means a boiler in which pulverized coal is
introduced into an air stream that carries the coal to the combustion
chamber of the boiler where it is fired in suspension.
Qualified personnel means specialists in evaluating energy systems,
such as those who have successfully completed the DOE Qualified
Specialist program for all systems, Certified Energy Manager certified
by the Association of Energy Engineers, or the equivalent.
Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6,
as defined by the American Society for Testing and Materials in ASTM
D396-02a, ``Standard Specifications for Fuel Oils \1\'' (incorporated
by reference, see Sec. 63.14(b)).
Responsible official means responsible official as defined in 40
CFR 70.2.
Stoker means a unit consisting of a mechanically operated fuel
feeding mechanism, a stationary or moving grate to support the burning
of fuel and admit undergrate air to the fuel, an overfire air system to
complete combustion, and an ash discharge system. There are two general
types of stokers: Underfeed and overfeed. Overfeed stokers include mass
feed and spreader stokers.
Suspension boiler means a unit designed to feed the fuel by means
of fuel distributors. The distributors inject air at the point where
the fuel is introduced into the boiler in order to spread the fuel
material over the boiler width. The drying (and much of the combustion)
occurs while the material is suspended in air. The combustion of the
fuel material is completed on a grate or floor below. Suspension
boilers almost universally are designed to have high heat release rates
to quickly dry the wet fuel as it is blown into the boilers.
Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another. A temporary boiler that remains at a location for
more than 180 consecutive days is no longer considered to be a
temporary boiler. Any temporary boiler that replaces a temporary boiler
at a location and is intended to perform the same or similar function
will be included in calculating the consecutive time period.
Tune-up means adjustments made to a boiler in accordance with
procedures supplied by the manufacturer (or an approved specialist) to
optimize the combustion efficiency.
Unit designed to burn biomass subcategory includes any boiler or
process heater that burns at least 10 percent biomass, but less than 10
percent coal, on a heat input basis on an annual average, either alone
or in combination with liquid fuels or gaseous fuels.
Unit designed to burn coal subcategory includes any boiler or
process heater that burns any coal alone or at least 10 percent coal on
a heat input basis on an annual average in combination with biomass,
liquid fuels, or gaseous fuels.
Unit designed to burn gas 1 (NG/RG) subcategory includes any boiler
or process heater that burns at least 90 percent natural gas and/or
refinery gas on a heat input basis on an annual average.
Unit designed to burn gas 2 (other) subcategory includes any boiler
or process heater that burns gaseous fuels other than natural gas and/
or refinery gas not combined with any solid or liquid fuels.
Unit designed to burn oil subcategory includes any boiler or
process heater that burns any liquid fuel, but less than 10 percent
solid fuel on a heat input basis on an annual average, either alone or
in combination with gaseous fuels. Gaseous fuel boilers and process
heaters that burn liquid fuel during periods of gas curtailment, gas
supply emergencies or for periodic testing of liquid fuel not to exceed
a combined total of 48 hours during any calendar year are not included
in this definition.
Voluntary Consensus Standards or VCS mean technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) developed or adopted by one or more voluntary
consensus bodies. EPA/OAQPS has by precedent only used VCS that are
written in English. Examples of VCS bodies are: American Society of
Testing and Materials (ASTM), American Society of Mechanical Engineers
(ASME), International Standards Organization (ISO), Standards Australia
(AS), British Standards (BS), Canadian Standards (CSA), European
Standard (EN or CEN) and German Engineering Standards (VDI). The types
of standards that are not considered VCS are standards developed by:
The U.S. states, e.g., California (CARB) and Texas (TCEQ); industry
groups, such as American Petroleum Institute (API), Gas Processors
Association (GPA), and Gas Research Institute (GRI); and other branches
of the U.S. government, e.g., Department of Defense (DOD) and
Department of Transportation (DOT). This does not preclude EPA from
using standards developed by groups that are not VCS bodies within
their rule. When this occurs, EPA has done searches and reviews for VCS
equivalent to these non-EPA methods.
Waste heat boiler means a device that recovers normally unused
energy and converts it to usable heat. Waste heat recovery boilers
incorporating duct or supplemental burners that are designed to supply
50 percent or more of the total rated heat input capacity of the waste
heat boiler are not considered waste heat boilers, but are considered
boilers. Waste heat boilers are also referred to as heat recovery steam
generators.
[[Page 32066]]
Waste heat process heater means an enclosed device that recovers
normally unused energy and converts it to usable heat. Waste heat
process heaters incorporating duct or supplemental burners that are
designed to supply 50 percent or more of the total rated heat input
capacity of the waste heat process heater are not considered waste heat
process heaters, but are considered process heaters. Waste heat process
heaters are also referred to as recuperative process heaters.
Wet scrubber means any add-on air pollution control device that
mixes an aqueous stream or slurry with the exhaust gases from a boiler
or process heater to control emissions of particulate matter and/or to
absorb and neutralize acid gases, such as hydrogen chloride.
Work practice standard means any design, equipment, work practice,
or operational standard, or combination thereof, that is promulgated
pursuant to section 112(h) of the CAA.
Tables to Subpart DDDDD of Part 63
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 for New or
Reconstructed Boilers and Process Heaters
------------------------------------------------------------------------
You must meet the
If your boiler or process For the following following emission
heater is in this subcategory pollutants . . . limits and work
. . . practice standards .
. .
------------------------------------------------------------------------
1. Pulverized coal............ a. Particulate 0.001 lb per MMBtu of
Matter. heat input.
b. Hydrogen 0.00006 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 2.0E-06 lb per MMBtu
of heat input.
d. CO............ 90 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.002 ng/dscm (TEQ)
corrected to 7
percent oxygen.
2. Stokers designed to burn a. Particulate 0.001 lb per MMBtu of
coal. Matter. heat input.
b. Hydrogen 0.00006 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 2.0E-06 lb per MMBtu
of heat input.
d. CO............ 7 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.003 ng/dscm (TEQ)
corrected to 7
percent oxygen.
3. Fluidized bed units a. Particulate 0.001 lb per MMBtu of
designed to burn coal. Matter. heat input.
b. Hydrogen 0.00006 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 2.0E-06 lb per MMBtu
of heat input.
d. CO............ 30 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.00003 ng/dscm (TEQ)
corrected to 7
percent oxygen.
4. Stokers designed to burn a. Particulate 0.008 lb per MMBtu of
biomass. Matter. heat input.
b. Hydrogen 0.004 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
d. CO............ of heat input.
560 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.00005 ng/dscm (TEQ)
corrected to 7
percent oxygen.
5. Fluidized bed units a. Particulate 0.008 lb per MMBtu of
designed to burn biomass. Matter. heat input.
b. Hydrogen 0.004 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
of heat input.
d. CO............ 40 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.007 ng/dscm (TEQ)
corrected to 7
percent oxygen.
6. Suspension burners/Dutch a. Particulate 0.008 lb per MMBtu of
Ovens designed to burn Matter. heat input.
biomass. b. Hydrogen 0.004 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
d. CO............ of heat input.
1,010 ppm by volume
on a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.03 ng/dscm (TEQ)
corrected to 7
percent oxygen.
7. Fuel cells designed to burn a. Particulate 0.008 lb per MMBtu of
biomass. Matter. heat input.
b. Hydrogen 0.004 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
d. CO............ of heat input.
270 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.0005 ng/dscm (TEQ)
corrected to 7
percent oxygen.
8. Units designed to burn a. Particulate 0.002 lb per MMBtu of
liquid fuel. Matter. heat input.
b. Hydrogen 0.0004 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 3.0E-07 lb per MMBtu
of heat input.
d. CO............ 1 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.002 ng/dscm (TEQ)
corrected to 7
percent oxygen.
[[Page 32067]]
9. Units designed to burn a. Particulate 0.003 lb per MMBtu of
other gases. Matter. heat input.
b. Hydrogen 3.0E-06 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
d. CO............ of heat input.
1 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.009 ng/dscm (TEQ)
corrected to 7
percent oxygen.
------------------------------------------------------------------------
As stated in Sec. 63.7500, you must comply with the following
applicable emission limits:
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing
Boilers and Process Heaters
[Units with heat input capacity of 10 million Btu per hour or greater]
------------------------------------------------------------------------
You must meet the
If your boiler or process For the following following emission
heater is in this subcategory pollutants . . . limits and work
. . . practice standards .
. .
------------------------------------------------------------------------
1. Pulverized coal............ a. Particulate 0.02 lb per MMBtu of
Matter. heat input.
b. Hydrogen 0.02 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 3.0E-06 lb per MMBtu
of heat input.
d. CO............ 90 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.004 ng/dscm (TEQ)
corrected to 7
percent oxygen.
2. Stokers designed to burn a. Particulate 0.02 lb per MMBtu of
coal. Matter. heat input.
b. Hydrogen 0.02 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 3.0E-06 lb per MMBtu
of heat input.
d. CO............ 50 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.003 ng/dscm (TEQ)
corrected to 7
percent oxygen.
3. Fluidized bed units a. Particulate 0.02 lb per MMBtu of
designed to burn coal. Matter. heat input.
b. Hydrogen 0.02 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 3.0E-06 lb per MMBtu
of heat input.
d. CO............ 30 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.002 ng/dscm (TEQ)
corrected to 7
percent oxygen.
4. Stokers designed to burn a. Particulate 0.02 lb per MMBtu of
biomass. Matter. heat input.
b. Hydrogen 0.006 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 9.0E-07 lb per MMBtu
d. CO............ of heat input.
560 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.004 ng/dscm (TEQ)
corrected to 7
percent oxygen.
5. Fluidized bed units a. Particulate 0.02 lb per MMBtu of
designed to burn biomass. Matter. heat input.
b. Hydrogen 0.006 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 9.0E-07 lb per MMBtu
of heat input.
d. CO............ 250 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.02 ng/dscm (TEQ)
corrected to 7
percent oxygen.
6. Suspension burners/Dutch a. Particulate 0.02 lb per MMBtu of
Ovens designed to burn Matter. heat input.
biomass. b. Hydrogen 0.006 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 9.0E-07 lb per MMBtu
of heat input.
d. CO............ 1,010 ppm by volume
on a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.03 ng/dscm (TEQ)
corrected to 7
percent oxygen.
7. Fuel cells designed to burn a. Particulate 0.02 lb per MMBtu of
biomass. Matter. heat input.
b. Hydrogen 0.006 lb per MMBtu of
Chloride. heat input.
c. Mercury....... 9.0E-07 lb per MMBtu
d. CO............ of heat input.
270 ppm by volume on
a dry basis
corrected to 3
percent oxygen (30-
day rolling average
for units 100 MMBtu/
hr or greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.02 ng/dscm (TEQ)
corrected to 7
percent oxygen.
[[Page 32068]]
8. Units designed to burn a. Particulate 0.004 lb per MMBtu of
liquid fuel. Matter. heat input.
b. Hydrogen 0.0009 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 4.0E-06 lb per MMBtu
of heat input.
d. CO............ 1 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.002 ng/dscm (TEQ)
corrected to 7
percent oxygen.
9. Units designed to burn a. Particulate 0.05 lb per MMBtu of
other gases. Matter. heat input.
b. Hydrogen 3.0E-06 lb per MMBtu
Chloride. of heat input.
c. Mercury....... 2.0E-07 lb per MMBtu
d. CO............ of heat input.
1 ppm by volume on a
dry basis corrected
to 3 percent oxygen
(30-day rolling
average for units
100 MMBtu/hr or
greater, 3-run
average for units
less than 100 MMBtu/
hr).
e. Dioxin/Furan.. 0.009 ng/dscm (TEQ)
corrected to 7
percent oxygen.
------------------------------------------------------------------------
As stated in Sec. Sec. 63.11202 and 63.11203, you must comply with
the following applicable work practice standards:
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
If your boiler is . . . You must meet the following . . .
------------------------------------------------------------------------
1. An existing boiler or Conduct a tune-up of the boiler
process heater with heat biennially as specified in Sec.
input capacity of less than 63.7540.
10 million Btu per hour.
2. A new or existing boiler Conduct a tune-up of the boiler annually
or process heater in either as specified in Sec. 63.7540.
the Gas 1 or Metal Process
Furnace subcategory with
heat input capacity of 10
million Btu per hour or
greater.
3. An existing boiler located Must have an energy assessment performed
at a major source facility. on the major source facility by
qualified personnel which includes:
(a) a visual inspection of the boiler
system.
(b) establish operating characteristics
of the facility, energy system
specifications, operating and
maintenance procedures, and unusual
operating constraints,
(c) identify major energy consuming
systems,
(d) a review of available
architectural and engineering plans,
facility operation and maintenance
procedures and logs, and fuel usage,
(e) a list of major energy
conservation measures,
(f) the energy savings potential of
the energy conservation measures
identified, and
(g) a comprehensive report detailing
the ways to improve efficiency, the
cost of specific improvements,
benefits, and the time frame for
recouping those investments, and
(h) a facility energy management
program developed according to the
ENERGY STAR guideline for energy
management.
------------------------------------------------------------------------
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters
------------------------------------------------------------------------
If you demonstrate compliance You must meet these operating limits . .
using . . . .
------------------------------------------------------------------------
1. Wet scrubber control...... a. Maintain the minimum pressure drop and
liquid flow-rate at or above the
operating levels established during the
performance test according to Sec.
63.7530(c) and Table 7 to this subpart.
2. Fabric filter control..... a. Install and operate a bag leak
detection system according to Sec.
63.7525 and operate the fabric filter
such that the bag leak detection system
alarm does not sound more than 5 percent
of the operating time during each 6-
month period; or
b. This option is for boilers and process
heaters that operate dry control
systems. Existing and new boilers and
process heaters must maintain opacity to
less than or equal to 10 percent (daily
block average).
3. Electrostatic precipitator a. This option is for boilers and process
control. heaters that operate dry control
systems. Existing and new boilers and
process heaters must maintain opacity to
less than or equal to 10 percent opacity
(daily block average); or
[[Page 32069]]
b. This option is only for boilers and
process heaters that operate additional
wet control systems. Maintain the
minimum voltage and secondary current or
total power input of the electrostatic
precipitator at or above the operating
limits established during the
performance test according to Sec.
63.7530(c) and Table 7 to this subpart.
4. Dry scrubber or carbon Maintain the minimum sorbent or carbon
injection control. injection rate at or above the operating
levels established during the
performance test according to Sec.
63.7530(c) and Table 7 to this subpart.
5. Any other control type.... This option is for boilers and process
heaters that operate dry control
systems. Existing and new boilers and
process heaters must maintain opacity to
less than or equal to 10 percent opacity
(daily block average).
6. Fuel analysis............. Maintain the fuel type or fuel mixture
such that the applicable emission rates
calculated according to Sec.
63.7530(d)(3), (4) and/or (5) is less
than the applicable emission limits.
------------------------------------------------------------------------
As stated in Sec. 63.7520, you must comply with the following
requirements for performance test for existing, new or reconstructed
affected sources:
Table 5 to Subpart DDDDD of Part 63--Performance Testing Requirements
------------------------------------------------------------------------
To conduct a performance test
for the following pollutant . You must . . . Using . . .
. .
------------------------------------------------------------------------
1. Particulate Matter......... a. Select Method 1 in appendix
sampling ports A to part 60 of this
location and the chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the chapter.
stack gas.
c. Determine Method 3A or 3B in
oxygen and appendix A to part
carbon dioxide 60 of this chapter,
concentrations or ASME PTC 19, Part
of the stack gas. 10 (1981) (IBR, see
Sec. 63.14(i)).
d. Measure the Method 4 in appendix
moisture content A to part 60 of this
of the stack gas. chapter.
e. Measure the Method 5 or 17
particulate (positive pressure
matter emission fabric filters must
concentration. use Method 5D) in
appendix A to part
60 of this chapter.
f. Convert Method 19 F-factor
emissions methodology in
concentration to appendix A to part
lb per MMBtu 60 of this chapter.
emission rates.
2. Hydrogen chloride.......... a. Select Method 1 in appendix
sampling ports A to part 60 of this
location and the chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the chapter.
stack gas.
c. Determine Method 3A or 3B in
oxygen and appendix A to part
carbon dioxide 60 of this chapter,
concentrations or ASME PTC 19, Part
of the stack gas. 10 (1981) (IBR, see
Sec. 63.14(i)).
d. Measure the Method 4 in appendix
moisture content A to part 60 of this
of the stack gas. chapter.
e. Measure the Method 26 or 26A in
hydrogen appendix A to part
chloride 60 of this chapter.
emission
concentration.
f. Convert Method 19 F-factor
emissions methodology in
concentration to appendix A to part
lb per MMBtu 60 of this chapter.
emission rates.
3. Mercury.................... a. Select Method 1 in appendix
sampling ports A to part 60 of this
location and the chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the chapter.
stack gas.
c. Determine Method 3A or 3B in
oxygen and appendix A to part
carbon dioxide 60 of this chapter,
concentrations or ASME PTC 19, Part
of the stack gas. 10 (1981) (IBR, see
Sec. 62.14(i)).
d. Measure the Method 4 in appendix
moisture content A to part 60 of this
of the stack gas. chapter.
e. Measure the Method 29 in appendix
mercury emission A to part 60 of this
concentration. chapter or Method
101A in appendix B
to part 61 of this
chapter or ASTM
Method D6784-02
(IBR, see Sec.
63.14(b)).
f. Convert Method 19 F-factor
emissions methodology in
concentration to appendix A to part
lb per MMBtu 60 of this chapter.
emission rates.
4. CO......................... a. Select the Method 1 in appendix
sampling ports A to part 60 of this
location and the chapter.
number of
traverse points.
b. Determine Method 3A or 3B in
oxygen and appendix A to part
carbon dioxide 60 of this chapter,
concentrations or ASTM D6522-00
of the stack gas. (IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part 10
(1981) (IBR, see
Sec. 63.14(i)).
c. Measure the Method 4 in appendix
moisture content A to part 60 of this
of the stack gas. chapter.
d. Measure the CO Method 10 in appendix
emission A to part 60 of this
concentration. chapter.
5. Dioxin/Furan............... a. Select the Method 1 in appendix
sampling ports A to part 60 of this
location and the chapter.
number of
traverse points.
[[Page 32070]]
b. Determine Method 3A or 3B in
oxygen and appendix A to part
carbon dioxide 60 of this chapter,
concentrations or ASTM D6522-00
of the stack gas. (IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part 10
(1981) (IBR, see
Sec. 63.14(i)).
c. Measure the Method 4 in appendix
moisture content A to part 60 of this
of the stack gas. chapter.
d. Measure the Method -- in appendix
dioxin/furans A to part 60 of this
emission chapter.
concentration.
------------------------------------------------------------------------
As stated in Sec. 63.7521, you must comply with the following
requirements for fuel analysis testing for existing, new or
reconstructed affected sources. However, equivalent methods may be used
in lieu of the prescribed methods at the discretion of the source owner
or operator:
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
To conduct a fuel analysis for
the following pollutant . . . You must . . . Using . . .
------------------------------------------------------------------------
1. Mercury.................... a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D2234-D2234M-03 (for
coal) (IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003) (for
biomass) (IBR, See
Sec. 63.14(b)) or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or SW-
samples. 846-3020A (for
liquid samples) or
ASTM D2013-04 (for
coal) (IBR, see Sec.
63.14(b)) or ASTM
D5198-92 (2003) (for
biomass) (IBR, see
Sec. 63.14(b)) or
equivalent.
d. Determine heat ASTM D5865-04 (for
content of the coal) (IBR, see Sec.
fuel type. 63.24(b)) or ASTM
E711-87 (for
biomass) (IBR, see
Sec. 63.14(b)) or
equivalent.
e. Determine ASTM D3173-03 (IBR,
moisture content see Sec. 63.14(b))
of the fuel type. or ASTM E871-82
(1998) (IBR, see
Sec. 63.14(b)) or
equivalent.
f. Measure ASTM D6722-01 (for
mercury coal) (IBR, see Sec.
concentration in 6314(b)) or SW-846-
fuel sample. 7471A (for solid
samples) or SW-846-
7470A (for liquid
samples or
equivalent.
g. Convert .....................
concentration
into units of
pounds of
pollutant per
MMBtu of heat
content.
2. Hydrogen Chloride.......... a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D2234-D2234M-03 (for
coal) (IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003) (for
biomass) (IBR, see
Sec. 63.14(b)) or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or SW-
samples. 846-3020A (for
liquid samples) or
ASTM D2013-04 (for
coal) (IBR, see Sec.
63.14(b)) or ASTM
D5198-92 (2003) (for
biomass) (IBR, see
Sec. 63.14(b)) or
equivalent.
d. Determine heat ASTM D5865-04 (for
content of the coal) (IBR, see Sec.
fuel type * * *. 63.14(b)) or ASTM
E711-87 (1996) (for
biomass) (IBR, see
Sec. 63.14(b)) or
equivalent.
e. Determine ASTM D3173-03 (IBR,
moisture content see Sec. 63.14(b))
of the fuel type. or ASTM E871-82
(1998) or
equivalent.
f. Measure SW-846-9250 or ASTM
chlorine D6721-01 (for coal)
concentration in or ASTM E776-87
fuel sample. (1996) (for biomass)
(IBR, see Sec.
63.14(b)) or
equivalent.
g. Convert .....................
concentrations
into units of
pounds of
pollutant per
MMBtu of heat
content.
------------------------------------------------------------------------
As stated in Sec. 63.7520, you must comply with the following
requirements for establishing operating limits:
[[Page 32071]]
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
And your operating According to the
If you have an applicable limits are based You must . . . Using . . . following
emission limit for . . . on . . . requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Particulate matter or mercury a. Wet scrubber i. Establish a (1) Data from the (a) You must
operating site-specific pressure drop and collect pressure
parameters. minimum pressure liquid flow rate drop and liquid
drop and minimum monitors and the flow-rate data
flow rate particulate every 15 minutes
operating limit matter or mercury during the entire
according to Sec. performance test. period of the
63.7530(c). performance
tests;
(b) Determine the
average pressure
drop and liquid
flow-rate for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during each test
run.
b. Electrostatic i. Establish a (1) Data from the (a) You must
precipitator site-specific pressure drop and collect voltage
operating minimum voltage liquid flow rate and secondary
parameters and secondary monitors and the current or total
(option only for current or total particulate power input data
units with power input matter or mercury every 15 minutes
additional wet according to Sec. performance test. during the entire
scrubber control). 63.7530(c). period of the
performance
tests;
(b) Determine the
average voltage
and secondary
current or total
power input for
each individual
test run in the
three-run
performance test
by computing the
average of all
the 15-minute
readings taken
during each test
run.
2. Hydrogen Chloride............ a. Wet scrubber i. Establish a (1) Data from the (a) You must
operating site-specific pH, pressure collect pH,
parameters. minimum pressure drop, and liquid pressure drop,
drop and minimum flow-rate and liquid flow-
flow rate monitors and the rate data every
operating limit hydrogen chloride 15 minutes during
according to Sec. performance test. the entire period
63.7530(c). of the
performance
tests;
(b) Determine the
average pH,
pressure drop,
and liquid flow-
rate for each
individual test
run in the three-
run performance
test by computing
the average of
all the 15-minute
readings taken
during each test
run.
b. Dry scrubber i. Establish a (1) Data from the (a) You must
operating site-specific sorbent injection collect sorbent
parameters. minimum sorbent rate monitors and injection rate
injection rate hydrogen chloride data every 15
operating limit performance test. minutes during
according to Sec. the entire period
63.7530(c). of the
performance
tests;
(b) Determine the
average sorbent
injection rate
for each
individual test
run in the three-
run performance
test by computing
the average of
all the 15-minute
readings taken
during each test
run.
----------------------------------------------------------------------------------------------------------------
As stated in Sec. 63.7540, you must show continuous compliance
with the emission limitations for affected sources according to the
following:
[[Page 32072]]
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
If you must meet the following
operating limits or work practice You must demonstrate continuous
standards . . . compliance by . . .
------------------------------------------------------------------------
1. Opacity........................ a. Collecting the opacity monitoring
system data according to Sec. Sec.
63.7525(b) and 63.7535; and
b. Reducing the opacity monitoring
data to 6-minute averages; and
c. Maintaining opacity to less than
or equal to 10 percent (daily block
average).
2. Fabric Filter Bag Leak Installing and operating a bag leak
Detection Operation. detection system according to Sec.
63.7525 and operating the fabric
filter such that the requirements
in Sec. 63.7540(a)(9) are met.
3. Wet Scrubber Pressure Drop and a. Collecting the pressure drop and
Liquid Flow-rate. liquid flow rate monitoring system
data according to Sec. Sec.
63.7525 and 63.7535; and
b. Reducing the data to 12-hour
block averages; and
c. Maintaining the 12-hour average
pressure drop and liquid flow-rate
at or above the operating limits
established during the performance
test according to Sec.
63.7530(c).
4. Wet Scrubber pH................ a. Collecting the pH monitoring
system data according to Sec. Sec.
63.7525 and 63.7535; and
b. Reducing the data to 12-hour
block averages; and
c. Maintaining the 12-hour average
pH at or above the operating limit
established during the performance
test according to Sec.
63.7530(c).
5. Dry Scrubber Sorbent or Carbon a. Collecting the sorbent or carbon
Injection Rate. injection rate monitoring system
data for the dry scrubber according
to Sec. Sec. 63.7525 and
63.7535; and
b. Reducing the data to 12-hour
block averages; and
c. Maintaining the 12-hour average
sorbent or carbon injection rate at
or above the operating limit
established during the performance
test according to Sec. Sec.
63.7530(c).
6. Electrostatic Precipitator a. Collecting the secondary current
Secondary Current and Voltage or and voltage or total power input
Total Power Input. monitoring system data for the
electrostatic precipitator
according to Sec. Sec. 63.7525
and 63.7535; and
b. Reducing the data to 12-hour
block averages; and
c. Maintaining the 12-hour average
secondary current and voltage or
total power input at or above the
operating limits established during
the performance test according to
Sec. Sec. 63.7530(c).
7. Fuel Pollutant Content......... a. Only burning the fuel types and
fuel mixtures used to demonstrate
compliance with the applicable
emission limit according to Sec.
63.7530(c) or (d) as applicable;
and
b. Keeping monthly records of fuel
use according to Sec. 63.7540(a).
------------------------------------------------------------------------
As stated in Sec. 63.7550, you must comply with the following
requirements for reports:
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
------------------------------------------------------------------------
The report must You must submit
You must submit a(n) . . . contain . . . the report . . .
------------------------------------------------------------------------
1. Compliance report............ a. Information Semiannually
required in Sec. according to the
63.7550(c)(1) requirements in
through (11); and Sec.
63.7550(b).
b. If there are no ..................
deviations from
any emission
limitation
(emission limit
and operating
limit) that
applies to you
and there are no
deviations from
the requirements
for work practice
standards in
Table 8 to this
subpart that
apply to you, a
statement that
there were no
deviations from
the emission
limitations and
work practice
standards during
the reporting
period. If there
were no periods
during which the
CMSs, including
continuous
emissions
monitoring
system,
continuous
opacity
monitoring
system, and
operating
parameter
monitoring
systems, were out-
of-control as
specified in Sec.
63.8(c)(7), a
statement that
there were no
periods during
which the CMSs
were out-of-
control during
the reporting
period; and
[[Page 32073]]
c. If you have a ..................
deviation from
any emission
limitation
(emission limit
and operating
limit) or work
practice standard
during the
reporting period,
the report must
contain the
information in
Sec.
63.7550(d). If
there were
periods during
which the CMSs,
including
continuous
emissions
monitoring
system,
continuous
opacity
monitoring
system, and
operating
parameter
monitoring
systems, were out-
of-control, as
specified in Sec.
63.8(c)(7), the
report must
contain the
information in
Sec.
63.7550(e); and
d. If you had a ..................
startup,
shutdown, or
malfunction
during the
reporting period
and you took
actions
consistent with
your startup,
shutdown, and
malfunction plan,
the compliance
report must
include the
information in
Sec.
63.10(d)(5)(i).
2. An immediate startup, a. Actions taken i. By fax or
shutdown, and malfunction for the event; telephone within
report if you had a startup, and 2 working days
shutdown, or malfunction during b. The information after starting
the reporting period that is in Sec. actions
not consistent with your 63.10(d)(5)(ii). inconsistent with
startup, shutdown, and the plan; and
malfunction plan, and the ii. By letter
source exceeds any applicable within 7 working
emission limitation in the days after the
relevant emission standard. end of the event
unless you have
made alternative
arrangements with
the permitting
authority.
------------------------------------------------------------------------
As stated in Sec. 63.7565, you must comply with the applicable
General Provisions according to the following:
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD
------------------------------------------------------------------------
Applies to subpart
Citation Subject DDDDD
------------------------------------------------------------------------
Sec. 63.1................. Applicability....... Yes.
Sec. 63.2................. Definitions......... Yes. Additional
terms defined in
Sec. 63.7575.
Sec. 63.3................. Units and Yes.
Abbreviations.
Sec. 63.4................. Prohibited Yes.
Activities and
Circumvention.
Sec. 63.5................. Preconstruction Yes.
Review and
Notification
Requirements.
Sec. 63.6(a), (b)(1)- Compliance with Yes.
(b)(5), (b)(7), (c), (f)(2)- Standards and
(3), (g), (h)(2)-(h)(9), Maintenance
(i), (j). Requirements.
Sec. 63.6(e)(1), (e)(3), Startup, shutdown, No. Standards apply
(f)(1), and (h)(1). and malfunction at all times,
requirements and including during
Opacity/Visible startup, shutdown,
Emission Limits. and malfunction
events.
Sec. 63.7(a), (b), (c), Performance Testing Yes.
(d), (e)(2)-(e)(9), (f), Requirements.
(g), and (h).
Sec. 63.7(e)(1)........... Conditions for No. Subpart DDDDD
conducting specifies
performance tests.. conditions for
conducting
performance tests
at Sec. 63.7520.
Sec. 63.8................. Monitoring Yes.
Requirements.
Sec. 63.9................. Notification Yes.
Requirements.
Sec. 63.10(a), (b)(1), Recordkeeping and Yes.
(b)(2)(i)-(iii), (b)(2)(vi)- Reporting
(xiv), (c), (d)(1)-(2), Requirements.
(e), and (f).
Sec. 63.10(b)(2)(iv)-(v), .................... No.
(b)(3), and (d)(3)-(5).
Sec. 63.10(c)(15)......... Allows use of SSM No.
plan.
Sec. 63.11................ Control Device No.
Requirements.
Sec. 63.12................ State Authority and Yes.
Delegation.
Sec. 63.13-63.16.......... Addresses, Yes.
Incorporation by
Reference,
Availability of
Information,
Performance Track
Provisions.
Sec. 63.1(a)(5), (a)(7)- Reserved............ No.
(a)(9), (b)(2), (c)(3)-(4),
(d), 63.6(b)(6), (c)(3),
(c)(4), (d), (e)(2),
(e)(3)(ii), (h)(3),
(h)(5)(iv), 63.8(a)(3),
63.9(b)(3), (h)(4),
63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------
[FR Doc. 2010-10827 Filed 6-3-10; 8:45 am]
BILLING CODE 6560-50-P