[Federal Register Volume 75, Number 107 (Friday, June 4, 2010)]
[Proposed Rules]
[Pages 31896-31935]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-10832]
[[Page 31895]]
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Part III
Environmental Protection Agency
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40 CFR Part 63
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National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers; Proposed
Rule
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed
Rules
[[Page 31896]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2006-0790; FRL-9148-3]
RIN 2060-AM44
National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing national emission standards for control of
hazardous air pollutants from two area source categories: Industrial
boilers and commercial and institutional boilers. The proposed emission
standards for control of mercury emissions from coal-fired area source
boilers and the proposed emission standards for control of polycyclic
organic matter emissions from all area source boilers are based on the
maximum achievable control technology. The proposed emission standards
for control of mercury emissions from biomass-fired and oil-fired area
source boilers and for other hazardous air pollutants are based on
EPA's proposed determination as to what constitutes the generally
available control technology or management practices.
EPA is also clarifying that gas-fired area source boilers are not
needed to meet the 90 percent requirement of section 112(c)(3) of the
Clean Air Act.
Finally, we are also proposing that existing area source facilities
with an affected boiler with a designed heat input capacity of 10
million Btu per hour or greater 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 major 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-2006-0790, 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-2006-
0790.
Fax: Fax your comments to: (202) 566-9744, Docket ID No.
EPA-HQ-OAR-2006-0790.
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-2006-0790.
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/DC), EPA West, Room 3334, 1301 Constitution Ave.,
NW., Washington, DC 20460. Attention Docket ID No. EPA-HQ-OAR-2006-
0790. 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: Ms. Mary Johnson, 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)
541-5025; Fax number (919) 541-5450; e-mail address:
[email protected].
SUPPLEMENTARY INFORMATION:
[[Page 31897]]
Outline. The information in this preamble is organized as follows:
I. General Information
A. Does this action apply to me?
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 and regulatory approach for
this proposed rule?
B. What source categories are affected by the proposed
standards?
C. What is the relationship between this proposed rule and other
related national emission standards?
D. How did we gather information for this proposed rule?
E. How are the area source boiler HAP addressed by this proposed
rule?
III. Clarification of the Source Category List
IV. Summary of This Proposed Rule
A. Do the proposed standards apply to my source?
B. What is the affected source?
C. When must I comply with the proposed standards?
D. What are the proposed MACT and GACT standards?
E. What are the Startup, Shutdown, and Malfunction (SSM)
requirements?
F. What are the proposed initial compliance requirements?
G. What are the proposed continuous compliance requirements?
H. What are the proposed notification, recordkeeping and
reporting requirements?
I. Submission of Emissions Test Results to EPA
V. Rationale of This Proposed Rule
A. How did EPA determine which pollution sources would be
regulated under this proposed rule?
B. How did EPA determine the subcategories for this proposed
rule?
C. What surrogates are we using?
D. How did EPA determine the proposed standards for existing
units?
1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
2. GACT Determination for Existing Area Source Boilers
E. How did EPA determine the proposed standards for new units?
1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
2. GACT Determination for New Area Source Boilers
F. How did we select the compliance requirements?
G. Alternative MACT Standards for Consideration
H. How did we decide to exempt these area source categories from
title V permitting requirements?
VI. Summary of the Impacts of This Proposed Rule
A. What are the air impacts?
B. What are the cost impacts?
C. What are the economic impacts?
D. What are the social costs and benefits of this proposed rule?
E. What are the water and solid waste impacts?
F. What are the energy impacts?
VII. Relationship of This Proposed Action to CAA Section 112(c)(6)
VIII. Statutory and Executive Order Review
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act of 1995
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. 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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Examples of regulated
Category NAICS Code \1\ entities
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Any area source facility using 321 Wood product
a boiler as defined in this manufacturing.
proposed rule.
11 Agriculture,
greenhouses.
311 Food manufacturing.
327 Nonmetallic mineral
product
manufacturing.
422 Wholesale trade,
nondurable goods.
531 Real estate.
611 Educational services.
813 Religious, civic,
professional, and
similar
organizations.
92 Public administration.
722 Food services and
drinking places.
62 Health care and social
assistance.
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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 63.11193 of subpart JJJJJJ
(National Emission Standards for Hazardous Air Pollutants for
Industrial, Commercial, and Institutional Boilers Area Sources). If you
have any questions regarding the applicability of this action to a
particular entity, consult either the delegated regulatory 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. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711, Attention: Docket ID EPA-HQ-OAR-2006-0790.
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.
[[Page 31898]]
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 Worldwide 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 and regulatory approach for this
proposed rule?
Section 112(d) of the Clean Air Act (CAA) requires us to establish
NESHAP for both major and area sources of hazardous air pollutants
(HAP) that are listed for regulation under CAA section 112(c). A major
source emits or has the potential to emit 10 tons per year (tpy) or
more of any single HAP or 25 tpy or more of any combination of HAP. An
area source is a HAP-emitting stationary source that is not a major
source.
CAA section 112(k)(3)(B) calls for EPA to identify at least 30 HAP
which, as the result of emissions from area sources, pose the greatest
threat to public health in the largest number of urban areas. EPA
implemented this provision in 1999 in the Integrated Urban Air Toxics
Strategy (Strategy), (64 FR 38715, July 19, 1999). Specifically, in the
Strategy, EPA identified 30 HAP that pose the greatest potential health
threat in urban areas, and these HAP are referred to as the ``30 urban
HAP.'' CAA section 112(c)(3) requires EPA to list sufficient categories
or subcategories of area sources to ensure that area sources
representing 90 percent of the emissions of the 30 urban HAP are
subject to regulation. A primary goal of the Strategy is to achieve a
75 percent reduction in cancer incidence attributable to HAP emitted
from stationary sources.
Under CAA section 112(d)(5), we may elect to promulgate standards
or requirements for area sources ``which provide for the use of
generally available control technologies or management practices
(`GACT') by such sources to reduce emissions of hazardous air
pollutants.'' Additional information on GACT is found in the Senate
report on the legislation (Senate Report Number 101-228, December 20,
1989), which describes GACT as:
* * * methods, practices and techniques which are commercially
available and appropriate for application by the sources in the
category considering economic impacts and the technical capabilities
of the firms to operate and maintain the emissions control systems.
Consistent with the legislative history, we can consider costs and
economic impacts in determining GACT, which is particularly important
when developing regulations for source categories that may have many
small businesses such as these.
Determining what constitutes GACT involves considering the control
technologies and management practices that are generally available to
the area sources in the source category. We also consider the standards
applicable to major sources in the analogous source category to
determine if the control technologies and management practices are
transferable and generally available to area sources. In appropriate
circumstances, we may also consider technologies and practices at area
and major sources in similar categories to determine whether such
technologies and practices could be considered generally available for
the area source categories at issue. Finally, as noted above, in
determining GACT for a particular area source category, we consider the
costs and economic impacts of available control technologies and
management practices on that category.
While GACT may be a basis for standards for most types of HAP
emitted from area sources, CAA section 112(c)(6) requires that EPA list
categories and subcategories of sources assuring that sources
accounting for not less than 90 percent of the aggregate emissions of
each of the seven specified hazardous air pollutants (HAP) are subject
to standards under section 112(d)(2) or (d)(4). The seven HAP specified
in section 112(c)(6) are as follows: alkylated lead compounds,
polycyclic organic matter, hexachlorobenzene, mercury, polychlorinated
biphenyls, 2,3,7,9-tetrachlorodibenzofurans, and 2,3,7,8-
tetrachloridibenzo-p-dioxin.
The CAA section 112(c)(6) list of source categories currently
includes industrial coal combustion, industrial oil combustion,
industrial wood combustion, commercial coal combustion, commercial oil
combustion, and commercial wood combustion. See 63 FR 17849. We listed
these source categories under CAA section 112(c)(6) based on the source
categories' contribution of mercury and polycyclic organic matter
(POM). In the documentation for the CAA section 112(c)(6) listing, the
commercial fuel combustion categories included institutional fuel
combustion (see ``1990 Emissions Inventory of Section 112(c)(6)
Pollutants, Final Report,'' April 1998). As discussed in greater detail
below, we re-examine the emission inventory and the need to address
categories under CAA section 112(c)(6) during the rule development
process. Based on this re-examination, we now believe we will only need
to address the coal-fueled portion of these categories under CAA
section 112(c)(6).
With this proposed rule and the major source boilers rule, we
currently believe that we have subjected to regulation or proposed to
regulate at least 90 percent of the 1990 section 112(c)(6) emissions
inventory for mercury. Coal-fired area source boilers represent
approximately 4.3 percent of the 1990 section 112(c)(6) emissions
inventory for mercury. In contrast, biomass- and oil-fired boilers
represent approximately 0.34 percent. Consequently, we are proposing to
regulate coal-fired boilers under MACT because we need these sources to
meet the 90 percent requirement for mercury in section 112(c)(6). We
are proposing to regulate biomass-fired and oil-fired types of boilers
under GACT to meet the 90 percent requirement for mercury in section
112(c)(3).
We solicit comment on whether we should nevertheless establish
MACT-based mercury emission standards for all boilers in this category.
In your comments, please explain the basis for your position and
provide any supporting documentation.
The ``maximum achievable control technology'' or ``MACT''
regulation required by CAA section 112(d)(2) or (4) can be based on the
emissions reductions achievable through application of measures,
processes, methods, systems, or techniques including, but not limited
to: (1)
[[Page 31899]]
Reducing the volume of, or eliminating emissions of, such pollutants
through process changes, substitutions of materials, or other
modifications; (2) enclosing systems or processes to eliminate
emissions; (3) collecting, capturing, or treating such pollutants when
released from a process, stack, storage or fugitive emission point; (4)
design, equipment, work practices, or operational standards as provided
in CAA section 112(h); or (5) a combination of the above.
The MACT floor is the minimum control level allowed for NESHAP and
is defined under CAA section 112(d)(3). For new sources, MACT based
standards cannot be less stringent than the emission control achieved
in practice by the best-controlled similar source, as determined by the
Administrator. The MACT based standards for existing sources can be
less stringent than standards for new sources, but they cannot be less
stringent than the average emission limitation achieved by the best
performing 12 percent of existing sources in the category or
subcategory (for which the Administrator has emission information) for
source categories and subcategories with 30 or more sources, or the
best performing 5 sources for categories and subcategories with fewer
than 30 sources (CAA section 112(d)(3)(A) and (B)).
Although emission standards are often structured in terms of
numerical emissions limits, alternative approaches are sometimes
necessary and authorized pursuant to CAA section 112. For example, in
some cases, physically measuring emissions from a source may be not
practicable due to technological and economic limitations. CAA section
112(h) authorizes the Administrator to promulgate a design, equipment,
work practice, or operational standard, or combination thereof,
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 prescribe or enforce an emission standard. CAA section 112(h)(2)
provides that the phrase ``not feasible to prescribe or enforce an
emission standard'' includes the situation in which the Administrator
determines that * * * the application of measurement methodology to a
particular class of sources is not practicable due to technological and
economic limitations.
As noted above, we listed industrial coal combustion, industrial
oil combustion, industrial wood combustion, commercial coal combustion,
commercial oil combustion, and commercial wood combustion under CAA
section 112(c)(6) based on the source categories' contribution of
mercury and polycyclic organic matter (POM). We listed these same
categories under section 112(c)(3) for their contribution of mercury,
arsenic, beryllium, cadmium, lead, chromium, manganese, nickel,
polycyclic organic matter (POM) (as 7-PAH (polynuclear aromatic
hydrocarbons)), ethylene dioxide, and polychlorinated biphenyls (PCB).
We have developed proposed standards to reflect the application of
MACT for mercury from coal-fired area source boilers and POM from all
area source boilers under section 112(c)(6) and have applied GACT for
the other pollutants noted above.
B. What source categories are affected by the proposed standards?
The source categories affected by the proposed standards are
industrial boilers and commercial and institutional boilers. Both
source categories were included in the area source list published on
July 19, 1999 (64 FR 38721). The inclusion of these two source
categories on the CAA section 112(c)(3) area source category list is
based on 1990 emissions data, as EPA used 1990 as the baseline year for
that listing. We describe above the pollutants that formed the basis of
the listings.
This proposed rule would apply to all existing and new industrial
boilers, institutional boilers, and commercial boilers located at area
sources. The industrial boiler source category includes boilers used in
manufacturing, processing, mining, refining, or any other industry. The
commercial boiler source category includes boilers used in commercial
establishments such as stores/malls, laundries, apartments,
restaurants, and hotels/motels. The institutional boiler source
category includes boilers used in medical centers (e.g., hospitals,
clinics, nursing homes), educational and religious facilities (e.g.,
schools, universities, churches), and municipal buildings (e.g.,
courthouses, prisons).
Boiler means an enclosed combustion device having the primary
purpose of recovering thermal energy in the form of steam or hot water.
C. What is the relationship between this proposed rule and other
related national emission standards?
This proposed rule regulates industrial boilers and institutional/
commercial boilers that are area sources of HAP. Today, in a parallel
action, a NESHAP for industrial, commercial, and institutional boilers
located at major sources is being proposed reflecting application of
MACT. The major source NESHAP regulates emissions of particulate matter
(PM) (as a surrogate for non-mercury metals), mercury, hydrogen
chloride (HCl)(as a surrogate for acid gases), dioxins/furans, and
carbon monoxide (CO) (as a surrogate for non-dioxin organic HAP) from
existing and new major source boilers.
This proposed rule covers boilers located at area source
facilities. In addition to the major source MACT for boilers being
issued today and this rule, the Agency is also issuing emission
standards today pursuant to CAA section 129 for commercial and
industrial solid waste incineration units. In a parallel action, EPA is
proposing a solid waste definition rulemaking pursuant to Subtitle D of
RCRA. That action is relevant to this proceeding because if an
industrial, commercial, or institutional unit located at an area source
combusts secondary materials that are ``solid waste,'' as that term is
defined by the Administrator under RCRA, those units would be subject
to section 129 of the CAA, not section 112.
As background, in 2007, the United States Court of Appeals for the
District of Columbia Circuit (DC Circuit) vacated the CISWI Definitions
Rule, which EPA issued pursuant to CAA section 129. The court found
that the definitions in that rule were inconsistent with the CAA.
Specifically, the Court held that the term ``solid waste incineration
unit'' in CAA Section 129(g)(1) ``unambiguously include[s] 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 at 1257-58.
Based on the information available to the Agency, we believe that
the boilers that are subject to this area source rule combust coal,
oil, and biomass. EPA does not believe that the boilers subject to this
rule combust any non-hazardous secondary materials, whether they are
considered a solid waste or not. If you are aware of such materials
being combusted at these boilers, please provide specific information
as to the type of secondary material being combusted and at what type
of facilities and in what quantities. If the final form of the solid
waste definition results in any secondary materials being considered
solid waste it will be important to know whether units are burning
those materials, because that would result in those units becoming
incinerators subject to regulation under
[[Page 31900]]
section 129 and no longer being considered boilers.
There is also another CAA regulation that is relevant in that they
apply to some of the affected sources in this rule. For example, in
1986, EPA codified new source performance standards (NSPS) for
industrial, commercial, and institutional boilers (40 CFR part 60,
subparts Db and Dc) and revised portions of them in 1999 and 2006. The
NSPS regulates emissions of PM, sulfur dioxide (SO2), and
nitrogen oxides from boilers constructed after June 19, 1984. Sources
subject to the NSPS that are located at area source facilities are also
subject to this proposed rule because this proposed rule regulates HAP.
In developing this proposal, we have streamlined the monitoring and
recordkeeping requirements to avoid duplicating requirements in the
NSPS.
D. How did we gather information for this proposed rule?
We gathered information for this proposed rule from States' boiler
inspection lists, company Web sites, published literature, State
permits, current State and Federal regulations, and from an Information
Collection Request (ICR) conducted for the major source NESHAP.
We developed an initial nationwide population of area source
boilers based on boiler inspector databases from 13 States. The boiler
inspector databases include steam boilers that are required to be
inspected for safety or insurance purposes. We classified the area
source boilers to NAICS codes based on the ``name'' of the facility at
which the boiler was located. However, many of the boilers in the
boiler inspector database could not be readily assigned to an NAICS
code.
We reviewed State and other Federal regulations that apply to the
area sources in the source categories for information concerning
existing HAP emission control approaches. For example, as noted above,
the NSPS for small industrial, commercial, and institutional boilers in
40 CFR part 60, subpart Dc apply to boilers at some area sources.
Similarly, permit requirements established by the Ohio, Illinois,
Vermont, New Hampshire, and Maine air regulatory agencies apply to some
area sources. We also reviewed standards for boilers at major sources
that would be appropriate for and transferable to boilers at area
sources. For example, we determined that management practices, such as,
annual tune-ups and operator training applicable to major source
boilers are equally feasible for boilers at area sources.
E. How are the area source boiler HAP addressed by this proposed rule?
As explained above, industrial coal combustion, industrial oil
combustion, industrial wood combustion, commercial coal combustion,
commercial oil combustion, and commercial wood combustion are listed
under CAA section 112(c)(6) due to contributions of mercury and POM and
these same categories are listed under CAA section 112(c)(3) for their
contribution of mercury, arsenic, beryllium, cadmium, lead, chromium,
manganese, nickel, POM, ethylene dioxide, and PCB.
With respect to the 112(c)(3) pollutants, we used surrogates
because, as explained below, it was not practical to establish
individual standards for each specific HAP. We grouped the 112(c)(3)
pollutants, which formed the basis for the listing of these two source
categories, into three common groupings: mercury, non-mercury metallic
HAP (arsenic, beryllium, cadmium, chromium, lead, manganese, and
nickel), and organic HAP (POM, ethylene dichloride, and PCB). In
general, the pollutants within each group have similar characteristics
and can be controlled with the same techniques.
For the non-mercury metallic HAP, we selected PM as a surrogate.
The inherent variability and unpredictability of the non-mercury metal
HAP compositions and amounts in fuel has a material effect on the
composition and amount of non-mercury metal HAP in the emissions from
the boiler. As a result, establishing individual numerical emissions
limits for each non-mercury HAP metal species is difficult given the
level of uncertainty about the individual non-mercury metal HAP
compositions of the fuels that will be combusted. An emission
characteristic common to all boilers is that the non-mercury metal HAP
are a component of the PM contained in the fly ash emitted from the
boiler. A sufficient correlation exists between PM and non-mercury
metallic HAP to rely on PM as a surrogate for these HAP and for their
control. Therefore, the same control techniques that would be used to
control the fly-ash PM will control non-mercury metallic HAP. Emissions
limits established to achieve control of PM will also achieve control
of non-mercury metal HAP. Furthermore, establishing separate standards
for each individual HAP would impose costly and significantly more
complex compliance and monitoring requirements and achieve little, if
any, HAP emissions reductions beyond what would be achieved using the
surrogate pollutant approach.
For organic HAP, we selected CO as a surrogate for organic
compounds, including POM, emitted from the various fuels burned in
boilers. The presence of CO is an indicator of incomplete combustion. A
high level of CO in emissions is an indicator of incomplete combustion
and, thus, a potential indication of elevated organic HAP emissions.
Monitoring equipment for CO is readily available, which is not the case
for organic HAP. Also, it is significantly easier and less expensive to
measure and monitor CO emissions than to measure and monitor emissions
of each individual organic HAP. We considered other surrogates, such as
total hydrocarbon (THC), but lacked data on emissions and permit limits
for area source boilers. Therefore, using CO as a surrogate for organic
urban HAP is a reasonable approach because minimizing CO emissions will
result in minimizing organic urban HAP emissions.
Based on these considerations, we are proposing GACT standards for
PM (as a surrogate for the individual urban metal HAP), CO (as a
surrogate pollutant for the individual urban organic HAP), and mercury
from biomass-fired and oil-fired boilers. We are proposing MACT
standards for mercury from coal-fired boilers and for POM from all
boilers.
III. Clarification of the Source Category List
The Industrial Boilers and the Institutional/Commercial Boilers
area source categories were listed under section 112(c)(3) of the CAA.
EPA needs to establish emission standards for area source boilers for
the following urban HAP in order to meet the section 112(c)(3) 90
percent requirement for these HAP: mercury, arsenic, beryllium,
cadmium, lead, chromium, manganese, nickel, POM (as 7-PAH), ethylene
dioxide, and PCB. Natural gas-fired area source boilers do not emit any
of the urban HAP identified above. Therefore, regulation of gas-fired
area source boilers is not necessary to meet the 90 percent requirement
under section 112(c)(3) for these HAP. For the reason stated above,
pursuant to section 112(c)(3) of the CAA, we are proposing emission
standards for the above mentioned HAP for area source boilers fired by
coal, oil, and wood, but not standards for boilers fired by natural
gas.
[[Page 31901]]
IV. Summary of This Proposed Rule
A. Do the proposed standards apply to my source?
This proposed rule applies to you if you own or operate a boiler
combusting coal, biomass, or oil located at an area source. The
standards do not apply to boilers that are subject to another standard
under 40 CFR part 63 or to a standard developed under CAA section 129.
This proposed rule applies to you if you own or operate a boiler
combusting natural gas, located at an area source, which switches to
combusting coal, biomass, or oil after the date of proposal.
B. What is the affected source?
The affected source is the collection of all existing boilers
within a subcategory located at an area source facility or each new
boiler located at an area source facility.
C. When must I comply with the proposed standards?
The owner or operator of an existing source would be required to
comply with the rule no later than 3 years after the date of
publication of the final rule in the Federal Register. The owner or
operator of a new source would be required to comply upon the date of
publication of the final rule in the Federal Register or startup of the
facility, whichever is later.
D. What are the proposed MACT and GACT standards?
Emission standards expressed in the form of emission limits are
being proposed for new and existing area source boilers. The proposed
MACT emission limits for mercury and CO (as a surrogate for POM) are
presented, along with the proposed GACT standards for PM (as a
surrogate for urban metals), in Table 1 of this preamble.
Table 1--Emission Limits for Area Source Boilers
[Pounds per million British thermal units heat input]
----------------------------------------------------------------------------------------------------------------
Particulate Carbon monoxide
Source Subcategory matter (PM) Mercury (CO) (ppm)
----------------------------------------------------------------------------------------------------------------
New Boiler...................... Coal............... 0.03 3.0E-06 310 (@ 7% oxygen).
Biomass............ 0.03 ................. 100 (@ 7% oxygen).
Oil................ 0.03 ................. 1 (@ 3% oxygen).
Existing Boiler................. Coal............... ................. 3.0E-06 310 (@ 7% oxygen).
Biomass............ ................. ................. 160 (@ 7% oxygen).
Oil................ ................. ................. 2 (@ 3% oxygen).
----------------------------------------------------------------------------------------------------------------
The emission limits for existing area source boilers are only
applicable to area source boilers that have a designed heat input
capacity of 10 million British thermal units per hour (MMBtu/h) or
greater. If your boiler burns at least 10 percent coal on a total fuel
annual heat input basis, the boiler is in the coal fuel subcategory. If
your boiler burns biomass or biomass in combination with a liquid or
gaseous fuel, the unit is in the biomass subcategory. If your boiler
burns oil, or oil in combination with a gaseous fuel, the unit is in
the oil subcategory, except if the unit burns oil only during periods
of gas curtailment.
As allowed under CAA section 112(h), a work practice standard is
being proposed for existing area source boilers that are units with
designed heat input capacity of less than 10 MMBtu/h. The work practice
standard for existing small area source boilers requires the
implementation of a tune-up program.
An additional standard is being proposed for existing area source
facilities having an affected boiler with a designed heat input
capacity of 10 MMBtu/h or greater that requires the performance of an
energy assessment, by qualified personnel, on the boiler and the
facility to identify 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
(D.C. 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 reasons explained
below, has not established different standards for those periods. The
standards that we are proposing are daily or monthly averages. Based
upon continuous emission monitoring data, obtained as part of the
information collection effort for the major source boiler and process
heater rulemaking, which included periods of startup and shutdown, over
long averaging periods, startups and shutdowns will not affect the
achievability of the standard. Boilers, especially solid fuel-fired
boilers, do not normally startup and shutdown more than 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 operations. However, by
contrast, malfunction is
[[Page 31902]]
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 CAA 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. Similarly, although standards for area
sources are generally not required to be set based on ``best
performers,'' we believe that what is ``generally available'' should
not be based on periods in which there is a ``failure to operate.''
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 area source
boilers. 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 proposed initial compliance requirements?
For new and existing area source boilers with applicable emission
limits, we are proposing that you must conduct initial stack tests or
fuel analysis (for mercury) to determine compliance with the PM,
mercury, and CO emission limits.
As part of the initial compliance demonstration, we are proposing
that you must monitor specified operating parameters during the initial
performance tests that demonstrate compliance with the PM and mercury
emission limits for area source boilers with wet or dry scrubbers. The
test average establishes your site-specific operating levels.
For owners or operators of existing area source boilers having a
heat input capacity of less than 10 MMBtu/h, we are proposing that you
must submit to the delegated authority or EPA, as appropriate,
documentation that a tune-up was conducted.
For owners or operators of existing area source facilities having a
boiler with a heat input capacity of 10 MMBtu/h or greater and subject
to this rule, we are proposing that you submit to the delegated
authority or EPA, as appropriate, documentation that the energy
assessment was performed and the cost-effective energy conservation
measures identified.
G. What are the proposed continuous compliance requirements?
If you demonstrate initial compliance with the emission limits by
performance (stack) tests, we are proposing that you conduct stack
tests on an annual basis. Furthermore, to demonstrate continuous
compliance with the PM and mercury emission limits, we are proposing
that you must monitor and comply with the applicable site-specific
operating limits.
For area source boilers without wet scrubbers that must comply with
the PM and mercury emission limits, we are proposing that you must
continuously monitor opacity and maintain the opacity at or below ten
percent (daily block average). Or, if the unit is controlled with a
fabric filter, instead of continuously monitoring opacity, we are
proposing that the fabric filter may be continuously operated such that
the bag leak detection system alarm does not sound more than 5 percent
of the operating time during any 6-month period.
For boilers with wet scrubbers that must comply with the PM and
mercury emission limits, we are proposing that you must monitor
pressure drop and liquid flow rate of the scrubber and maintain the
daily block averages at or above the minimum operating limits
established during the performance test.
If you elected to demonstrate initial compliance with the mercury
emission limit by fuel analysis, we are proposing that you conduct a
monthly fuel analysis and maintain the annual average at or below the
limit indicated in Table 1 of this preamble.
For boilers that demonstrate compliance with the PM and mercury
emission limits by performance (stack) tests, we propose that you must
maintain monthly fuel records that demonstrate that you burned no new
fuel type or new mixture (monthly average) as set during the
performance test. If you plan to burn a new fuel type or new mixture
than what was burned during the initial performance test, then we are
proposing that you must conduct a new performance test to demonstrate
continuous compliance with the PM emission limit and mercury emission
limit.
For boilers with heat input capacities equal to or greater than 100
MMBtu/hr, we propose that you must continuously monitor CO and maintain
the daily average CO emissions at or below the limits indicated in
Table 1 to demonstrate compliance with the CO emission limits at all
times.
H. What are the proposed notification, recordkeeping and reporting
requirements?
All new and existing sources would be required to comply with some
requirements of the General Provisions (40 CFR part 63, subpart A),
which are identified in Table 6 of this proposed rule. The General
Provisions include specific requirements for notifications,
recordkeeping, and reporting. If performance tests are required under
this proposed rule, then the notification and reporting requirements
for performance tests in the General Provisions would also apply.
Each owner or operator would be required to submit a notification
of compliance status report, as required by 40 CFR 63.9(h) of the
General Provisions. This proposed rule requires 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 40 CFR 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.
[[Page 31903]]
This proposed rule would require records to demonstrate compliance
with each emission limit, work practice standard, or management
practice. These recordkeeping requirements are specified directly in
the General Provisions to 40 CFR part 63.
Records for applicable management practices must be maintained.
Specifically, the owner or operator must keep records of the dates and
the results of each boiler tune-up.
Records of either continuously monitored parameter data for a
control device if a device is used to control the emissions or
continuous emission monitoring system (CEMS) data would be required.
Each owner and operator would be required to keep the following
records:
(1) All reports and notifications submitted to comply with the
rule;
(2) Continuous monitoring data as required in the rule;
(3) Each instance in which you did not meet each emission limit,
work/management practice, and operating limit (i.e., deviations from
the rule);
(4) Monthly fuel use by each boiler including a description of the
type(s) of fuel(s) burned, amount of each fuel type burned, and units
of measure;
(5) A copy of the results of all performance tests, energy
assessments, opacity observations, performance evaluations, or other
compliance demonstrations conducted to demonstrate initial or
continuous compliance with the rule; and
(6) A copy of your site-specific monitoring plan developed for the
rule, if applicable.
Typically, records would be retained for at least 5 years. In
addition, monitoring plans, operating and maintenance plans, and other
plans would be updated as necessary and kept for as long as they are
still current.
I. Submission of Emissions Test Results to EPA
Compliance test data are necessary for many purposes including
compliance determinations, development of emission factors, and
determining annual emission rates. EPA has found it burdensome and time
consuming to collect emission 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 bulky paper copies.
In this action, we are taking a step to improve data accessibility
for stack tests (and in the future continuous monitoring data). Boiler
area sources would be required to submit to WebFIRE (an EPA electronic
database) an electronic copy of stack test reports as well as process
data. Data entry requires only access to the Internet and is expected
to be completed by the stack testing company as part of the work that
it is contracted to perform.
Please note that the proposed requirement to submit source test
data electronically to EPA would not require any additional performance
testing. In addition, when a facility submits performance test data to
WebFIRE, there would be no additional requirements for data
compilation; instead, we believe industry would greatly benefit from
improved emissions factors, fewer information requests, and better
regulation development as discussed below. Because the information that
would be reported is already required in the existing test methods and
is necessary to evaluate the conformance to the test methods,
facilities would already be collecting and compiling these data. One
major advantage of submitting source test data through the Electronic
Reporting Tool (ERT), which was developed with input from stack testing
companies (who already collect and compile performance test data
electronically), is that it would provide a standardized method to
compile and store all the documentation required by this proposed rule.
Another important benefit of submitting these data to EPA at the time
the source test is conducted is that these data should reduce the
effort involved in data collection activities in the future for these
source categories. 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). Finally, another benefit of submitting these data
to WebFIRE electronically is that these data will greatly improve the
overall quality of the existing and new emissions factors by
supplementing the pool of emissions test data upon which emissions
factors are 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 out-dated or
not representative of a particular source category. Receiving recent
performance test results would ensure that emissions factors are
updated and more accurate. In summary, receiving these 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.
As mentioned earlier, the electronic data base that will be used is
EPA's WebFIRE, which is a Web site accessible through EPA's TTN
(technology transfer network). The WebFIRE Web site was constructed to
store emissions test data for use in developing emission 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.
The ERT can be used to document the conducting of stack tests data
for various pollutants including PM, mercury, dioxin/furan, and HCl.
Presently, the ERT does not accept opacity data or CEMS data.
EPA specifically requests comment on the utility of this electronic
reporting requirement and the burden that owners and operators of
boiler area source facilities estimate would be associated with this
requirement.
V. Rationale of This Proposed Rule
A. How did EPA determine which pollution sources would be regulated
under this proposed rule?
This proposed rule regulates industrial boilers (fired by coal,
biomass, or oil) and institutional and commercial boilers (fired by
coal, biomass, or oil) that are located at area sources of HAP.
Boilers that are used specifically for research and development are
not regulated. However, boilers that only provide steam to a process or
for heating at a research and development facility are still subject to
this proposed rule.
B. How did EPA determine the subcategories for this proposed rule?
The CAA allows EPA to divide source categories into subcategories
when differences between given types of units lead to corresponding
differences in the nature of emissions or the technical feasibility of
applying emission control techniques. The design, operating, and
emissions information that EPA reviewed during the major source
rulemaking indicates the need to subcategorize boilers based on the
boiler type.
[[Page 31904]]
Boiler systems are designed for specific fuel types (e.g., coal,
biomass, or oil) and will encounter problems if a fuel with
characteristics other than those originally specified is fired. Most
boilers can only achieve full load on the fuel or fuels for which they
were specifically designed. Changes to the fuel type would often
require extensive changes to the fuel handling and feeding system.
Additionally, the burners and combustion chamber would need to be
redesigned and modified to handle different fuel types and account for
increases or decreases in the fuel volume and shape. In some cases, the
changes may reduce the capacity and efficiency of the boiler. An
additional effect of these changes would be extensive retrofit costs.
Emissions from boilers burning coal, biomass, and oil will also
differ. Boilers emit a number of urban HAP. In general, HAP formation
is dependent upon the composition of the fuel. The combustion quality
and temperature also play an important role. The fuel dependent urban
HAP emissions from boilers are metals, including mercury. These fuel
dependent HAP emissions generally can be controlled by either changing
the fuel property before combustion or by removing the HAP from the
flue gas after combustion. Organic HAP, on the other hand, are formed
from incomplete combustion and are much less influenced by the
characteristics of the fuel being burned. The degree of combustion may
be greatly influenced by three general factors: time, turbulence, and
temperature. These factors are a function of the design of the boiler
which is dependent in part on the type of fuel being burned.
Because these different types of boilers have different emission
characteristics which may influence the feasibility and effectiveness
of emission control, we are proposing to subcategorize them as follows:
boilers designed to fire coal, boilers designed to fire biomass, and
boilers designed to fire oil in order to account for these differences
in emissions. The coal-fired subcategory includes boilers burning
greater than 10 percent coal on an annual fuel heat input basis. The
biomass fuel subcategory includes units burning any biomass but not
more than 10 percent coal on an annual fuel heat input basis. The oil
subcategory includes all remaining boilers.
In summary, we have identified three subcategories of boilers
located at area sources: (1) Boilers designed for coal firing, (2)
boilers designed for biomass firing, and (3) boilers designed for oil
firing.
C. What surrogates are we using?
As explained above, EPA is proposing emission standards for the two
source categories in this proposed rule. For mercury from coal-fired
area source boilers and POM from all area source boilers, EPA is
proposing these standards under CAA sections 112(d)(2) and 112(h). For
the other urban HAP which formed the basis of the CAA section 112(c)(3)
listing, EPA is proposing standards pursuant to CAA section 112(d)(5).
In selecting the proposed emission standards, we are using PM as a
surrogate for the non-mercury metallic urban HAP (arsenic, beryllium,
cadmium, chromium, lead, manganese, and nickel). The inherent
variability and unpredictability of the non-mercury metal HAP
compositions and amounts in fuel have a material effect on the
composition and amount of non-mercury metal HAP in the emissions from
the boiler. As a result, establishing individual numerical emissions
limits for each non-mercury HAP metal species is difficult given the
level of uncertainty about the individual non-mercury metal HAP
compositions of the fuels that will be combusted. An emission
characteristic common to all boilers is that the non-mercury metal HAP
are a component of the PM contained in the fly ash emitted from the
boiler. A sufficient correlation exists between PM and non-mercury
metallic HAP to rely on PM as a surrogate for these HAP and for their
control. Therefore, the same control techniques that would be used to
control the fly-ash PM will control non-mercury metallic HAP. Emissions
limits established to achieve control of PM will also achieve control
of non-mercury metal HAP. Consequently, we used PM as a surrogate for
the non-mercury metal urban HAP in establishing emissions limits. 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.
We looked at mercury separately from other metallic urban HAP due
to its different chemical characteristics and applicable controls.
For the organic urban HAP listed for these source categories (POM,
acetaldehyde, acrolein, dioxins, PCB, and formaldehyde), we used CO as
a surrogate to represent the organic urban HAP emitted from the
boilers. The presence of CO is an indicator of incomplete combustion. A
high level of CO in emissions is an indicator of incomplete combustion
and, thus, a potential indication of elevated organic HAP emissions.
Monitoring equipment for CO is readily available, which is not the case
for organic HAP. Also, it is significantly easier and less expensive to
measure and monitor CO emissions than to measure and monitor emissions
of each individual organic HAP. We considered other surrogates, such as
THC, but lacked data on emissions and permit limits for area source
boilers. Therefore, using CO as a surrogate for organic urban HAP is a
reasonable approach because minimizing CO emissions will result in
minimizing organic urban HAP emissions.
D. How did EPA determine the proposed standards for existing units?
Both industrial boilers and institutional/commercial boilers have
been on the list of CAA section 112(c)(6) source categories for mercury
and POM. That section requires MACT standards for each of the
pollutants needed to achieve regulation of 90 percent of the emissions
of the relevant pollutant. As previously noted, the CAA allows EPA to
establish standards under GACT instead of MACT for urban HAP we propose
to regulate to fulfill CAA section 112(c)(3).
As discussed previously, CAA section 112(h) allows the
Administrator to promulgate a design, equipment, work practice, or
operational standard, or combination thereof, in certain cases where,
in the judgment of the Administrator, it is not feasible to prescribe
or enforce an emission standard under CAA section 112(d). These cases
include the situation in which the application of measurement
methodology to a particular class of sources is not practicable due to
technical and economic limitations.
As we establish emission standards for each source category listed
pursuant to CAA section 112(c)(6), we learn more about the source
category. As part of our analysis, we examine the available information
about the source category, and we re-examine the inventory associated
with the original listing. We continue to believe that we must regulate
POM from coal-fired, biomass-fired, and oil-fired area source boilers
in order to meet the requirement in section 112(c)(6), and propose
below MACT-based limits for POM for all categories. However, based on
the information we have learned to date as we are developing standards
for various source categories, such as major source boilers, gold
mines, commercial and industrial solid waste incinerators, and other
categories, we believe that we only need coal-fired area source boilers
to meet the 90 percent requirement set forth in section 112(c)(6) for
mercury. Therefore,
[[Page 31905]]
we propose as our primary option MACT-based controls for mercury only
for coal-fired boilers.
With respect to mercury from area source boilers classified as
biomass-fired or oil-fired, as well as with respect to other urban HAP
besides POM, we have developed proposed standards that reflect GACT for
these two area source categories.
1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
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 non-air quality health
and environmental impacts and energy requirements, determined is
achievable for each category or subcategory. For existing sources, MACT
cannot be less stringent than the average emission limitation achieved
by the best performing 12 percent of existing sources in the category
or subcategory for categories or subcategories with 30 or more sources.
This requirement constitutes the ``MACT floor'' for existing area
source boilers. EPA may not consider cost in determining the MACT
floor. EPA must consider cost, non-air quality health and environmental
impacts, and energy requirements in evaluating whether it is
appropriate to set a standard more stringent than the MACT floor
(beyond-the-floor controls).
a. MACT Floor Analysis for Mercury and POM
The approach selected for determining the MACT floors is based on
estimating the emissions levels achieved on average by the best 12
percent of existing sources, for which we have information. In terms of
developing MACT emission limits for area source boilers, we have:
--No emission data for POM,
--Limited emission data (nine coal-fired boilers) for mercury,
--No State regulations applicable for mercury or POM,
--No State permits specific for mercury or POM,
--No surrogate for mercury, but CO as a surrogate for POM,
--Emission data on four coal-fired area source boilers using add-on
control technology for mercury,
--Limited emission data for CO (5 coal-fired boilers, 30 wood-fired
boilers, 68 oil-fired boilers),
--A few State permits with CO limits for coal, oil, and wood-fired area
source boilers,
The MACT floor limits for each of the HAP and HAP surrogates
(mercury and CO) 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 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 in the subcategory considering the existing design
of boilers. 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. 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--Area Source'' located in the docket.
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 Court 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'').
To calculate the achieved emission limit, including variability, we
used the equation:
[GRAPHIC] [TIFF OMITTED] TP04JN10.000
Where:
n = the number of test runs
m = the number of test runs in the compliance average
s = standard deviation of emission data
t(0.99, n-1) = the t-statistic
x = emissions data average
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 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. That is, 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 percent 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
(SD), which are two statistical measures calculated from the sample
data. The average is the central value of a data set, and the SD is the
common measure of the dispersion of the data set around the average.
Based on this limited available information, the MACT floor
analyses for the three subcategories (coal, biomass, and oil) are
discussed below.
1. Existing area source boilers designed for coal firing:
Mercury--The total number of coal-fired area source boilers for
which we have actual mercury emission data is 9. Thus, the top 12
percent is based on emissions from two boilers. The average mercury
emission level of the top 12 percent is 1.3 pounds per trillion Btu
(lb/TBtu). The SD of test runs in the top 12 percent boilers is 0.322.
Therefore, the 99 percent UPL level is 2.5 lb/TBtu. The resulting MACT
floor mercury limit for existing coal-fired area source boilers is 2.5
lb/T Btu (rounded to 0.000003 lb/
[[Page 31906]]
million Btu). No fuel analysis data from boilers in the top 12 percent
were available for assessing the impact of fuel variability on mercury
emissions.
POM--None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. However, one
State (New Jersey) does have standards for CO, but for boilers the size
of coal-fired area source boilers, the requirement is actually a work
practice standard for CO (i.e., boiler tune-up). For small (less than
50 MMBtu/h) boilers, the New Jersey requirement is to maintain and
operate the source in accordance with manufacturer specifications.
The available State permits obtained for coal-fired area source
boilers limiting CO emissions were for 12 units located in Ohio (3
units), California (1 unit), and Illinois (8 units). We also obtained
CO emission data from 5 coal-fired area source boilers as part of the
information collection effort for the major source NESHAP. Therefore,
the top 12 percent is made up of three boilers. The average CO level of
the top 12 percent is 162 parts per million (ppm) at 3 percent oxygen.
The SD of the run data in top 12 percent boilers is 92.1 ppm.
Therefore, the 99 percent UPL level is 390 ppm at 3 percent oxygen. The
resulting MACT floor CO limit for existing coal-fired area source
boilers is 310 ppm at 7 percent oxygen. We correct to 7 percent oxygen
because that is typically in the oxygen range that coal-fired boilers
operate and we rounded up to the nearest 10 ppm.
2. Existing area source boilers designed for biomass firing:
POM--None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. Actual CO
emission data were available from the National Forest Service's Fuels
for Schools program for 14 wood-fired boilers. Also, State permits
limiting CO emissions from biomass boilers were obtained on another 24
biomass-fired area source boilers. We also obtained CO emission test
data from 26 biomass-fired area source boilers as part of the major
source ICR survey.
The top 12 percent is made up of 8 boilers. The average CO level of
the top 12 percent is 80.6 ppm at 3 percent oxygen. The SD of the top
12 percent boilers is 73.5 ppm. The 99 percent UPL is 192 ppm at 3
percent oxygen, rounded up to 200 ppm. Biomass-fired boilers typically
operate at around 7 percent oxygen. Therefore, the MACT floor level is
160 ppm CO at 7 percent oxygen.
3. Existing area source boilers designed for oil firing:
POM--None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. Actual CO
emission data were available from 68 oil-fired area source boilers
responding to the Boiler MACT ICR. State permits limiting CO emissions
from oil-fired area source boilers were obtained on 56 oil-fired area
source boilers.
The top 12 percent is made up of 15 boilers. The average CO level
of the top 12 percent is 1 ppm at 3 percent oxygen. Based on the test
runs from these 15 best performing units, the 99 percent UPL level is 2
ppm at 3 percent oxygen. Therefore, the MACT floor level is 2 ppm CO at
3 percent oxygen. Because oil-fired boilers typically operate at around
3 percent oxygen, additional oxygen content correction was not
necessary.
4. Work Practice Standards for Smaller Boilers
As previously discussed, 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'' to mean 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 POM), and PM (as a surrogate for urban non-
mercury metals) are EPA Methods 29, 10, and 5 of 40 CFR part 60
appendices A-8, A-4, and A-3, respectively. These methods are reliable
and relatively inexpensive. However, the methods are not applicable for
sampling small diameter (less than 12 inches) stacks. For example, in
these small diameter stacks, the conventional Method 5 stack assembly
blocks a significant portion of the cross-section of the duct and
causes inaccurate measurements. Many existing area source boilers have
stacks with diameters less than 12 inches. The stack diameter is
generally related to the size of the boiler. Boilers that have a
capacity below 10 MMBtu/h generally have stacks with diameters less
than 12 inches. Also, many area source boilers 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-to-sales analysis to evaluate the economic
impact of the testing and monitoring costs that area source boiler
facilities would incur to demonstrate compliance with the proposed
emission limits. The annual compliance costs imposed on each source is
for the costs of a stack test for mercury and PM emissions and a
continuous emission monitor (CEM) for CO emissions. We assumed that
each establishment in each industry, commercial, or institutional
sector would be associated with a single boiler. The financial impacts
of potential compliance costs are assessed for representative entities
in each entity sector using the ratio of compliance costs to the
average representative entity revenue (cost-to-sales ratio or CSR).
The results of the analysis indicate that total compliance costs
exceed 3 percent (and can reach as high as 19 percent) of the average
firm revenues for 79 percent of the facilities. This indicates that the
annual costs for testing and monitoring 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. For small
institutional (schools) and commercial (farms) facilities the costs
would be prohibitive. This analysis is discussed in the memorandum
``Cost-to-Sales Analysis of Testing and Monitoring Costs'' located in
the docket.
Based on this analysis, pursuant to CAA section 112(h), EPA is
proposing that it is not feasible to enforce emission standards for
area source boilers having a heat input capacity of less than 10 MMBtu/
h because of the technological and economic limitations described
above. Thus, a work practice, as discussed below, is being proposed to
limit the emissions of mercury and CO (as a surrogate for POM) for
existing area source boilers having a heat input capacity of less than
10 MMBTU/h. We are specifically requesting comment on whether a
threshold higher than 10 MMBtu/h meets the technical and economic
limitations as specified in section 112(h).
For existing area source boilers, the only work practice being used
that potentially controls mercury and POM emissions is a boiler tune-
up. Mercury is a fuel dependent HAP. That is, the amount of mercury
emitted from the boiler depends on the amount of mercury contained in
the fuel. Fuel usage can be reduced by improving the combustion
efficiency of the boiler. At best, boilers may be 85 percent efficient
and untuned boilers may have combustion efficiencies of 60 percent or
lower. As combustion efficiency
[[Page 31907]]
decreases, fuel usage increases to maintain energy output resulting in
increased emissions.
On the other hand, POM is 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 as the three Ts
of combustion. Good combustion practice (GCP), in terms of boilers,
could be defined as the system design and work practices expected to
minimize organic HAP emissions.
We have obtained information on area source boilers reported using
GCP, as part of the information collection effort for the major source
NESHAP. The data that we have suggests that area source boilers
typically conduct boiler tune-ups. We also reviewed State regulations
and permits applicable to area source boilers. 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 44 area
source boilers with a capacity of less than 10 MMBtu/h that responded
to EPA's information collection effort for major source NESHAP, 28 (or
64 percent) reported conducting a boiler tune-up program. Ultimately,
we determined that at least 6 percent of the boilers in each of the
subcategories are subject to a tune-up requirement. Therefore, the work
practice of a tune-up does establish the MACT floor for mercury and POM
emissions from existing area source boilers with a heat input capacity
of less than 10 MMBtu/h.
A detailed discussion of the MACT floor methodology is presented in
the memorandum ``MACT Floor Analysis for the Industrial, Commercial,
and Institutional Area Source Boilers'' in the docket.
b. Beyond-the-Floor Determination for Mercury and POM.
We considered the pollution prevention and energy conservation
measure of an energy assessment as a beyond-the-floor option for
mercury and POM emissions. An energy assessment provides valuable
information on improving energy efficiency. An energy assessment, or
energy 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. Improvement in energy efficiency results in
decreased fuel use which results in a corresponding decrease in
emissions (both HAP and non-HAP) from the boiler, but not necessarily
all those present. The Department of Energy (DOE) 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. If a facility elected to
implement the cost-effective energy conservation measures identified in
the energy assessment, it would potentially result in greater mercury
and POM reduction than achieved by a boiler tune-up alone. In addition,
the cost of an energy assessment is minimal, in most cases, compared to
the cost for testing and monitoring to demonstrate compliance with an
emission limit. Furthermore, 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 area source boilers. The proposed standards for
existing area source facilities with a boiler that has a capacity equal
to or greater than 10 MMBtu/h for mercury and POM include the
requirement of a performance of an energy assessment to identify 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 two 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--
(A) 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 on the boiler's energy consuming systems.
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 specialist
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.
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
[[Page 31908]]
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; and (6) what rate of return should be used.
A detailed description of the beyond-the-floor consideration is in
the memorandum ``Methodology for Estimating Cost and Emissions Impacts
for Industrial, Commercial, Institutional Area Source Boilers'' in the
docket.
2. GACT Determination for Existing Area Source Boilers
As provided in CAA section 112(d)(5), we are proposing standards
representing GACT for these area source boilers.
For existing coal and biomass-fired area source boilers, the add-on
control technology generally being used is multiclones. We found that
this technology is minimally effective in controlling urban metal HAP
and has no effect on urban organic HAP.
Multiclones are mechanical separators that use velocity
differential across the cyclones to separate particles. A multiclone
uses several smaller diameter cyclones to improve efficiency.
Multiclones have a control efficiency for PM emissions of about 75
percent. Multiclones are more efficient in collecting larger particles
and their collection efficiency falls off at small particle sizes. This
is a disadvantage because non-mercury metallic HAP tend to be on small
size particles (i.e., fine particle enrichment). Based on emission data
obtained during the major source NESHAP development, multiclones have a
control efficiency for non-mercury metallic HAP of only about 10
percent and have no effect on reducing mercury emissions. The cost of
using multiclones (capital, testing, and monitoring) is estimated to be
between $50,000 and $100,000 depending on the size of the boiler.
We also considered various pollution prevention and energy
conservation options as the potential basis for GACT for the urban
metal HAP and the organic urban HAP. The most common options, and
generally available, are simply tuning the boiler to the manufacturer's
specification. A boiler tune-up provides potential savings from energy
efficiency improvements and pollution prevention. Besides reducing
operating and maintenance costs, improving energy efficiency reduces
negative impacts on the environment. Improvement in energy efficiency
results in decreased fuel use which results in a corresponding decrease
in emissions (both HAP and non-HAP) from the boiler. A boiler tune-up
requirement would potentially result in the same non-mercury metallic
HAP reduction as a PM emission limit based on performance of
multiclones but would also reduce emissions of organic HAP. In
addition, the cost of a boiler tune-up appears minimal compared to the
cost for testing and monitoring to demonstrate compliance with an
emission limit.
For existing oil-fired area source boilers, we found no add-on
control technology being used.
Therefore, we determined that GACT for existing area source boilers
with heat input capacities of 10 MMBtu/hour or greater is a management
practice requiring the implementation of a boiler tune-up program.
Thus, for existing area source boilers, we are proposing GACT for HAP
other than mercury and POM to be a management practice requiring the
implementation of a boiler tune-up program.
If we conclude that our obligations under section 112(c)(6) for
mercury can be met without mercury emissions from biomass-fired or oil-
fired area source boilers, we believe that several requirements of this
proposed rule would be generally available to the regulated community
and would provide some control of mercury and other fuel-bound
pollutants at existing sources with larger boilers. For example, the
requirements to optimize combustion, conduct an energy assessment, and
conduct biennial tune-ups would decrease emissions of mercury because
less fuel would be burned. In contrast, we do not believe that fabric
filters are widely used now, would be expensive to install for small
businesses, and therefore would not be considered GACT. Therefore, we
seek comment on whether the various measures discussed in this preamble
to reduce fuel consumption in connection with POM control and control
of urban metal HAP and organic urban HAP would represent GACT for
mercury emitted from biomass-fired and oil-fired area source boilers.
E. How did EPA determine the proposed standards for new units?
As noted above, we have developed the proposed standards to reflect
the application of MACT for mercury and POM, and GACT for arsenic,
beryllium, cadmium, lead, chromium, manganese, nickel, ethylene
dioxide, and polychlorinated biphenyls (PCB).\1\
---------------------------------------------------------------------------
\1\ The proposed emission standards will also reduce emissions
of other urban HAP, which did not form the basis of the listing.
Those urban HAP include benzene, acetaldehyde, acrolein, dioxins,
and formaldehyde.
---------------------------------------------------------------------------
1. MACT Analysis for Mercury From Coal-fired Boilers and POM
The CAA specifies that MACT for new boilers shall not be less
stringent than the emission control that is achieved in practice by the
best-controlled similar source, as determined by the Administrator.
This minimum level of stringency is the MACT floor for new units. EPA
may not consider costs or other impacts in determining the MACT floor.
However, EPA must consider cost, non-air quality health and
environmental impacts, and energy requirements in evaluating whether it
is appropriate to set a standard that is more stringent than the MACT
floor (beyond-the-floor controls).
a. MACT Floor Analysis for Mercury and POM. Similar to the MACT
floor process used for existing area source boilers, the approach used
for determining the MACT floors for new units is based on estimating
the emissions levels achieved by the best-controlled similar source,
for which we have information.
1. New area source boilers designed for coal firing:
Mercury--We determined in the context of the major source
rulemaking for boilers that fabric filters are the most effective
technology employed by coal-fired industrial, commercial, and
institutional boilers for controlling mercury emissions. Five coal-
fired area source boilers have been identified as having a fabric
filter. Based on available emission data, the best performing unit
(i.e., the unit having the reported lowest mercury level based on a
three run test) is an area source coal-fired boiler equipped with an
electrostatic precipitator (ESP). The boiler had a test average for
mercury of 1.4 lb/TBtu with a SD of 0.307 to account for variability.
Therefore, the resulting MACT floor mercury limit for new coal-fired
area source boilers is determined to be 3.2 lb/T Btu. Since this
calculated value is less stringent than the MACT floor for mercury at
existing boilers designed for coal firing, the MACT floor for new
sources was established to be equal to the floor for existing sources
(0.000003 lb/million Btu).
POM--For POM emissions, the only control technology identified as
being used on area source boilers is monitoring and maintaining CO
emission levels which is associated with minimizing emissions of
organic HAP (including POM). Carbon monoxide is generally an indicator
of incomplete combustion because CO will oxidize to carbon dioxide if
adequate oxygen is available. Therefore, controlling CO emissions can
be a mechanism for
[[Page 31909]]
ensuring combustion efficiency and may be viewed as a GCP. As discussed
previously in this preamble, CO is considered a surrogate for organic
HAP (including POM) emissions in this proposed rule.
None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. However, one
State (New Jersey) does have standards for CO, but for boilers the size
of coal-fired area source boilers, it is actually a work practice
standard for CO (i.e., tune-up). For small (less than 50 MMBtu/h)
boilers, New Jersey's requirement is to maintain and operate the source
in accordance with manufacturers' specifications.
Considering available State permit data and emission test data for
coal-fired area source boilers the best controlled similar source is a
coal-fired area source boiler having an average three run CO test
emission level of 216 ppm at 3 percent oxygen. The calculated 99
percent UPL, to account for variability, is 640 ppm at 3 percent
oxygen. Since this calculated value is less stringent than the MACT
floor for CO at existing boilers designed for coal firing, the MACT
floor for new sources was established to be equal to the floor for
existing sources (310 ppm at 7 percent oxygen).
2. New area source boilers designed for biomass firing:
POM--None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. Actual CO
emission data were available from the Fuels for Schools program for 14
biomass-fired boilers and from 29 biomass-fired area source boilers as
part of the major source ICR survey. Also, State permits limiting CO
emissions from biomass boilers were obtained on another 27 biomass-
fired area source boilers. Therefore, the MACT floor for POM achieved
by the best controlled similar source is based on actual CO emission
data.
The average 3-run test CO level of the best controlled similar
source is 38.6 ppm at 3 percent oxygen. The SD for the test runs is 14
ppm. Therefore, the 99 percent UPL is 120 ppm at 3 percent oxygen,
rounded up to the nearest 10 ppm. Thus, the proposed MACT floor level
is 100 ppm CO at 7 percent oxygen.
3. New area source boilers designed for oil firing:
POM--None of the States for which we have an inventory have an
applicable emission limit specifically for POM or CO. Actual CO
emission data were available on 66 oil-fired area source boilers. State
permits limiting CO emissions from oil-fired area source boilers were
obtained on 46 oil-fired area source boilers. Therefore, the proposed
MACT floor for POM achieved by the best controlled similar source would
be based on the boilers reporting the lowest CO emission level.
The CO emission level of the best performing similar source is 0.6
ppm at 3 percent oxygen. The SD of the test runs is 0.04 ppm.
Therefore, the 99 percent UPL and the proposed MACT floor level is 1
ppm CO at 3 percent oxygen, rounded up to the nearest whole ppm.
A detailed description of the MACT floor determination is in the
memorandum, ``MACT Floor Analysis for Industrial, Commercial, and
Institutional Area Source Boilers'' in the docket.
4. Appropriateness of Work Practice Standards for New Area Source
Boilers:
As previously discussed, CAA section 112(h) 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 due to technical and
economic limitations.
As was the case for existing small area source boilers, total
compliance costs would likely exceed 3 percent of the average firm
revenues for some new facilities. This indicates that the annual costs
for testing and monitoring alone may have a significant adverse
economic impact on some new facilities.
As discussed previously, the standard reference methods for
measuring emissions of mercury, CO (as a surrogate for POM), and PM (as
a surrogate for urban non-mercury metals) are EPA Methods 29, 10, and 5
and are not applicable for sampling small diameter stacks. We solicit
comment on whether it would be technically infeasible to design
sampling ports adequate for the test methods in boilers that are below
a certain size.
Based on this analysis and the reason discussed below, we are not
proposing a work practice under CAA section 112(h) for new area source
boilers. New facilities, as opposed to existing facilities, have the
added flexibility of including compliance costs into their design and
planning. This would include the design and cost to provide a
performance testing facility that has sampling ports adequate for the
test methods and constructing the exhaust stack such that HAP emission
rates can be accurately determined. In addition, a new facility has the
option of fuel selection in minimizing their compliance costs.
A detailed discussion of the MACT floor methodology is presented in
the memorandum ``MACT Floor Analysis for the Industrial, Commercial,
and Institutional Area Source Boilers'' in the docket.
b. Beyond-the-floor Analysis for Mercury and POM for New Area
Source Boilers. 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 or other HAP emission reduction approaches were identified
that would achieve mercury or POM reduction greater than the new source
floors for each of the subcategories.
Therefore, we decided to not go beyond the MACT floor level of
control for mercury and POM emissions for new area source boilers 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 Area
Source Boilers'' in the docket.
2. GACT Determination for New Area Source Boilers
The control technologies currently used by facilities in the source
categories that reduce non-mercury metallic HAP and PM are fabric
filters and ESP. We determined that these controls are generally
available and cost effective for new area source boilers. New area
source boilers with heat input capacity of 10 MMBtu/h or greater are
subject to the NSPS for boilers (either subpart Db or Dc of 40 CFR part
60) which regulate emissions of PM and require performance testing.
Furthermore, new coal-fired area source boilers will likely require a
PM control device to comply with the proposed mercury MACT standard.
The emissions database contains PM test data for 82 area source
boilers obtained from the ICR survey conducted for major sources. All
of the boilers were greater than 10 million Btu per hour in size. In
order to develop PM (as a surrogate for non-mercury metallic HAP)
emission limits for the three subcategories, we compared the PM limits
in NSPS subpart Dc with the obtained PM emission data. We considered
this to be an appropriate methodology because many new area source
boilers will be subject to NSPS subpart Dc. Consequently, we determined
that the PM limits in the NSPS could be used to establish the PM GACT
emission limit for area source boilers.
[[Page 31910]]
The proposed GACT PM emission level based on NSPS subpart Dc for
new area source boilers is 0.03 lb/million Btu. Of the 82 area source
boilers for which we have PM emission data, 11 had reported PM emission
levels below 0.03 lb/million Btu.
For the organic urban HAP (acetaldehyde, acrolein, dioxins, and
formaldehyde), the most effective control technology identified is
minimizing CO emissions and we determined that this control is
generally available and cost effective for new area source boilers.
This determination is based on the fact there is no additional costs
associated with proposing a CO emission limit (as a surrogate for the
urban organic HAP) as GACT because it is the same as the MACT standard
being proposed for these subcategories for POM.
F. 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 the rule. Those requirements are
described in detail in sections IV.F to IV.H. We selected these
requirements based upon our determination of the information necessary
to ensure that the emission standards, work practices, and management
practices are being followed and that emission control devices and
equipment are maintained and operated properly. The proposed
requirements ensure compliance with this proposed rule without
proposing a significant additional burden for facilities that must
implement them.
We are proposing that compliance with the PM and mercury emission
limits be demonstrated by an initial performance test. To ensure
continuous compliance with the proposed PM and mercury emission limits,
this proposed rule would require continuous parameter monitoring of
control devices and recordkeeping. Additionally, this proposed rule
requires annual performance tests to ensure, on an ongoing basis, that
the air pollution control device is operating properly and its
performance has not deteriorated. If initial compliance with the
mercury emission limit is demonstrated by a fuel analysis performance
test, this proposed rule requires fuel analyses monthly, with
compliance determined based on an annual average.
We evaluated the cost of applying PM CEMS to area source boilers.
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. The
estimated national annual cost would be $4.5 billion. We determined the
costs would make them an unreasonable monitoring option.
We reviewed the cost information for CO CEMS provided by commenters
on the NESHAP for major source boilers 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 requires units with heat
input capacities less than 100 MMBtu/hr to conduct initial and annual
performance (stack) tests.
G. Alternative MACT Standards for Consideration
Our analysis of the inventory for mercury under CAA section
112(c)(6) has led us to believe that we do not need to regulate
biomass-fired and oil-fired boilers under MACT in order to meet our
statutory obligations under this provision. We solicit comment on
whether we should require the MACT-based emission limits on mercury
emissions from larger boilers in this category if we conclude that such
controls are unnecessary to meet our obligations under section
112(c)(6).
We also solicit comment on MACT-based requirements for mercury
emitted from biomass-fired and oil-fired area source boilers in the
event comment and further analysis of the inventory demonstrates such
regulation is necessary to fulfill the 90 percent requirement under CAA
section 112(c)(6) or is otherwise appropriate. We present what would be
MACT below.
1. Existing area source boilers designed for biomass firing:
Mercury--We obtained mercury emission data from two biomass-fired
area source boilers as part of the information collection effort for
the major source NESHAP. Thus, the top 12 percent would be comprised of
one boiler. The average mercury level of the top 12 percent is 0.36 lb/
TBtu. All 3 test runs results were nondetect. The standard deviation
for the three detection limits, when converted to lb/mmBtu using the
heat input rates during each run, was 1.82E-09. Therefore, the
resulting MACT floor mercury limit for existing biomass-fired area
source boilers would be 0.37 lb/TBtu (rounded to 0.0000004 lb/MMBtu).
2. Existing area source boilers designed for oil firing:
Mercury--There are no available emission data, State regulations,
or State permits regarding mercury emissions from oil-fired area source
boilers. Available emission factors are generally the average of
available data and would not reasonably represent the average of the
top 12 percent best performing units. However, we have obtained mercury
emission data on major source oil-fired boilers as part of the major
source rulemaking. Since major source oil-fired boilers are similar in
design and controls as compared to area source oil-fired boilers, we
are applying the major source MACT limit of 4 lb/TBtu (0.000004 lb/
MMBtu) to existing oil-fired area source boilers.
3. New area source boilers designed for biomass firing:
Mercury--We determined in the context of the major source
rulemaking for boilers that fabric filters are the most effective
technology employed by biomass-fired boilers for controlling mercury
emissions. However, there is no test information on biomass-fired
boilers equipped with fabric filters in which to determine control
efficiency.
The average mercury level of the ``best controlled'' unit for which
we have emission data is 0.36 lb/TBtu. All 3 test runs results were
nondetect. The standard deviation for the three detection limits, when
converted to lb/MMBtu using the heat input rates during each run, was
1.82E-09. Therefore, the resulting MACT floor mercury limit for
existing biomass-fired area source boilers would be 0.36 lb/TBtu
(0.0000004 lb/MMBtu).
4. New area source boilers designed for oil firing:
Mercury--There are no available emission data, State regulations,
or State permits regarding mercury emissions from oil-fired area source
boilers. Available emission factors are generally the average of
available data and would not reasonably represent the best performing
unit. However, we have obtained mercury emission data on major source
oil-fired boilers as part of the major source rulemaking. Since major
source oil-fired boilers are similar in design and controls as compared
to area source oil-fired boilers, we are applying the major source MACT
limit for new oil-fired boilers of 0.3 lb/TBtu (0.0000003 lb/MMBtu) to
new oil-fired area source boilers.
H. How did we decide to exempt these area source categories from title
V permitting requirements?
For the reasons described below, we are proposing to exempt from
title V permitting requirements affected sources in the industrial
boiler and the
[[Page 31911]]
institutional/commercial boiler area source categories that are not
certain synthetic area sources. We estimate that at least 48 synthetic
area sources reduced their HAP emissions to below the major source
thresholds by installing air pollution control devices. We are not
proposing to exempt from title V those synthetic area sources that have
reduced their HAP emissions to below the major source thresholds by
installing air pollution control devices.
CAA section 502(a) provides that the Administrator may exempt an
area source category (in whole or in part) from title V if the
Administrator determines that compliance with title V requirements is
``impracticable, infeasible, or unnecessarily burdensome'' on an area
source category. See CAA section 502(a). In December 2005, in a
national rulemaking, EPA interpreted the term ``unnecessarily
burdensome'' in CAA section 502 and developed a four-factor balancing
test for determining whether title V is unnecessarily burdensome for a
particular area source category, such that an exemption from title V is
appropriate. See 70 FR 75320, December 19, 2005 (Exemption Rule).
The four factors that EPA identified in the Exemption Rule for
determining whether title V is ``unnecessarily burdensome'' on a
particular area source category include: (1) Whether title V would
result in significant improvements to the compliance requirements,
including monitoring, recordkeeping, and reporting, that are proposed
for an area source category (70 FR 75323); (2) whether title V
permitting would impose significant burdens on the area source category
and whether the burdens would be aggravated by any difficulty the
sources may have in obtaining assistance from permitting agencies (70
FR 75324); (3) whether the costs of title V permitting for the area
source category would be justified, taking into consideration any
potential gains in compliance likely to occur for such sources (70 FR
75325); and (4) whether there are implementation and enforcement
programs in place that are sufficient to assure compliance with the
NESHAP for the area source category, without relying on title V permits
(70 FR 75326).
In discussing these factors in the Exemption Rule, we further
explained that we considered on ``a case-by-case basis the extent to
which one or more of the four factors supported title V exemptions for
a given source category, and then we assessed whether considered
together those factors demonstrated that compliance with title V
requirements would be `unnecessarily burdensome' on the category,
consistent with section 502(a) of the Act.'' See 70 FR 75323. Thus, in
the Exemption Rule, we explained that not all of the four factors must
weigh in favor of exemption for EPA to determine that title V is
unnecessarily burdensome for a particular area source category.
Instead, the factors are to be considered in combination, and EPA
determines whether the factors, taken together, support an exemption
from title V for a particular source category.
In the Exemption Rule, in addition to determining whether
compliance with title V requirements would be unnecessarily burdensome
on an area source category, we considered, consistent with the guidance
provided by the legislative history of CAA section 502(a), whether
exempting the area source category would adversely affect public
health, welfare, or the environment. See 70 FR 15254-15255, March 25,
2005. As explained below, we propose that title V permitting is
unnecessarily burdensome for a majority of the area sources at issue in
this proposed rule. We have also determined that the proposed
exemptions from title V would not adversely affect public health,
welfare, and the environment. Our rationale for this decision follows
here.
In considering the exemption from title V requirements for sources
in the categories affected by this proposed rule, we first compared the
title V monitoring, recordkeeping, and reporting requirements (factor
one) to the requirements in the proposed NESHAP for the boiler area
source categories. This proposed rule requires facilities to comply
with either emission limits using add-on controls or process changes or
implementation of certain work or management practices. This proposed
rule would require direct monitoring of emissions or control device
parameters, both continuous and periodic, recordkeeping that also may
serve as monitoring, and deviation and other semi-annual reporting to
assure compliance with this NESHAP.
The monitoring component of the first factor favors title V
exemption. For the work and management practices, this proposed
standard provides monitoring in the form of recordkeeping that would
assure compliance with the requirements of this proposed rule.
Monitoring by means other than recordkeeping for the work and
management practices is not practical or appropriate. Records are
required to ensure that the work and management practices are followed.
This proposed rule requires continuous parameter monitoring, with
periodic recording of the parameter for the required control device, to
assure compliance. The records are required to be maintained in a form
suitable and readily available for expeditious review, and that they
are kept for at least five years, the first two of which must be
onsite.
As part of the first factor, in addition to monitoring, we have
considered the extent to which title V could potentially enhance
compliance for area sources covered by this proposed rule through
recordkeeping or reporting requirements. We have considered the various
title V recordkeeping and reporting requirements, including
requirements for a 6-month monitoring report, deviation reports, and an
annual certification in 40 CFR 70.6 and 71.6.
For any boiler area source, this proposed NESHAP requires an
Initial Notification and a Notification of Compliance Status. This
proposed rule also requires facilities to certify compliance with the
emission limits, work practices, and management practices. In addition,
facilities must maintain records showing compliance through the
required parameter monitoring and deviation requirements. The
information required in the deviation reports is similar to the
information that must be provided in the deviation reports required
under 40 CFR 70.6(a)(3) and 40 CFR 71.6(a)(3).
We acknowledge that title V might require additional compliance
requirements on these categories, but we have determined that the
monitoring, recordkeeping and reporting requirements of the proposed
NESHAP are sufficient to assure compliance with the provisions of the
NESHAP. Given the nature of the operations at most area sources and the
types of requirements in this rule, title V would not significantly
improve those compliance requirements.
For the second factor, we determine whether title V permitting
would impose a significant burden on the area sources in the categories
and whether that burden would be aggravated by any difficulty the
source may have in obtaining assistance from the permitting agency.
Subjecting any source to title V permitting imposes certain burdens and
costs that do not exist outside of the title V program. EPA estimated
that the average cost of obtaining and complying with a title V permit
was $65,700 per source for a 5-year permit period, including fees. See
Information Collection Request for Part 70 Operating Permit
Regulations, January 2007, EPA ICR Number 1587.07. EPA does not have
specific estimates for the burdens and costs of permitting industrial,
commercial, and institutional boiler
[[Page 31912]]
area sources; however, there are certain activities associated with the
part 70 and 71 rules. These activities are mandatory and impose burdens
on the any facility subject to title V. They include reading and
understanding permit program guidance and regulations; obtaining and
understanding permit application forms; answering follow-up questions
from permitting authorities after the application is submitted;
reviewing and understanding the permit; collecting records; preparing
and submitting monitoring reports on a 6-month or more frequent basis;
preparing and submitting prompt deviation reports, as defined by the
State, which may include a combination of written, verbal, and other
communications methods; collecting information, preparing, and
submitting the annual compliance certification; preparing applications
for permit revisions every 5 years; and, as needed, preparing and
submitting applications for permit revisions. In addition, although not
required by the permit rules, many sources obtain the contractual
services of consultants to help them understand and meet the permitting
program's requirements. The ICR for part 70 provides additional
information on the overall burdens and costs, as well as the relative
burdens of each activity described here. Also, for a more comprehensive
list of requirements imposed on part 70 sources (hence, burden on
sources), see the requirements of 40 CFR 70.3, 70.5, 70.6, and 70.7.
In assessing the second factor for facilities affected by this
proposal, we found that most of the facilities that would be affected
by this proposed rule are small entities. These small sources lack the
technical resources that would be needed to comply with permitting
requirements and the financial resources that would be needed to hire
the necessary staff or outside consultants. As discussed above, title V
permitting would impose significant costs on these area sources, and,
accordingly, we conclude that title V is a significant burden for the
sources in these categories that we propose to exempt. Furthermore,
given the estimated 91,300 area source facilities (including schools,
hospitals, and churches) in the categories, it would likely be
difficult for them to obtain sufficient assistance from the permitting
authority. Thus, we conclude that factor two supports title V exemption
for the sources in these categories that we propose to exempt.
The third factor, which is closely related to the second factor, is
whether the costs of title V permitting for these area sources would be
justified, taking into consideration any potential gains in compliance
likely to occur for such sources. We explained above under the second
factor that the costs of compliance with title V would impose a
significant burden on many of the approximately 137,000 facilities
affected by this proposed rule. We also concluded in considering the
first factor that, while title V might impose additional requirements,
the monitoring, recordkeeping and reporting requirements in this
proposed NESHAP assure compliance with the emission standards, work
practices, and management practices imposed in the NESHAP. In addition,
below in our consideration of the fourth factor, we find that there are
adequate implementation and enforcement programs in place to assure
compliance with the NESHAP. Because the costs, both economic and non-
economic, of compliance with title V are high, and the potential for
gains in compliance is low, title V permitting is not justified for the
sources we propose to exempt. Accordingly, the third factor supports
title V exemptions for these area source categories, except as
discussed below.
The fourth factor we considered in determining if title V is
unnecessarily burdensome is whether there are implementation and
enforcement programs in place that are sufficient to assure compliance
with the NESHAP without relying on title V permits. EPA has implemented
regulations that provide States the opportunity to take delegation of
area source NESHAP, and we believe that State delegated programs are
sufficient to assure compliance with this NESHAP. See 40 CFR part 63,
subpart E (States must have adequate programs to enforce the CAA
section 112 regulations and provide assurances that they will enforce
the NESHP before EPA will delegate the program).
We also note that EPA retains authority to enforce this NESHAP
anytime under CAA sections 112, 113, and 114. Also, States and EPA
often conduct voluntary compliance assistance, outreach, and education
programs (compliance assistance programs), which are not required by
statute. We determined that these additional programs will supplement
and enhance the success of compliance with these proposed standards. We
believe that the statutory requirements for implementation and
enforcement of this NESHAP by the delegated States and EPA and the
additional assistance programs described above together are sufficient
to assure compliance with these proposed standards without relying on
title V permitting.
In light of all the information presented here, we believe that
there are implementation and enforcement programs in place that are
sufficient to assure compliance with the proposed standards without
relying on title V permitting for the sources we are proposing to
exempt.
Balancing the four factors for these area source categories
strongly supports the proposed finding that title V is unnecessarily
burdensome for the sources we propose to exempt. While title V might
add additional compliance requirements if imposed, we believe that
there would not be significant improvements to the compliance
requirements in this proposed rule because the proposed rule
requirements are specifically designed to assure compliance with the
emission standards imposed on the area sources we propose to exempt. We
further maintain that the economic and non-economic costs of compliance
with title V would impose a significant burden on the sources we
propose to exempt. We determined that the high relative costs would not
be justified given that there is likely to be little or no potential
gain in compliance if title V were required. And, finally, there are
adequate implementation and enforcement programs in place to assure
compliance with these proposed standards. Thus, we propose that title V
permitting is ``unnecessarily burdensome'' for these area source
categories, except as discussed below.
In addition to evaluating whether compliance with title V
requirements is ``unnecessarily burdensome'', EPA also considered,
consistent with guidance provided by the legislative history of CAA
section 502(a), whether exempting these area source categories from
title V requirements would adversely affect public health, welfare, or
the environment. Exemption of these area source categories from title V
requirements would not adversely affect public health, welfare, or the
environment because the level of control would remain the same if a
permit were required. The title V permit program does not impose new
substantive air quality control requirements on sources, but instead
requires that certain procedural measures be followed, particularly
with respect to determining compliance with applicable requirements. As
stated in our consideration of factor one for this category, title V
would not lead to significant improvements in the compliance
requirements applicable to existing or new area sources that we propose
to exempt.
[[Page 31913]]
Furthermore, we explained in the Exemption Rule that requiring
permits for the large number of area sources could, at least in the
first few years of implementation, potentially adversely affect public
health, welfare, or the environment by shifting State agencies
resources away from assuring compliance for major sources with existing
permits to issuing new permits for these area sources, potentially
reducing overall air program effectiveness. Based on the above
analysis, we conclude that title V exemptions for these area sources
would not adversely affect public health, welfare, or the environment
for all of the reasons explained above.
For the reasons stated here, we are proposing to exempt these area
source categories, except for certain synthetic area sources, as
explained below, from title V permitting requirements.
We have determined that it is not appropriate to exempt from Title
V requirements those synthetic area sources that installed air
pollution controls. Unlike many other area source categories that we
have exempted from title V while implementing the requirements of CAA
sections 112(c)(3) and 112(k)(3)(B), the boiler area source categories
include a number of synthetic area sources that installed air pollution
controls to become area sources. Synthetic area sources that installed
controls represent less than one percent of the total number of sources
that will be subject to the final rule. In fact, these sources are much
more like the major sources of HAP that will be subject to the Boiler
MACT. In addition, many of these sources are located in cities, and
often in close proximity to residential and commercial centers where
large numbers of people live and work. The record also indicates that
many of these synthetic area sources have significantly higher
emissions potential when uncontrolled than the other sources in the
boiler area source categories, even those that are synthetic minor
sources that took operational limits to attain area source status.
For these reasons, we believe that the additional public
participation and compliance benefits of additional informational,
monitoring, reporting, certification, and enforcement requirements that
exist in title V should be the same for a major source that installed a
control device after 1990 to become an area source as for a source that
is major and installed a control device to comply with an applicable
major source NESHAP, and thereby reduced emissions below major source
levels (10 tpy of a single HAP and 25 tpy of total HAP). Many of the
synthetic area sources that became area sources by virtue of installing
add-on controls are large facilities with comprehensive compliance
programs in place because their uncontrolled emissions would far exceed
the major source threshold. We maintain that requiring additional
public involvement and compliance assurance requirements through title
V is important to ensure that these sources are maintaining their
emissions at the area source level.
For these reasons above, this proposed rule requires title V
permits for major sources of HAP emissions that installed controls
after 1990 to become area sources of HAP emissions. We estimate that
approximately 170 sources that will be subject to this rule are either
required to have title V permits because of criteria pollutants or the
proposed rule will require the affected area sources to obtain title V
permits.
We are not requiring title V permits for sources that reduced their
emissions to area source levels by taking operational restrictions,
such as restricting hours of operation or production, or for natural
area sources, for the reasons set forth above.
VI. Summary of the Impacts of This Proposed Rule
A. What are the air impacts?
Table 2 of this preamble illustrates, for each subcategory, the
estimated emissions reductions achieved by this proposed rule (i.e.,
the difference in emissions between an area source boiler controlled to
the MACT/GACT level of control and boilers at the current baseline) for
new and existing sources. Nationwide emissions of total HAP (hydrogen
chloride, hydrogen fluoride, non-mercury metals, mercury, and VOC (for
organic HAP) will be reduced by about 1,200 tpy for existing units and
340 tpy for new units. Emissions of mercury will be reduced by about
0.7 tpy per year for existing units and by 0.1 tpy for new units.
Emissions of filterable PM will be reduced by about 6,300 tpy for
existing units and 1,300 tpy for new units. Emissions of non-mercury
metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt,
lead, manganese, nickel, and selenium) will be reduced by about 210 tpy
for existing units and will be reduced by 40 tpy for new units.
Additionally, EPA has estimated that conducting an annual tune-up could
potentially reduce emissions of organic HAP as a result of improved
combustion and reduced fuel use. POM reductions are represented by 7-
PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that
the energy efficient work and management practices may reduce emissions
of 7-PAH by 8 tpy for existing units and that the CO emission limit may
reduce emissions of 7-PAH by 1 tpy for new units. A discussion of the
methodology used to estimate baseline emissions and emissions
reductions is presented in ``Estimation of Impacts for Industrial,
Commercial, and Institutional Boilers Area Source NESHAP'' in the
docket.
Table 2--Summary of HAP Emissions Reductions for Existing and New Sources (tpy)
----------------------------------------------------------------------------------------------------------------
Non mercury
Source Subcategory PM metals \a\ Mercury POM \b\
----------------------------------------------------------------------------------------------------------------
Existing Units................ Coal............ 5,350 24 0.6 0.2
Biomass......... 760 10 0.003 5
Oil............. 230 175 0.03 3
New Units..................... Coal............ 510 3 0.09 0.02
Biomass......... 690 8 0.0003 0.5
Oil............. 100 28 0.005 0.5
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ POM is represented by total emissions of polycyclic aromatic hydrocarbons (7-PAH). It is assumed that
compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may
reduce emissions of 7-PAH by an equivalent amount.
[[Page 31914]]
B. What are the cost impacts?
To estimate the national cost impacts of this proposed rule for
existing sources, EPA developed several model boilers and determined
the cost of control for these model boilers. The EPA assigned a model
boiler to each existing unit based on the fuel, size, and current
controls. The analysis considered all air pollution control equipment
currently in operation at existing boilers. Model costs were then
assigned to all existing units that could not otherwise meet the
proposed standards. The resulting total national cost impact of this
proposed rule for existing units is $696 million dollars in total
annualized costs. The total annualized costs (new and existing) for
installing controls, conducting biennial tune-ups and an energy
assessment, and implementing testing and monitoring requirements, is
$1.0 billion. Table 3 of this preamble shows the total annualized cost
impacts for each subcategory.
Table 3--Summary of Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
Estimated/ Total
projected annualized
Source Subcategory number of cost (10\6\$/
affected units yr) \a\
----------------------------------------------------------------------------------------------------------------
Existing Units................................ Coal............................ 3,710 160
Biomass......................... 10,958 48
Oil............................. 168,003 436
Facility Energy Assessment.................... All............................. .............. 52
New Units \b\................................. Coal............................ 155 54
Biomass......................... 200 13
Oil............................. 6,424 244
----------------------------------------------------------------------------------------------------------------
\a\ TAC does not include fuel savings from improving combustion efficiency.
\b\ Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013).
Using DOE projections on fuel expenditures, as well as the history
of installation dates of area source boilers in the dataset, the number
of additional boilers that could be potentially constructed was
estimated. The resulting total national cost impact of this proposed
rule on new sources by the 3rd year, 2013, is $311 million dollars in
total annualized costs. When accounting for a 1 percent fuel savings
resulting from improvements to combustion efficiency, the total
national cost impact on new sources is $260 million.
A discussion of the methodology used to estimate cost impacts is
presented in the memorandum ``Estimation of Impacts for Industrial,
Commercial, and Institutional Boilers Area Source NESHAP'' in the
Docket.
C. 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 less than 0.01
percent. Because of higher domestic prices imports may rise by less
than 0.01 percent. Energy prices will not be affected.
Social costs are estimated to also be $0.5 billion in 2008 dollars.
This is estimated to made up of a $0.3 billion loss in domestic
consumer surplus, a $0.3 billion loss in domestic producer surplus, a
$0.1 billion increase in rest of the world surplus, and a $0.1 billion
net loss associated with new source costs and 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
[[Page 31915]]
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 sectors
in the EPA model that show a change in output. The total job losses are
estimated to be approximately 1,000.
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 1,000 jobs (-3.56 x
$0.5 billion x 0.60).\2\
---------------------------------------------------------------------------
\2\ Since Morgenstern's analysis reports environmental
expenditures in $1987, we make an inflation adjustment to 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
percent 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 4--Employment Changes: 2013
------------------------------------------------------------------------
Estimation method 1,000 jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets) -1.
(demand effect only).
Literature-based estimate (net effect [A + B +1 (-1 to +2).
+ C below]).
A. Literature-based estimate: Demand effect.. -1 (-3 to 0).
B. Literature-based estimate: Cost effect.... +1 (0 to +2).
C. Literature-based estimate: Factor shift +1 (0 to +2).
effect.
------------------------------------------------------------------------
Note: Totals may not add due to independent rounding. 95 percent
confidence intervals for literature-based estimates are shown in
parenthesis.
D. What are the social costs and benefits of this proposed rule?
We estimated the monetized benefits of this proposed regulatory
action to be $1.0 billion to $2.4 billion (2008$, 3 percent discount
rate) in the implementation year (2013). The monetized benefits of this
proposed regulatory action at a 7 percent discount rate are $910
million to $2.2 billion (2008$). 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.\3\ A summary of the
monetized benefits estimates at discount rates of 3 percent and 7
percent is in Table 5 of this preamble.
---------------------------------------------------------------------------
\3\ 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 31916]]
Table 5--Summary of the Monetized Benefits Estimates for the Proposed Boiler Area Source Rule 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................................... 2,682 $0.96 to $2.4............. $0.88 to $2.1.
PM2.5 Precursors........................ .............. .......................... ..........................
SO2..................................... 1,539 $0.31 to $0.76............ $0.28 to $0.68.
VOC..................................... 1,179 $0.01 to $0.04............ $0.01 to $0.03.
Total............................... .............. $1.0 to $2.4.............. $0.91 to $2.2.
----------------------------------------------------------------------------------------------------------------
\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), ecosystem effects, and visibility impairment
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 laid out in Fann et al. (2009).\4\
---------------------------------------------------------------------------
\4\ 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 \5\ and the extended Six Cities
cohort study.\6\ 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.
---------------------------------------------------------------------------
\5\ 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.
\6\ 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 \7\
provides an indication of the sensitivity of our results to various
assumptions.
---------------------------------------------------------------------------
\7\ 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 39,000 tons of carbon monoxide, 0.75 ton of mercury,
and 130 tons of HCl, 5 tons of HF, and 460 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
$0.5 billion (2008$) in the implementation year, and the monetized
benefits are $1.0 billion to $2.4 billion (2008$, 3 percent discount
rate) for that same year. The benefits at a 7 percent discount rate are
$910 million to $2.2 billion (2008$). Thus, net benefits of this
rulemaking are estimated at $500 million to $1.9 billion (2008$, 3
percent discount rate) and $400 million to $1.7 billion (2008$, 7
percent discount rate).
A summary of the monetized benefits, social costs, and net benefits
at discount rates of 3 percent and 7 percent is in Table 6 of this
preamble.
[[Page 31917]]
Table 6--Summary of the Monetized Benefits, Social Costs, and Net
Benefits for the Boiler Area Source Rule in 2013
[Billions of 2008$] \1\
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\.... $1.0 to $2.4...... $0.91 to $2.2.
Total Social Costs \3\.......... $0.50............. $0.5.
Net Benefits.................... $0.5 to $1.9...... $0.4 to $1.7.
---------------------------------------
Non-monetized Benefits.......... 39,000 tons of carbon monoxide.
130 tons of HCl.
5 tons of HF.
0.75 tons of mercury.
250 tons of other metals.
470 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.
E. What are the water and solid waste impacts?
The EPA estimated that no additional water usage would result from
the MACT floor level of control or GACT requirement. The fabric filter,
multiclone or combustion control devices used to meet the standards of
this proposed rule do not require any water to operate, nor do they
generate any wastewater.
The EPA estimated the additional solid waste that would result from
this proposed rule to be 14,300 tpy for existing sources due to the
dust and flyash captured by mercury and PM control devices. The cost of
handling the additional solid waste generated from existing sources is
$602,000 per year. For new sources installed by 2013, the EPA estimated
the additional solid waste that would result from this proposed rule to
be 1,800 tpy for new sources due to the dust and flyash captured by
mercury and PM control devices. The cost of handling the additional
solid waste generated from existing sources is $75,900 per year. 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 Area Source NESHAP'' in the Docket.
F. What are the energy impacts?
The EPA expects an increase of approximately 206 million kilowatt
hours (kWh) in national annual energy usage from existing sources as a
result of this proposed rule. The increase results from the electricity
required to operate control devices installed to meet this proposed
rule, such as fabric filters. Additionally, for new sources installed
by 2013, EPA expects an increase of approximately 22 million kWh in
national annual energy usage in order to operate the control devices.
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. Additionally, the EPA expects work
practice standards such as boilers tune-ups and combustion controls
such as new replacement burners and will improve the efficiency of
boilers. The EPA estimates existing area source facilities can save 20
trillion BTU of fuel each year. For new sources online by 2013, the EPA
estimates 2.3 trillion BTU per year of fuel can be conserved. This fuel
savings estimates includes only those fuel savings resulting from
liquid and coal fuels and it is based on the assumption that the work
practice standards will achieve 1 percent improvement in efficiency.
VII. Relationship of This Proposed Action to CAA Section 112(c)(6)
CAA section 112(c)(6) 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 (PAH) and extractable organic matter (EOM).)
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
[[Page 31918]]
controlled by the various post-combustion controls. The add-on PM
control systems (fabric filter) used to reduce mercury and/or PM
emissions further reduce emissions of these organic pollutants, as is
evidenced by performance data. Specifically, the emission tests
obtained at currently operating major source boilers show that the
proposed MACT regulations for area source boilers will reduce Hg
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 CAA section 112(c)(6).
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 product of incomplete 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 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 Review
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 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 5 of this
preamble.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by EPA has been assigned EPA ICR number 2253.01.
The recordkeeping and reporting requirements in this proposed rule
would be based on the information collection requirements in EPA's
NESHAP General Provisions (40 CFR part 63, subpart A). The
recordkeeping and reporting requirements in the General Provisions are
mandatory pursuant to section 114 of the CAA (42 U.S.C. 7414). All
information other than emissions data submitted to EPA pursuant to the
information collection requirements for which a claim of
confidentiality is made is safeguarded according to CAA section 114(c)
and EPA's implementing regulations at 40 CFR part 2, subpart B.
This proposed NESHAP would require applicable one-time
notifications according to the NESHAP General Provisions. Facility
owners or operators would be required to include compliance
certifications for the work practices and management practices in their
Notifications of Compliance Status. Recordkeeping would be required to
demonstrate compliance with emission limits, work practices, management
practices, monitoring, and applicability provisions. New affected
facilities would be required to comply with the requirements for
startup, shutdown, and malfunction plans/reports and to submit a
compliance report if a deviation occurred during the semiannual
reporting period.
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 $523 million. This includes 3.6
million labor hours per year at a cost of $336 million and total non-
labor capital costs of $186 million per year. This estimate includes
initial and annual performance tests, 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 were also included in the cost
estimates presented in the control costs impacts estimates in section
VI.B 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 767,403 hours per year at a total labor
cost of $37.6 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 the collection
displays a currently valid OMB control number. The OMB control numbers
for EPA's regulations in 40 CFR part 63 are listed in 40 CFR part 9.
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-2006-0790. 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.
C. Regulatory Flexibility Act (RFA)
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
[[Page 31919]]
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.
(1) 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.
(2) 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 each of
the Panel's recommendations regarding area source facilities.
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 recommendations is detailed below. As noted above, this proposal
includes proposed provisions for each of the Panel recommendations
regarding area source facilities.
(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 CAA section 112(h), that is, it
is impracticable to enforce the emission standards due to technical and
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) 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.
D. Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
[[Page 31920]]
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 requires us to establish NESHAP for both
major and area sources of HAP that are listed for regulation under CAA
section 112(c). CAA section 112(k)(3)(B) calls for EPA to identify at
least 30 HAP which, as the result of emissions from area sources, pose
the greatest threat to public health in the largest number of urban
areas. CAA section 112(c)(3) requires EPA to list sufficient categories
or subcategories of area sources to ensure that area sources
representing 90 percent of the emissions of the 30 urban HAP are
subject to regulation.
Under CAA section 112(d)(5), we may elect to promulgate standards
or requirements for area sources based on GACT used by those sources to
reduce emissions of HAP. Determining what constitutes GACT involves
considering the control technologies and management practices that are
generally available to the area sources in the source category. We also
consider the standards applicable to major sources in the analogous
source category and, as appropriate, the control technologies and
management practices at area and major sources in similar categories,
to determine if the standards, technologies, and/or practices are
transferable and generally available to area sources. In determining
GACT for a particular area source category, we consider the costs and
economic impacts of available control technologies and management
practices on that category.
While GACT may be a basis for standards for most types of HAP
emitted from area source, CAA section 112(c)(6) requires that source
categories accounting for emissions of the HAP listed in CAA section
112(c)(6) be subject to standards under CAA section 112(d)(2) for the
listed pollutants. Thus, CAA section 112(c)(6) requires that emissions
of each listed HAP for the listed categories be subject to MACT
regulation. The CAA section 112(c)(6) list of source categories
includes industrial boilers and institutional/commercial boilers.
Within these two source categories, coal combustion, oil combustion,
and wood combustion have been on the CAA section 112(c)(6) list because
of emissions of mercury and POM. We currently believe that regulation
of coal-fired boilers will ensure that we fulfill our obligation under
CAA section 112(c)(6) with respect to mercury reductions. Consequently,
we deem it reasonable to propose to regulate the coal-fired boilers
under MACT, rather than the biomass and oil-fired boilers, to obtain
additional mercury reductions towards achieving the CAA section
112(c)(6) obligation. We propose to regulate biomass-fired and oil-
fired boilers under GACT.
This proposed NESHAP would apply to all existing and new industrial
boilers, institutional boilers, and commercial boilers located at area
sources. 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 standards are
based represents the MACT floor for the listed CAA section 112(c)(6)
pollutants (mercury and POM) and GACT for the other urban HAP which
formed the basis for the listing of these two area source categories.
The proposed standards would require new coal-fired boilers to meet
MACT-based emission limits for mercury and CO (as a surrogate for POM)
and GACT-based emission limits for PM (as a surrogate for urban
metals). New biomass and oil-fired boilers would be required to meet
MACT-based CO emission limits and GACT-based emission limits for PM.
The emission limits for existing area source boilers are only
applicable to area source boilers that have a designed heat input
capacity of 10 MMBtu/h or greater. Existing large coal-fired boilers
would be required to meet MACT-based emission limits for mercury and
CO, and existing large biomass and oil-fired boilers would be subject
to MACT-based CO emission limits. As allowed under CAA section 112(h),
a work practice standard requiring the implementation of a tune-up
program is being proposed for existing area source boilers with a
designed heat input capacity of less than 10 MMBtu/h. An additional
``beyond-the-floor'' standard is being proposed for existing area
source facilities having an affected boiler with a heat input capacity
of 10 MMBtu/h or greater that requires the performance of an energy
assessment on the boiler and the facility to identify cost-effective
energy conservation measures.
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 $0.5 billion (2008 dollars).
It is estimated that 3 years after implementation of the proposed
rule, HAP would be reduced by hundreds of
[[Page 31921]]
tons, including reductions in metallic HAP including mercury,
hydrochloric acid, hydrogen fluoride, and several other organic HAP
from area source boilers. 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 reductions in PM2.5 and in
SO2 that would occur, including 2,700 tons of
PM2.5 and 1,500 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
range from $1.0 billion (2008 dollars) to $2.4 billion (2008 dollars)
when using a 3 percent discount rate (or from $0.9 billion (2008
dollars) to $2.2 billion (2008 dollars) when using a 7 percent discount
rate. 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 Reform Act requires that we estimate, where
accurate estimation is reasonably feasible, future compliance costs
imposed by the proposed rule and any disproportionate budgetary
effects. Our estimates of the future compliance costs of the proposed
rule are discussed previously in this preamble.
We do not believe that there will be any disproportionate budgetary
effects of the proposed rule on any particular areas of the country,
State or local governments, types of communities (e.g., urban, rural),
or particular industry segments. 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 Reform 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 (less than 0.01 percent). 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 Reform 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. Consistent with the intergovernmental
consultation provisions of section 204 of the UMRA, EPA has initiated
consultations with governmental entities affected by this proposed
rule. EPA invited the following 10 national organizations representing
State and local elected officials to a meeting held on March 24, 2010
in Washington DC: (1) National Governors Association; (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations of elected State and local officials have been
identified by EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. The
purposes of the consultation were to provide general background on the
proposal, answer questions, and solicit input from State/local
governments. During the meeting, officials expressed uncertainty with
regard to how boilers owned/operated by State and local entities would
be impacted, as well as with regard to the potential burden associated
with implementing the rule on State and local entities. To that end,
officials requested and EPA provided (1) model boiler costs, (2)
inventory of area source boilers (coal, oil, biomass only) for the 13
States for which we have an inventory, and (3) information on potential
size of boilers used for various facility types and sizes. EPA has not
received additional questions or requests from State or local
officials.
Consistent with section 205, EPA has identified and considered a
reasonable number of regulatory alternatives. 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 the
rule. As part of that process, EPA considered several options. Those
options included establishing emission limits, establishing work
practice standards, and establishing work practice standards and
requiring an energy assessment. The regulatory alternative selected is
a combination of the options considered and includes proposed
provisions regarding each of the SBAR Panel's recommendations for area
source boilers. The recommendations regard subcategorization, work
practice standards, and compliance costs (see section VIII.C. of this
preamble for more detail).
EPA determined subcategorization based on boiler type to be
appropriate because different types of units have different emission
characteristics which may affect the feasibility and effectiveness of
emission control. Thus, the proposal identifies three subcategories of
area source boilers: (1) Boilers designed for coal firing, (2) boilers
designed for biomass firing, and (3) boilers designed for oil firing.
[[Page 31922]]
The regulatory alternative upon which the proposed standards are
based represents the MACT floor for mercury for coal-fired boilers, the
MACT floor for POM (CO is used as a surrogate for POM) for coal,
biomass, and oil-fired boilers, and GACT for the other urban HAP (PM is
used as a surrogate for urban HAP metals and CO is used as a surrogate
for urban organic pollutants) for coal, biomass, and oil-fired boilers.
The emission limits for existing area source boilers are only
applicable to area source boilers that have a designed heat input
capacity of 10 MMBtu/h or greater. A work practice standard (for
mercury from coal-fired boilers and for POM from all boilers) or
management practice (for all other HAP, including mercury from biomass-
fired and oil-fired boilers) requiring the implementation of a tune-up
program is being proposed for existing area source boilers with a
designed heat input capacity of less than 10 MMBtu/h. An additional
``beyond-the-floor'' standard is being proposed for existing area
source facilities having an affected boiler with a heat input capacity
of 10 MMBtu/h or greater that requires the performance of an energy
assessment on the boiler and the facility to identify cost-effective
energy conservation measures.
The proposed use of surrogate pollutants would result in reduced
compliance costs because testing would only be required for the
surrogate pollutants (i.e., CO and PM) versus for the HAP (i.e., POM
and metals). The proposed work practice standard/management practice
also would result in reduced compliance costs with respect to
monitoring/testing for the smaller existing area source boilers. EPA's
proposed exemption of most area source facilities from title V permit
requirements also would reduce burden on area source boiler facilities.
This proposed rule is not subject to the requirements of section
203 of UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. While some small
governments may have boilers that would be affected by the proposed
rule, EPA's analysis shows that other public facilities that are
located at area source facilities owned by small entities would have
cost-to-revenue ratios exceeding 10 percent. Hospitals' and schools'
revenue tests fall below 1 percent. Because the proposed rule's
requirements apply equally to boilers owned and/or operated by
governments and to boilers owned and/or operated by private entities,
there would be no requirements that uniquely apply to such governments
or impose any disproportionate impacts on them.
E. Executive Order 13132: Federalism
Under Executive Order 13132, EPA may not issue an action that has
federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or EPA consults with
State and local officials early in the process of developing the
proposed action.
EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on State or local governments, and the Federal government will not
provide the funds necessary to pay those costs. Accordingly, EPA
provides the following federalism summary impact statement as required
by section 6(b) of Executive Order 13132.
Based on the estimates in EPA's RIA for today's action, the
proposed regulatory option, if promulgated, may have federalism
implications because the option may impose approximately $416 million
in annual direct compliance costs on an estimated 57,000 State or local
governments. Boiler inventories for the health services, educational
services, and government-owned buildings sectors from 13 States were
used to estimate the nationwide number of potentially impacted State or
local governments. Because the inventories for these sectors include
privately owned and Federal government owned facilities, the estimate
may include many facilities that are not State or local government
owned. Table 7 of this preamble presents estimates of the number of
potentially impacted State and local governments and their potential
annual compliance costs for each of the three sectors. In addition to
an estimate of the total number of potentially impacted facilities,
estimates for facilities with small boilers and for facilities with
large boilers are presented. Small boilers (boilers with heat input
capacity of less than 10 MMBtu/h) would be subject to a work practice
standard that requires a boiler tune-up every 2 years. Large coal-fired
boilers (boilers with heat input capacity of 10 MMBtu/h or greater)
would be subject to emission limits for mercury and CO, while large
biomass and oil-fired boilers would be subject to emission limits for
CO. All facilities with large boilers would be required to conduct a
one-time energy assessment.
Table 7--State and Local Governments Potentially Impacted by the Proposed Standards for Boilers at Area Source
Facilities
----------------------------------------------------------------------------------------------------------------
Number of potentially impacted
facilities Annual compliance costs to
Sector --------------------------------------- meet standards
Total Small Large
----------------------------------------------------------------------------------------------------------------
Health Services........................... 17,206 15,293 1,913 $143 million.
Educational Services...................... 34,052 33,303 749 $200 million.
Government-Owned Buildings................ 5,796 5,098 698 $73 million.
---------------------------------------------------------------------
Total................................. 57,054 53,694 3,360 $416 million.
----------------------------------------------------------------------------------------------------------------
EPA consulted with State and local officials in the process of
developing the proposed action to permit them to have meaningful and
timely input into its development. EPA met with 10 national
organizations representing State and local elected officials to provide
general background on the proposal, answer questions, and solicit input
from State/local governments. The UMRA discussion in this preamble
includes a description of the consultation.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed action
from State and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 9, 2000), requires EPA
to develop an accountable process to
[[Page 31923]]
ensure ``meaningful and timely input by tribal officials in the
development of regulatory policies that have tribal implications.'' The
proposed rule does not have tribal implications, as specified in
Executive Order 13175 (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.
The 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
the proposed rule on communities of tribal governments would not be
unique or disproportionate to the effect on other communities. Thus,
Executive Order 13175 does not apply to the proposed rule. EPA
specifically solicits additional comment on the proposed rule from
tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
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 the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
The 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 the 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 the
proposed rule.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211, (66 FR 28355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, OMB, 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 no significant changes for the energy sector for price,
production, or 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.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272
note) directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. The VCS are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
VCS bodies. The NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency does not use available and applicable VCS.
The proposed rule involves technical standards. The EPA cites the
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A,
3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 40 CFR part 60; 101A of 40
CFR part 61; and voluntary consensus standards: American Society for
Testing and Materials (ASTM) D6522-00, American Society of Mechanical
Engineers (ASME) PTC 19 (manual methods only), ASTM D6784-02, ASTM
D2234-D2234M-03, ASTM D6323-98, ASTM D2013-04, ASTM d5198-92, ASTM
D5865-04, ASTM E711-87, ASTM D3173-03, ASTM E871-82, and ASTM D6722-01.
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 are in the
docket for this rule.
The search for emissions measurement procedures identified 16 other
voluntary consensus standards. The EPA determined that these 16
standards identified for measuring emissions of the HAP or surrogates
subject to emission standards in this rule were impractical
alternatives to EPA test methods for the purposes of this rule.
Therefore, EPA does not intend to adopt these standards for this
purpose. The reasons for the determinations for the 16 methods can be
found in the docket to this rule.
Table 4 to subpart JJJJJJ of this proposed rule lists the testing
methods included in the regulation. Under section 3.7(f) and section
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 required testing methods,
performance specifications, or procedures.
EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.
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
[[Page 31924]]
make EJ 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
industrial, commercial, and institutional boilers that are area
sources. The industrial boiler source category includes boilers used in
manufacturing, processing, mining, refining, or any other industry. The
commercial boiler source category includes boilers used in commercial
establishments such as stores/malls, laundries, apartments,
restaurants, theaters, and hotels/motels. The institutional boiler
source category includes boilers used in medical centers (e.g.,
hospitals, clinics, nursing homes), educational and religious
facilities (e.g., schools, universities, places of worship), and
municipal buildings (e.g., courthouses, arts centers, prisons). There
are approximately 91,000 facilities affected by the proposed rule, most
of which are small entities. By the defined nature of the category,
many of these sources are located in close proximity to residential
areas, commercial centers, and other locations where large numbers of
people live and work.
Due to the large number of these sources, their nation-wide
dispersal, and the absence of site specific coordinates, EPA is unable
to examine the distributions of exposures and health risks attributable
to these sources among different socio-demographic groups for this
rule, or to relate the locations of expected emission reductions to the
locations of current poor air quality. However, the rule is anticipated
to have substantial emissions reductions of toxic air pollutants (See
Table 2.), some of which are potential carcinogens, neurotoxins, and
respiratory irritants. The rule will also result in substantial
reductions in criteria pollutants such as CO, PM, SO2, as
well as ozone precursors.
Because of the close proximity of these source categories to
people, the substantial emission reductions of air toxics resulting
from the implementation of this proposed rule is anticipated to have
health benefits for all persons living or going near these types of
sources. (Please refer to the RIA for this rulemaking, which is
available in the docket.) For example, there will be significant
reductions of mercury emissions which will reduce potential exposures
due to the atmospheric deposition of mercury for populations such as
subsistence fisherman. In addition, there will be substantial
reductions in other air toxics that can cause adverse health effects
such as ozone precursors which contribute to ``smog.'' This rule will
not cause an increase in any adverse human health or environmental
effects on any population, including any minority, low-income, or
Tribal populations.
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 an EJ communication 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, EPA will publicize the rulemaking via EJ
newsletters, Tribal newsletters, EJ listserves, and the Internet,
including Office of Policy, Economics, and Innovation's (OPEI)
Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/rulegate.nsf/content/index.html?opendocument). 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, local governments and communities the opportunity
to provide their comments on the permit conditions associated with
permitting these sources.
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 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.
Subpart A--[Amended]
2. Section 63.14 is amended by revising paragraphs (b)(27),
(b)(39), (b)(47), (b)(49), (b)(50), (b)(52), (b)(55), (b)(56), (b)(58),
(b)(61), (b)(62), and (i)(1) to read as follows:
63.14 Incorporation by reference.
* * * * *
(b) * * *
(27) ASTM D 6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,\1\ IBR
approved for Sec. 63.9307(c)(2), Table 4 to subpart ZZZZ, Table 5 to
subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
(39) ASTM Method D388-99 [egr]\1\, Standard Classification of Coals
by Rank\1\, IBR approved for Sec. 63.7575 and Sec. 63.11237.
* * * * *
(47) ASTM D5198-92 (Reapproved 2003), Standard Practice for Nitric
Acid Digestion of Solid Waste,\1\ IBR approved for Table 6 to subpart
DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
(49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory
Subsampling of Media Related to Waste Management Activities,\1\ IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
(50) ASTM E711-87 (Reapproved 1996), Standard Test Method for Gross
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter,\1\ IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
* * * * *
(52) ASTM E871-82 (Reapproved 1998), Standard Method of Moisture
Analysis of Particulate Wood Fuels,\1\ IBR approved for Table 6 to
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
(55) ASTM D2013-04, Standard Practice for Preparing Coal Samples
for Analysis, IBR approved for Table 6 to subpart DDDDD and Table 5 to
subpart JJJJJJ of this part.
(56) ASTM D2234-D2234M-03 [egr]\1\, Standard Practice for
Collection of a Gross Sample of Coal, IBR approved for Table 6 to
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
(58) ASTM D3173-03, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved
[[Page 31925]]
for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this
part.
(61) ASTM D6722-01, Standard Test Method for Total Mercury in Coal
and Coal Combustion Residues by the Direct Combustion Analysis, IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
(62) ASTM D5865-04, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Table 6 to subpart DDDDD and Table 5
to subpart JJJJJJ of this part.
* * * * *
(i) * * *
(1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.
63.865(b), 63.3166(a), 63.3360(e)(1)(iii), 63.3545(a)(3),
63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3),
63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), Table
5 to subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
3. Add subpart JJJJJJ to read as follows:
Subpart JJJJJJ--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
Area Sources
Sec.
What This Subpart Covers
63.11193 Am I subject to this subpart?
63.11194 What is the affected source of this subpart?
63.11195 Are any boilers not subject to this subpart?
63.11196 When do I have to comply with this subpart?
Emission Limits, Work Practice Standards, Emission Reduction Measures,
and Management Practices
63.11200 What are the subcategories of boilers?
63.11201 What standards must I meet?
Initial Compliance Requirements
63.11205 What are my general requirements for complying with this
subpart?
63.11210 What are my initial compliance requirements and by what
date must I conduct them?
63.11211 How do I demonstrate initial compliance with the emission
limits?
63.11212 What stack tests and procedures must I use for the
performance tests?
63.11213 What fuel analyses and procedures must I use for the
performance tests?
63.11214 When must I conduct subsequent performance tests?
63.11215 How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?
Continuous Compliance Requirements
63.11220 How do I monitor and collect data to demonstrate continuous
compliance?
63.11221 How do I demonstrate continuous compliance with the
emission limits?
63.11222 How do I demonstrate continuous compliance with the work
practice standards?
63.11223 What are my monitoring, installation, operation, and
maintenance requirements?
63.11225 What are my notification, reporting, and recordkeeping
requirements?
Other Requirements and Information
63.11235 What parts of the General Provisions apply to me?
63.11236 Who implements and enforces this subpart?
63.11237 What definitions apply to this subpart?
Table 1 to Subpart JJJJJJ of Part 63. Emission Limits
Table 2 to Subpart JJJJJJ of Part 63. Work Practice Standards
Table 3 to Subpart JJJJJJ of Part 63. Operating Limits for Boilers
With Emission Limits
Table 4 to Subpart JJJJJJ of Part 63. Performance (Stack) Testing
Requirements
Table 5 to Subpart JJJJJJ of Part 63. Fuel Analysis Requirements
Table 6 to Subpart JJJJJJ of Part 63. Applicability of General
Provisions to Subpart JJJJJJ
Subpart JJJJJJ--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
Area Sources
What This Subpart Covers
Sec. 63.11193 Am I subject to this subpart?
You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler as defined in Sec.
63.11237 that is located at, or is part of, an area source of hazardous
air pollutants (HAP), as defined in Sec. 63.2.
Sec. 63.11194 What is the affected source of this subpart?
(a) This subpart applies to each new or existing affected sources
as defined in paragraphs (a)(1) and (2) of this section.
(1) The affected source is the collection of all existing
industrial, commercial, and institutional boilers within a subcategory
located at an area source.
(2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler located
at an area source.
(b) An affected source is an existing source if you commenced
construction or reconstruction of the affected source on or before June
4, 2010.
(c) An affected source is a new source if you commenced
construction or reconstruction of the affected source after June 4,
2010.
(d) A boiler is a new affected source if you commenced fuel
switching from natural gas to coal, biomass, or oil after June 4, 2010.
(e) Any source that was a major source and installed a control
device on a boiler after November 15, 1990, and, as a result, became an
area source under 40 CFR part 63 is required to obtain a permit under
40 CFR part 70 or 40 CFR part 71. Otherwise, you are exempt from the
obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71,
provided you are not otherwise required by law to obtain a permit under
40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous
sentence, you must continue to comply with the provisions of this
subpart.
Sec. 63.11195 Are any boilers not subject to this subpart?
The types of boilers listed in paragraphs (a) through (e) of this
section are not subject to this subpart.
(a) Any boiler specifically listed as an affected source in another
standard(s) under this part.
(b) Any boiler specifically listed as an affected source in another
standard(s) established under section 129 of the Clean Air Act (CAA).
(c) A boiler required to have a permit under section 3005 of the
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g.,
hazardous waste boilers).
(d) A boiler that is used specifically for research and
development. This does not include boilers that only provide steam to a
process or for heating at a research and development facility.
(e) A gas-fired boiler as defined in this subpart.
Sec. 63.11196 What are my compliance dates?
(a) If you own or operate an existing affected source, you must
achieve compliance with the applicable provisions in this subpart no
later than [DATE 3 YEARS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER].
(b) If you start up a new affected source on or before [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
achieve compliance with the provisions of this subpart no later than
[DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
(c) If you start up a new affected source after [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
achieve compliance with the provisions of this
[[Page 31926]]
subpart upon startup of your affected source.
Emission Limits, Work Practice Standards, Emission Reduction Measures,
and Management Practices
Sec. 63.11200 What are the subcategories of boilers?
The subcategories of boilers are coal, biomass, and oil. Each
subcategory is defined in Sec. 63.11237.
Sec. 63.11201 What standards must I meet?
(a) You must comply with each emission limit specified in Table 1
of this subpart that applies to your boiler.
(b) You must comply with each work practice standard, emission
reduction measure, and management practice specified in Table 2 of this
subpart that applies to your boiler.
(c) These standards apply at all times.
Initial Compliance Requirements
Sec. 63.11205 What are my general requirements for complying with
this subpart?
(a) 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.
(b) You can demonstrate compliance with any applicable mercury
emission limit using fuel analysis if the emission rate calculated
according to Sec. 63.11211(b) is less than the applicable emission
limit. Otherwise, you must demonstrate compliance using stack testing.
Sec. 63.11210 What are my initial compliance requirements and by what
date must I conduct them?
(a) You must demonstrate initial compliance with each emission
limit specified in Table 1 of this subpart that applies to you by
either conducting performance (stack) tests, as applicable, according
to Sec. 63.11212 and Table 4 of this subpart or conducting fuel
analyses, as applicable, according to Sec. 63.11213 and Table 5 to
this subpart.
(b) For affected sources that have an applicable carbon monoxide
(CO) emission limit, your initial compliance requirements depend on the
rated capacity of your boiler. If your boiler has a heat input capacity
between 10 and 100 million British thermal units (MMBtu) per hour, your
initial compliance demonstration is conducting a performance test for
CO according to Table 4 to this subpart. If your boiler has a heat
input capacity of 100 MMBtu per hour or greater, your initial
compliance demonstration is conducting a performance evaluation of your
continuous emission monitoring system (CEMS) for CO according to Sec.
63.11223.
(c) For existing affected sources that have applicable emission
limits, you must demonstrate initial compliance no later than 180 days
after the compliance date that is specified in Sec. 63.11196 and
according to the applicable provisions in Sec. 63.7(a)(2).
(d) For existing affected sources that have applicable work
practice standards or emission reduction measures, you must demonstrate
initial compliance no later than the compliance date that is specified
in Sec. 63.11196 and according to the applicable provisions in Sec.
63.7(a)(2).
(e) For new affected sources, you must demonstrate initial
compliance no later than 180 calendar days after [INSERT THE DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 180
calendar days after startup of the source, whichever is later,
according to Sec. 63.7(a)(2)(ix).
Sec. 63.11211 How do I demonstrate initial compliance with the
emission limits?
(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 tests according to Sec. 63.11212 and Table 4 to this
subpart and conducting CMS performance evaluations according to Sec.
63.11223.
(b) If you elect to demonstrate compliance with an applicable
mercury emission limit through fuel analysis, you must conduct fuel
analyses according to Sec. 63.11213 and follow the procedures in
paragraphs (b)(1) through (3) of this section.
(1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your boiler that would result in the
maximum emission rates of mercury that you elect to demonstrate
compliance through fuel analysis.
(2) You must determine the 90th percentile confidence level fuel
mercury concentration of the composite samples analyzed for each fuel
type using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.001
Where:
P90 = 90th percentile confidence level mercury
concentration, in pounds per million Btu;
mean = Arithmetic average of the fuel mercury concentration in the
fuel samples analyzed according to Sec. 63.11213, in units of
pounds per million Btu;
SD = Standard deviation of the mercury concentration in the fuel
samples analyzed according to Sec. 63.11213, 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 mercury emission
limit, the emission rate that you calculate for your boiler using
Equation 1 of this section must be less than the applicable mercury
emission limit.
Sec. 63.11212 What stack tests and procedures must I use for the
performance tests?
(a) You must conduct all performance tests according to the
requirements in Sec. 63.7.
(b) You must conduct each stack test according to the requirements
in Table 4 to this subpart.
(c) You must conduct stack tests at the maximum normal operating
load while burning the type of fuel or mixture of fuels that have the
highest content of mercury, and you must demonstrate initial compliance
based on these tests.
(d) You must conduct a minimum of three separate test runs for each
performance test required in this section, as specified in Sec.
63.7(e)(3). The sampling time for each test run must last at least 1
hour except that the sampling time for the test runs conducted for
mercury emissions must last at least 2 hours.
(e) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 of appendix A to part 60 of this chapter to convert the
measured particulate matter concentrations and the measured mercury
concentrations that result from the initial performance test to pounds
per million Btu heat input emission rates.
Sec. 63.11213 What fuel analyses and procedures must I use for the
performance tests?
(a) You must conduct fuel analyses according to the procedures in
[[Page 31927]]
paragraphs (b) and (c) of this section and Table 5 to this subpart, as
applicable.
(b) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in Table 5 of this subpart.
Each composite sample will consist of a minimum of three samples
collected at approximately equal intervals during a test run period.
(c) Determine the concentration of mercury in the fuel in units of
pounds per million Btu of each composite sample for each fuel type
according to the procedures in Table 5 to this subpart.
Sec. 63.11214 When must I conduct subsequent performance tests?
(a) You must conduct all applicable performance (stack) tests
according to Sec. 63.11212 on an annual basis, unless you follow the
requirements listed in paragraphs (b) through (d) of this section.
Annual performance tests must be completed between 10 and 12 months
after the previous performance test, unless you follow the requirements
listed in paragraphs (b) through (d) of this section.
(b) You can conduct performance stack tests less often for
particulate matter or mercury 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.
(c) If your boiler continues to meet the emission limit for
particulate matter or mercury, 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.
(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 consecutive 3-year period
show compliance.
(e) If you have an applicable CO emission limit and your boiler has
a heat input capacity between 10 and 100 MMBtu per hour, you must
conduct annual performance tests for CO according to Sec. 63.11211.
Each annual performance test must be conducted between 10 and 12 months
after the previous performance test.
(f) If you demonstrate compliance with the mercury based on fuel
analysis, you must conduct a fuel analysis according to Sec. 63.11213
for each type of fuel burned monthly. If you plan to burn a new type of
fuel or fuel mixture, you must conduct a fuel analysis before burning
the new type of fuel or mixture in your boiler. You must recalculate
the mercury emission rate using Equation 1 of Sec. 63.11211. The
recalculated mercury emission rate must be less than the applicable
emission limit.
Sec. 63.11215 How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?
(a) If you own or operate an existing boiler with a heat input
capacity of less than 10 million Btu per hour, you must submit a signed
statement in the Notification of Compliance Status report that
indicates that you conducted a tune-up of the boiler.
(b) If you own or operate an existing affected boiler with a heat
input capacity of 10 million Btu per hour or greater, you must submit
the energy assessment report, along with a signed certification that
the assessment is an accurate depiction of your facility.
Continuous Compliance Requirements
Sec. 63.11220 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. 63.11223.
(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. 63.11221 How do I demonstrate continuous compliance with the
emission limits?
(a) You must demonstrate continuous compliance with each emission
limit and operating limit in Tables 1 and 3 to this subpart that
applies to you according to paragraphs (a)(1) through (5) 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
63.11196, 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 3 to this subpart at all
times. Operation above the established maximum or below the established
minimum operating limits shall constitute a deviation of established
operating limits. Operating limits are confirmed or reestablished
during performance tests.
(2) If you have an applicable mercury emission limit, you must keep
records of the type and amount of all fuels burned in each boiler
during the reporting period to demonstrate that all fuel types and
mixtures of fuels burned would result in lower emissions of mercury
than the applicable emission limit.
(3) If you have you have an applicable mercury emission limit and
you plan to burn a new type of fuel, you must determine the mercury
concentration for any new fuel type in units of pounds per million Btu,
based on supplier data or your own fuel analysis and meet the
requirements in paragraphs (a)(3)(i) or (ii) of this section.
(i) The recalculated mercury emission rate must be less than the
applicable emission limit.
(ii) If the results are higher than mercury fuel input 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. 63.11212 to demonstrate that the mercury
emissions do not exceed the emission limit.
(4) 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 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
[[Page 31928]]
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.
(5) If you have an applicable CO emission limit and you are
required to install a CEMS according to Sec. 63.11223, then you must
continuously monitor CO according to Sec. Sec. 63.11223(a) and
63.11220 and maintain a CO emission level below your applicable CO
emission limit in Table 1 to this subpart at all times.
(b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 and 3 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. 63.11224.
Sec. 63.11222 How do I demonstrate continuous compliance with the
work practice and management practice standards?
(a) For affected sources subject to the work practice standard or
the management practices, you must keep records as required in Sec.
63.11224(c) to demonstrate continuous compliance.
(b) You must conduct a tune-up of the boiler biennially to
demonstrate continuous compliance as specified in paragraphs (b)(1)
through (6) of this section.
(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 parts
per million, by volume, dry basis (ppmvd), before and after the
adjustments are made; and
(6) Maintain on-site and submit, if requested by the Administrator,
an annual report containing the information in paragraphs (b)(6)(i)
through (iii) of this section,
(i) 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;
(ii) A description of any corrective actions taken as a part of the
combustion adjustment; and
(iii) The type and amount of fuel used over the 12 months prior to
the annual adjustment.
Sec. 63.11223 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If you are using a control device to comply with the emission
limits specified in Table 1 of this subpart, you must maintain each
operating limit in Table 3 of this subpart that applies to your boiler.
If you use a control device not covered in Table 3, 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) If you demonstrate compliance with any applicable emission
limit through stack testing, you must develop a site-specific
monitoring plan according to the requirements in paragraphs (b)(1)
through (4) of this section. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec. 63.8(f).
(1) For each continuous monitoring system (CMS) required in this
section, you must develop, and submit to the EPA Administrator for
approval upon request, a site-specific monitoring plan that addresses
paragraphs (b)(1)(i) through (iii) of this section. You must submit
this site-specific monitoring plan (if requested) at least 60 days
before your initial performance evaluation of your CMS.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected 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 (b)(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), (3), and (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.
(c) If you have an operating limit that requires the use of a CMS,
you must install, operate, and maintain each continuous parameter
monitoring system (CPMS) according to the procedures in paragraphs
(c)(1) through (5) of this section.
(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 period for which the monitoring
system is out-of-control and data are not available for required
calculations constitutes a deviation from the monitoring requirements.
(4) Determine the 3-hour block average of all recorded readings,
except as provided in paragraph (c)(3) of this section.
(5) Record the results of each inspection, calibration, and
validation check.
(d) If you have an applicable opacity operating limit, you must
install, operate, certify and maintain each
[[Page 31929]]
continuous opacity monitoring system (COMS) according to the procedures
in paragraphs (d)(1) through (7) of this section by the compliance date
specified in Sec. 63.11196.
(1) Each COMS must be installed, operated, and maintained according
to PS 1 of 40 CFR part 60, appendix B.
(2) You must conduct a performance evaluation of each COMS
according to the requirements in Sec. 63.8 and according to PS 1 of 40
CFR part 60, appendix B.
(3) As specified in Sec. 63.8(c)(4)(i), each COMS must complete a
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
(4) The COMS data must be reduced as specified in Sec. 63.8(g)(2).
(5) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
COMS according to the requirements in Sec. 63.8(d). At a minimum, the
monitoring plan must include a daily calibration drift assessment, a
quarterly performance audit, and an annual zero alignment audit of each
COMS.
(6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). Identify periods the COMS is out of control including any
periods that the COMS fails to pass a daily calibration drift
assessment, a quarterly performance audit, or an annual zero alignment
audit.
(7) You must determine and record all the 1-hour block averages
collected for periods during which the COMS is not out of control.
(e) If you have an applicable CO emission limit and your boiler has
a heat input capacity of 100 MMBtu per hour or greater, you must
install, operate, and maintain a CEMS for CO and oxygen according to
the procedures in paragraphs (e)(1) through (6) of this section by the
compliance date specified in Sec. 63.11196. The CO and oxygen shall be
monitored at the same location at the outlet of the boiler.
(1) Each CEMS must be installed, operated, and maintained according
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and
according to the site-specific monitoring plan developed according to
Sec. 63.11223.
(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 all daily averages. A new daily
average emission rate is calculated as the average of all of the hourly
CO emission data for the calendar day.
(6) For purposes of calculating data averages, you must not use
data recorded during periods of monitoring malfunctions, associated
repairs, out-of-control periods, required quality assurance or control
activities, or when your boiler is operating at less than 50 percent of
its rated capacity. You must use all the data collected during all
other periods in assessing compliance. Any period for which the
monitoring system is out of control and data are not available for
required calculations constitutes a deviation from the monitoring
requirements.
(f) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
CEMS according to the requirements in Sec. 63.8(d).
Sec. 63.11224 What are my notification, reporting, and recordkeeping,
requirements?
(a) You must submit the notifications specified in paragraphs
(a)(1) through (a)(4) of this section.
(1) You must submit all of the notifications in Sec. Sec. 63.5(b),
63.7(b): 63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that
apply to you by the dates specified in those sections.
(2) As specified in Sec. 63.9(b)(2), you must submit the Initial
Notification no later than 120 calendar days after [INSERT THE DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 120
days after the source becomes subject to the standard.
(3) You must submit the Notification of Compliance Status in
accordance with Sec. 63.9(h) no later than 120 days after the
applicable compliance date specified in Sec. 63.11196 unless you must
conduct a performance test. If you must conduct a performance test, you
must submit the Notification of Compliance Status within 60 days of
completing the performance test. 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:
(i) ``This facility complies with the requirements in Sec.
63.11222(b) to conduct a biennial tune-up of the boiler''.
(ii) ``This facility has had an energy assessment performed
according to Sec. 63.11215.''
(iii) This certification of compliance by the owner or operator
that installs bag leak detection systems: ``This facility has prepared
a bag leak detection system monitoring plan in accordance with Sec.
63.11221 and will operate each bag leak detection system according to
the plan.''
(4) If you are using data from a previously conducted emission test
to serve as documentation of conformance with the emission standards
and operating limits of this subpart consistent with Sec.
63.7(e)(2)(iv), you must submit the test data in lieu of the initial
performance test results with the Notification of Compliance Status
required under paragraph (a)(3) of this section.
(b) You must prepare, by March 1 of each year, an annual compliance
certification report for the previous calendar year containing the
information specified in paragraphs (b)(1) through (b)(3) of this
section. You must submit the report by March 15 if you had any instance
described by paragraph (b)(3) of this section.
(1) Company name and address.
(2) Statement by a responsible official, with the official's name,
title, phone number, e-mail address, and signature, certifying the
truth, accuracy and completeness of the notification and a statement of
whether the source has complied with all the relevant standards and
other requirements of this subpart.
(3) If the source is not in compliance, include a description of
deviations from the applicable requirements, the time periods during
which the deviations occurred, and the corrective actions taken.
(4) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the reporting period,
including, but not limited to, a description of the fuel, including
whether the fuel has received a non-waste determination by you or EPA,
and the total fuel usage amount with units of measure.
(c) You must maintain the records specified in paragraphs (c)(1)
through (5) of this section.
(1) As required in Sec. 63.10(b)(2)(xiv), you must keep a copy of
each notification and report that you submitted to comply with this
subpart and all documentation supporting any Initial Notification or
Notification of Compliance Status that you submitted.
(2) You must keep records to document conformance with the work
practices, emission reduction measures, and management practices
required by
[[Page 31930]]
Sec. 63.11215 as specified in paragraphs (c)(2)(i) through (iv) of
this section.
(i) Records must identify each boiler, the date of tune-up, the
procedures followed for tune-up, and the manufacturer's specifications
to which the boiler was tuned.
(ii) Records documenting monthly fuel use by each boiler, including
the type(s) of fuel, including, but not limited to, a description of
the fuel, including whether the fuel has received a non-waste
determination by you or EPA, and the total fuel usage amount with units
of measure.
(3) For sources that demonstrate compliance through fuel analysis,
a copy of all calculations and supporting documentation that were done
to demonstrate compliance with the mercury emission limits. Supporting
documentation should include results of any fuel analyses. You can use
the results from one fuel analysis for multiple boilers provided they
are all burning the same fuel type.
(4) You must keep the records of all inspection and monitoring data
required by Sec. Sec. 63.11221 and 63.11222, and the information
identified in paragraphs (c)(4)(i) through (vi) of this section for
each required inspection or monitoring.
(i) The date, place, and time of the monitoring event;
(ii) Person conducting the monitoring;
(iii) Technique or method used;
(iv) Operating conditions during the activity;
(v) Results, including the date, time, and duration of the period
from the time the monitoring indicated a problem to the time that
monitoring indicated proper operation; and
(vi) Maintenance or corrective action taken (if applicable).
(5) If you use a bag leak detection system, you must keep the
records specified in paragraphs (c)(5)(i) through (iii) of this
section.
(i) Records of the bag leak detection system output.
(ii) Records of bag leak detection system adjustments, including
the date and time of the adjustment, the initial bag leak detection
system settings, and the final bag leak detection system settings.
(iii) The date and time of all bag leak detection system alarms,
and for each valid alarm, the time you initiated corrective action, the
corrective action taken, and the date on which corrective action was
completed.
(d) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1). As specified in
Sec. 63.10(b)(1), you must keep each record for 5 years following the
date of each recorded action. You must keep each record onsite for at
least 2 years after the date of each recorded action according to Sec.
63.10(b)(1). You may keep the records offsite for the remaining 3
years.
(e) For affected facilities having applicable emission limits, you
must submit an electronic copy of stack test reports to EPA's WebFIRE
data base, the owner or operator of an affected facility shall enter
the test data into EPA's data base using the Electronic Reporting Tool
located at http://www.epa.gov/ttn/chief/ert/ert_tool.html.
Other Requirements and Information
Sec. 63.11235 What parts of the General Provisions apply to me?
Table 6 to this subpart shows which parts of the General Provisions
in Sec. Sec. 63.1 through 63.15 apply to you.
Sec. 63.11236 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by 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 has the authority to implement and
enforce this subpart. You should contact your EPA Regional Office to
find out if implementation and enforcement of 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 contained in paragraphs (c) of this section
are retained by the EPA Administrator and are not transferred to the
State, local, or tribal agency.
(c) The authorities that cannot be delegated to State, local, or
tribal agencies are specified in paragraphs (c)(1) through (5) of this
section.
(1) Approval of an alternative non-opacity emission standard and
work practice standards in Sec. 63.11223(a).
(2) Approval of alternative opacity emission standard under Sec.
63.6(h)(9).
(3) Approval of major change to test methods under Sec.
63.7(e)(2)(ii) and (f). A ``major change to test method'' is defined in
Sec. 63.90.
(4) Approval of a major change to monitoring under Sec. 63.8(f). A
``major change to monitoring'' is defined in Sec. 63.90.
(5) Approval of major change to recordkeeping and reporting under
Sec. 63.10(f). A ``major change to recordkeeping/reporting'' is
defined in Sec. 63.90.
Sec. 63.11237 What definitions apply to this subpart?
Terms used in this subpart are defined in the CAA, in Sec. 63.2
(the General Provisions), and in this section as follows:
Bag leak detection system means an instrument that is capable of
monitoring particulate matter loadings in the exhaust of a fabric
filter (i.e., baghouse) in order to detect bag failures. A bag leak
detection system includes, but is not limited to, an instrument that
operates on electrodynamic, triboelectric, light scattering, light
transmittance, or other principle to monitor relative particulate
matter loadings.
Biomass 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 not solid waste.
Biomass subcategory includes any boiler that burns any amount of
biomass, but no coal, either alone or in combination with liquid fuels
or gaseous fuels.
Boiler means an enclosed combustion device in which water is heated
to recover 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
the 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 D388-99e1, ``Standard Specification for
Classification of Coals by Rank\1\'' (incorporated by reference, see
Sec. 63.14(b)) and synthetic fuels derived from coal including but not
limited to, solvent-refined coal, coal-oil mixtures, and coal-water
mixtures. Coal derived gases are excluded from this definition.
Coal subcategory includes any boiler that burns any coal alone or
at least 10
[[Page 31931]]
percent coal on an annual heat input basis in combination with biomass,
liquid fuels, or gaseous fuels.
Commercial boiler means a boiler used in commercial establishments
such as hotels, restaurants, and laundries to provide electricity,
steam, and/or hot water that does not combust solid waste, as that term
is defined by the Administrator under RCRA.
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(3) 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.
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material. Sorbent injection systems
in fluidized bed boilers are included in this definition.
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 5
to this subpart:
(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 mercury using an aliquot of
the dried sample, then the drying temperature must be modified to
prevent vaporizing this metal. 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 mercury concentration mathematically
adjusted to a dry basis.
(6) An equivalent mercury determinative or analytical procedure
means a published VCS or EPA method that clearly states that the
standard, practice, or method is appropriate for mercury and the fuel
matrix and has a published detection limit equal or lower than the
methods listed in Table 5 to this subpart 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 part 60 and 40 CFR part 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, distillate oil,
residual oil.
Gaseous fuels includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, refinery gas, and biogas.
Gas-fired boiler includes any boiler that burns gaseous fuels not
combined with any solid fuels, burns liquid fuel only during periods of
gas curtailment, gas supply emergencies, or periodic testing on liquid
fuel. Periodic testing of liquid fuel shall not exceed a combined total
of 48 hours during any calendar year.
Heat input means heat derived from combustion of fuel in a boiler
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.
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam, hot water,
and/or electricity that does not combust solid waste, as that term is
defined by the Administrator under RCRA.
Institutional boiler means a boiler used in institutional
establishments such as medical centers, research centers, and
institutions of higher education to provide electricity, steam, and/or
hot water that does not combust solid waste, as that term is defined by
the Administrator under RCRA.
Liquid fuel means petroleum, distillate oil, residual oil, any form
of liquid fuel derived from petroleum, on-spec used oil, and biodiesel.
Minimum sorbent flow rate means 90 percent of the test average
sorbent (or activated carbon) flow rate measured according to Table 6
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)).
[[Page 31932]]
Oil subcategory includes any boiler that does not burn any solid
fuel and burns any liquid fuel either alone or in combination with
gaseous fuels. Gas boilers that burn liquid fuel during periods of gas
curtailment, gas supply emergencies, or for periodic testing of liquid
fuel are not included in this definition.
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.
Performance testing means the collection of data resulting from the
execution of a test method used (either by stack testing or fuel
analysis) to demonstrate compliance with a relevant emission standard.
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.
Qualified personnel mean specialists in evaluating energy systems,
such as, those who have successfully completed the DOE Qualified
Specialist program for all systems, Certified Energy Managers certified
by the Association of Energy Engineers, or the equivalent.
Responsible official means responsible official as defined in 40
CFR 70.2.
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.
Waste heat boiler means a device that recovers normally unused
energy and converts it to usable heat. Waste heat boilers incorporating
duct or supplemental burners that are designed to supply 50 percent or
more of the total rated heat input capacity of the waste heat boiler
are not considered waste heat boilers, but are considered boilers.
Waste heat boilers are also referred to as heat recovery steam
generators.
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.
As stated in Sec. 63.11201, you must comply with the following
applicable emission limits:
Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
------------------------------------------------------------------------
For the following You must meet the
If your boiler is in this pollutants . . . following emission
subcategory . . . limits . . .
------------------------------------------------------------------------
1. New coal................... a. Particulate 0.03 lb per MMBtu of
Matter. heat input.
b. Mercury....... 0.000003 lb per MMBtu
of heat input.
c. Carbon 310 ppm by volume on
Monoxide. a dry basis
corrected to 7
percent oxygen
(daily average).
2. New biomass................ a. Particulate 0.03 lb per MMBtu of
Matter. heat input.
b. Carbon 100 ppm by volume on
Monoxide. a dry basis
corrected to 7
percent oxygen
(daily average).
3. New oil.................... a. Particulate 0.03 lb per MMBtu of
Matter. heat input.
b. Carbon 1 ppm by volume on a
Monoxide. dry basis corrected
to 3 percent oxygen
(daily average).
4. Existing coal (units with a. Mercury....... 0.000003 lb per MMBtu
heat input capacity of 10 b. Carbon of heat input.
million Btu per hour or Monoxide. 310 ppm by volume on
greater). a dry basis
corrected to 7
percent oxygen
(daily average).
5. Existing biomass (units Carbon Monoxide.. 160 ppm by volume on
with heat input capacity of a dry basis
10 million Btu per hour or corrected to 7
greater). percent oxygen
(daily average).
6. Existing oil (units with Carbon Monoxide.. 2 ppm by volume on a
heat input capacity of 10 dry basis corrected
million Btu per hour or to 3 percent oxygen
greater). (daily average).
------------------------------------------------------------------------
As stated in Sec. Sec. 63.11202 and 63.11203, you must comply with
the following applicable work practice standards:
Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
Reduction Measures, and Management Practices
------------------------------------------------------------------------
If your boiler is in this
subcategory . . . You must meet the following . . .
------------------------------------------------------------------------
1. Existing coal, biomass, or oil a. Conduct a tune-up of the boiler
(units with heat input capacity biennially as specified in Sec.
of less than 10 million Btu per 63.11222.
hour).
2. Existing coal, biomass, or oil Must have an energy assessment
(units with heat input capacity performed by qualified personnel
of 10 million Btu per hour and which includes:
greater).
(1) 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) a review of available
architectural and engineering
plans, facility operation and
maintenance procedures and logs,
and fuel usage,
(5) a list of major energy
conservation measures,
(6) the energy savings potential
of the energy conservation
measures identified,
[[Page 31933]]
(7) a comprehensive report
detailing the ways to improve
efficiency, the cost of specific
improvements, benefits, and the
time frame for recouping those
investments.
------------------------------------------------------------------------
As stated in Sec. 63.11201, you must comply with the applicable
operating limits:
Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers with
Mercury Emission Limits
------------------------------------------------------------------------
If you demonstrate compliance with
applicable mercury emission limits You must meet these operating limits
using . . . . . .
------------------------------------------------------------------------
1. Fabric filter control.......... a. Maintain opacity to less than or
equal to 10 percent opacity (daily
block average); OR
b. Install and operate a bag leak
detection system according to Sec.
63.11221 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.
2. Electrostatic precipitator Maintain opacity to less than or
control. equal to 10 percent opacity (daily
block average).
3. Dry scrubber or carbon Maintain the minimum sorbent or
injection control. carbon injection rate at or above
the operating levels established
during the performance test that
demonstrated compliance with the
applicable emission limit for
mercury.
4. Fuel analysis.................. Maintain the fuel type or fuel
mixture (annual average) such that
the mercury emission rates
calculated according to Sec.
63.11211(c) is less than the
applicable emission limits for
mercury.
------------------------------------------------------------------------
As stated in Sec. 63.11212, you must comply with the following
requirements for performance (stack) test for new affected sources:
Table 4 to Subpart JJJJJJ of Part 63--Performance (Stack) Testing
Requirements
------------------------------------------------------------------------
To conduct a performance
test for the following You must . . . Using . . .
pollutant . . .
------------------------------------------------------------------------
1. Particulate Matter....... a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASTM D6522-00
(IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part
10(1981) (IBR, see
Sec. 63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 5 or 17
particulate matter (positive pressure
emission fabric filters must
concentration. use Method 5D) in
appendix A to part
60 of this chapter.
f. Convert emissions Method 19 F-factor
concentration to lb/ methodology in
MMBtu emission appendix A to part
rates. 60 of this chapter.
2. Mercury.................. a. Select sampling Method 1 in appendix
ports location and A to part 60 of
the number of this chapter.
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASTM D6522-00
(IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part
10(1981)(IBR, see
Sec. 63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 29 in
mercury emission appendix A to part
concentration. 60 of this chapter
or Method 101A in
appendix B to part
61 of this chapter
or ASTM Method
D6784-02 (IBR, see
Sec. 63.14(b)).
f. Convert emissions Method 19 F-factor
concentration to lb/ methodology in
MMBtu emission appendix A to part
rates. 60 of this chapter.
3. Carbon Monoxide.......... a. Select the Method 1 in appendix
sampling ports A to part 60 of
location and the this chapter.
number of traverse
points.
b. Determine Method 2, 2F, or 2G
velocity and in appendix A to
volumetric flow- part 60 of this
rate of the stack chapter.
gas.
[[Page 31934]]
c. Determine oxygen Method 3A or 3B in
and carbon dioxide appendix A to part
concentrations of 60 of this chapter,
the stack gas. or ASTM D6522-00
(IBR, see Sec.
63.14(b)), or ASME
PTC 19, Part
10(1981)(IBR, see
Sec. 63.14(i)).
d. Measure the Method 4 in appendix
moisture content of A to part 60 of
the stack gas. this chapter.
e. Measure the Method 10, 10A, or
carbon monoxide 10 B in appendix A
emission to part 60 of this
concentration. chapter or ASTM
D6522-00 (IBR, see
Sec. 63.14(b).
f. Convert emissions Method 19 F-factor
concentration to lb/ methodology in
MMBtu emission appendix A to part
rates. 60 of this chapter.
------------------------------------------------------------------------
As stated in Sec. 63.11213, you must comply with the following
requirements for fuel analysis testing for new affected sources:
Table 5 to Subpart JJJJJJ 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. 63.11213(c) or ASTM
D2234-D2234M-03[egr
]\1\ (for coal)
(IBR, see Sec.
63.14(b)) or ASTM
D6323-98 (2003)
(for biomass) (IBR,
see Sec.
63.14(b)) or
equivalent.
b. Compose fuel Procedure in Sec.
samples. 63.11213(c) or
equivalent.
c. Prepare SW-846-3050B (for
composited fuel solid samples) or
samples. SW-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 fuel coal) (IBR, see
type. Sec. 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 of see Sec.
the fuel type. 63.14(b)) or ASTM
E871-82 (1998)
(IBR, see Sec.
63.14(b)) or
equivalent.
f. Measure mercury ASTM D6722-01 (for
concentration in coal) (IBR, see
fuel sample. Sec. 63.14(b)) or
SW-846-7471A (for
solid samples) or
SW-846 7470A (for
liquid samples) or
equivalent.
g. Convert
concentrations into
units of lb/MMBtu
of heat content.
------------------------------------------------------------------------
As stated in Sec. 63.11235, you must comply with the applicable
General Provisions according to the following:
Table 6 to Subpart JJJJJJ of Part 63--Applicability of General
Provisions to Subpart JJJJJJ
------------------------------------------------------------------------
Applies to subpart
Citation Subject JJJJJJ
------------------------------------------------------------------------
Sec. 63.1..................... Applicability..... Yes.
Sec. 63.2..................... Definitions....... Yes.
Sec. 63.3..................... Units and Yes.
Abbreviations.
Sec. 63.4..................... Prohibited Yes.
Activities and
Circumvention.
Sec. 63.5..................... Preconstruction No.
Review and
Notification
Requirements.
Sec. 63.6(a), (b)(1)-(b)(5), Compliance with Yes.
(b)(7), (c), (f)(2)-(3), (g), Standards and
(i), (j). Maintenance
Requirements.
Sec. 63.6(e)(1), (e)(3), Startup, shutdown, No. Standards
(f)(1), and (h). and malfunction apply at all
requirements and times, including
Opacity/Visible during startup,
Emission Limits. shutdown, and
malfunction
events.
Sec. 63.7(a), (b), (c), (d), Performance Yes.
(e)(2)-(e)(9), (f), (g), and Testing
(h). Requirements.
Sec. 63.7(e)(1)............... Conditions for No. Subpart DDDDD
conducting specifies
performance tests. conditions for
conducting
performance tests
at Sec.
63.11210.
Sec. 63.8..................... Monitoring Yes.
Requirements.
[[Page 31935]]
Sec. 63.9..................... Notification Yes. Subpart
Requirements. JJJJJJ requires
submission of
Notification of
Compliance Status
within 120 days
of compliance
date unless a
performance test
is required.
Sec. 63.10(a), (b)(1), Recordkeeping and Yes.
(b)(2)(i)-(iii), (b)(2)(vi)- Reporting
(xiv), (c)(1)-(c)(14), (d)(1)- Requirements.
(2), and (f).
Sec. 63.10(b)(2)(iv)-(v), .................. No, Subpart JJJJJJ
(b)(3), (d)(3)-(5), and (e). requires
submission on an
annual basis.
Sec. 63.10(c)(15)............. Allows use of SSM No.
plan.
Sec. 63.11.................... Control Device No.
Requirements.
Sec. 63.12.................... State Authority Yes.
and 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. 2010-10832 Filed 6-3-10; 8:45 am]
BILLING CODE 6560-50-P