[Federal Register: June 4, 2010 (Volume 75, Number 107)]
[Proposed Rules]
[Page 31895-31935]
[DOCID:fr04jn10-25]

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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

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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_ADDRESS>Attention Docket ID No. EPA-HQ-OAR-2006-
0790.
     Fax: Fax your comments to:<PHONE_NUMBER>, 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<PHONE_NUMBER> 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<PHONE_NUMBER>, and the telephone number for the
Air Docket is<PHONE_NUMBER>.

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<PHONE_NUMBER>; e-mail address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

    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:

------------------------------------------------------------------------
                                                   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.

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)

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

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.

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

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.

    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.

    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,

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/

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

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

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

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.

    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

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

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.

    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