Document ID: EPA-HQ-OAR-2006-0790-0001
Agency: epa
Document Type: Proposed Rule
Title: National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers
Posted Date: 2010-06-04T04:00Z

[Federal Register: June 4, 2010 (Volume 75, Number 107)]
[Proposed Rules]               
[Page 31895-31935]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr04jn10-25]                         

[[Page 31895]]

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Part III

Environmental Protection Agency

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40 CFR Part 63

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National Emission Standards for Hazardous Air Pollutants for Area 
Sources: Industrial, Commercial, and Institutional Boilers; Proposed 
Rule

[[Page 31896]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL-9148-3]
RIN 2060-AM44

 
National Emission Standards for Hazardous Air Pollutants for Area 
Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing national emission standards for control of 
hazardous air pollutants from two area source categories: Industrial 
boilers and commercial and institutional boilers. The proposed emission 
standards for control of mercury emissions from coal-fired area source 
boilers and the proposed emission standards for control of polycyclic 
organic matter emissions from all area source boilers are based on the 
maximum achievable control technology. The proposed emission standards 
for control of mercury emissions from biomass-fired and oil-fired area 
source boilers and for other hazardous air pollutants are based on 
EPA's proposed determination as to what constitutes the generally 
available control technology or management practices.
    EPA is also clarifying that gas-fired area source boilers are not 
needed to meet the 90 percent requirement of section 112(c)(3) of the 
Clean Air Act.
    Finally, we are also proposing that existing area source facilities 
with an affected boiler with a designed heat input capacity of 10 
million Btu per hour or greater undergo an energy assessment on the 
boiler system to identify cost-effective energy conservation measures.

DATES: Comments must be received on or before July 19, 2010. Under the 
Paperwork Reduction Act, comments on the information collection 
provisions are best assured of having full effect if the Office of 
Management and Budget (OMB) receives a copy of your comments on or 
before July 6, 2010.
    Public Hearing. We will hold a public hearing concerning this 
proposed rule and the interrelated proposed Boiler major source, CISWI, 
and RCRA rules, discussed in this proposal and published in the 
proposed rules section of today's Federal Register, on June 21, 2010. 
Persons requesting to speak at a public hearing must contact EPA by 
June 14, 2010.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2006-0790, by one of the following methods:
     http://www.regulations.gov. Follow the instructions for 
submitting comments.
     http://www.epa.gov/oar/docket.html. Follow the 
instructions for submitting comments on the EPA Air and Radiation 
Docket Web site.
     E-mail: Comments may be sent by electronic mail (e-mail) 
to a-and-r-docket@epa.gov, Attention Docket ID No. EPA-HQ-OAR-2006-
0790.
     Fax: Fax your comments to: (202) 566-9744, Docket ID No. 
EPA-HQ-OAR-2006-0790.
     Mail: Send your comments to: EPA Docket Center (EPA/DC), 
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2006-0790. 
Please include a total of two copies. In addition, please mail a copy 
of your comments on the information collection provisions to the Office 
of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 
725 17th St., NW., Washington, DC 20503.
     Hand Delivery or Courier: Deliver your comments to: EPA 
Docket Center (EPA/DC), EPA West, Room 3334, 1301 Constitution Ave., 
NW., Washington, DC 20460. Attention Docket ID No. EPA-HQ-OAR-2006-
0790. Such deliveries are only accepted during the Docket's normal 
hours of operation (8:30 a.m. to 4:30 p.m., Monday through Friday, 
excluding legal holiday), and special arrangements should be made for 
deliveries of boxed information.
    Instructions: All submissions must include agency name and docket 
number or Regulatory Information Number (RIN) for this rulemaking. All 
comments will be posted without change and may be made available online 
at http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
confidential business information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://
www.regulations.gov or e-mail. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through http://www.regulations.gov, your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses.
    Public Hearing: We will hold a public hearing concerning this 
proposed rule on June 21, 2010. Persons interested in presenting oral 
testimony at the hearing should contact Ms. Pamela Garrett, Energy 
Strategies Group, at (919) 541-7966 by June 14, 2010. The public 
hearing will be held in the Washington, DC area at a location and time 
that will be posted at the following Web site: http://www.epa.gov/
airquality/combustion. Please refer to this Web site to confirm the 
date of the public hearing as well. If no one requests to speak at the 
public hearing by June 14, 2010 then the public hearing will be 
cancelled and a notification of cancellation posted on the following 
Web site: http://www.epa.gov/airquality/combustion.
    Docket: All documents in the docket are listed in the http://
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy 
form. Publicly available docket materials are available either 
electronically in http://www.regulations.gov or in hard copy at the EPA 
Docket Center, Room 3334, 1301 Constitution Ave., NW., Washington, DC. 
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy Strategies 
Group, Sector Policies and Programs Division, (D243-01), Office of Air 
Quality Planning and Standards, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711; telephone number: (919) 
541-5025; Fax number (919) 541-5450; e-mail address: 
johnson.mary@epa.gov.

SUPPLEMENTARY INFORMATION: 

[[Page 31897]]

    Outline. The information in this preamble is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. What should I consider as I prepare my comments to EPA?
    C. Where can I get a copy of this document?
    D. When would a public hearing occur?
II. Background Information
    A. What is the statutory authority and regulatory approach for 
this proposed rule?
    B. What source categories are affected by the proposed 
standards?
    C. What is the relationship between this proposed rule and other 
related national emission standards?
    D. How did we gather information for this proposed rule?
    E. How are the area source boiler HAP addressed by this proposed 
rule?
III. Clarification of the Source Category List
IV. Summary of This Proposed Rule
    A. Do the proposed standards apply to my source?
    B. What is the affected source?
    C. When must I comply with the proposed standards?
    D. What are the proposed MACT and GACT standards?
    E. What are the Startup, Shutdown, and Malfunction (SSM) 
requirements?
    F. What are the proposed initial compliance requirements?
    G. What are the proposed continuous compliance requirements?
    H. What are the proposed notification, recordkeeping and 
reporting requirements?
    I. Submission of Emissions Test Results to EPA
V. Rationale of This Proposed Rule
    A. How did EPA determine which pollution sources would be 
regulated under this proposed rule?
    B. How did EPA determine the subcategories for this proposed 
rule?
    C. What surrogates are we using?
    D. How did EPA determine the proposed standards for existing 
units?
    1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
    2. GACT Determination for Existing Area Source Boilers
    E. How did EPA determine the proposed standards for new units?
    1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
    2. GACT Determination for New Area Source Boilers
    F. How did we select the compliance requirements?
    G. Alternative MACT Standards for Consideration
    H. How did we decide to exempt these area source categories from 
title V permitting requirements?
VI. Summary of the Impacts of This Proposed Rule
    A. What are the air impacts?
    B. What are the cost impacts?
    C. What are the economic impacts?
    D. What are the social costs and benefits of this proposed rule?
    E. What are the water and solid waste impacts?
    F. What are the energy impacts?
VII. Relationship of This Proposed Action to CAA Section 112(c)(6)
VIII. Statutory and Executive Order Review
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act of 1995
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. General Information

A. Does this action apply to me?

    The regulated categories and entities potentially affected by the 
proposed standards include:

------------------------------------------------------------------------
                                                   Examples of regulated
           Category              NAICS Code \1\          entities
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
action. To determine whether your facility, company, business, 
organization, etc., would be regulated by this action, you should 
examine the applicability criteria in 40 CFR 63.11193 of subpart JJJJJJ 
(National Emission Standards for Hazardous Air Pollutants for 
Industrial, Commercial, and Institutional Boilers Area Sources). If you 
have any questions regarding the applicability of this action to a 
particular entity, consult either the delegated regulatory authority 
for the entity or your EPA regional representative as listed in 40 CFR 
63.13 of subpart A (General Provisions).

B. What should I consider as I prepare my comments to EPA?

    Do not submit information containing CBI to EPA through http://
www.regulations.gov or e-mail. Send or deliver information identified 
as CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S. Environmental Protection Agency, Research Triangle 
Park, North Carolina 27711, Attention: Docket ID EPA-HQ-OAR-2006-0790. 
Clearly mark the part or all of the information that you claim to be 
CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark 
the outside of the disk or CD-ROM as CBI and then identify 
electronically within the disk or CD-ROM the specific information that 
is claimed as CBI. In addition to one complete version of the comment 
that includes information claimed as CBI, a copy of the comment that 
does not contain the information claimed as CBI must be submitted for 
inclusion in the public docket. Information so marked will not be 
disclosed except in accordance with procedures set forth in 40 CFR part 
2.

[[Page 31898]]

C. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this proposed action will also be available on the Worldwide Web (WWW) 
through the Technology Transfer Network (TTN). Following signature, a 
copy of the proposed action will be posted on the TTN's policy and 
guidance page for newly proposed or promulgated rules at the following 
address: http://www.epa.gov/ttn/oarpg/. The TTN provides information 
and technology exchange in various areas of air pollution control.

D. When would a public hearing occur?

    We will hold a public hearing concerning this proposed rule on June 
21, 2010. Persons interested in presenting oral testimony at the 
hearing should contact Ms. Pamela Garrett, Energy Strategies Group, at 
(919) 541-7966 by June 14, 2010. The public hearing will be held in the 
Washington, DC area at a location and time that will be posted at the 
following Web site: http://www.epa.gov/airquality/combustion. Please 
refer to this Web site to confirm the date of the public hearing as 
well. If no one requests to speak at the public hearing by June 14, 
2010 then the public hearing will be cancelled and a notification of 
cancellation posted on the following Web site: http://www.epa.gov/
airquality/combustion.

II. Background Information

A. What is the statutory authority and regulatory approach for this 
proposed rule?

    Section 112(d) of the Clean Air Act (CAA) requires us to establish 
NESHAP for both major and area sources of hazardous air pollutants 
(HAP) that are listed for regulation under CAA section 112(c). A major 
source emits or has the potential to emit 10 tons per year (tpy) or 
more of any single HAP or 25 tpy or more of any combination of HAP. An 
area source is a HAP-emitting stationary source that is not a major 
source.
    CAA section 112(k)(3)(B) calls for EPA to identify at least 30 HAP 
which, as the result of emissions from area sources, pose the greatest 
threat to public health in the largest number of urban areas. EPA 
implemented this provision in 1999 in the Integrated Urban Air Toxics 
Strategy (Strategy), (64 FR 38715, July 19, 1999). Specifically, in the 
Strategy, EPA identified 30 HAP that pose the greatest potential health 
threat in urban areas, and these HAP are referred to as the ``30 urban 
HAP.'' CAA section 112(c)(3) requires EPA to list sufficient categories 
or subcategories of area sources to ensure that area sources 
representing 90 percent of the emissions of the 30 urban HAP are 
subject to regulation. A primary goal of the Strategy is to achieve a 
75 percent reduction in cancer incidence attributable to HAP emitted 
from stationary sources.
    Under CAA section 112(d)(5), we may elect to promulgate standards 
or requirements for area sources ``which provide for the use of 
generally available control technologies or management practices 
(`GACT') by such sources to reduce emissions of hazardous air 
pollutants.'' Additional information on GACT is found in the Senate 
report on the legislation (Senate Report Number 101-228, December 20, 
1989), which describes GACT as:

    * * * methods, practices and techniques which are commercially 
available and appropriate for application by the sources in the 
category considering economic impacts and the technical capabilities 
of the firms to operate and maintain the emissions control systems.

    Consistent with the legislative history, we can consider costs and 
economic impacts in determining GACT, which is particularly important 
when developing regulations for source categories that may have many 
small businesses such as these.
    Determining what constitutes GACT involves considering the control 
technologies and management practices that are generally available to 
the area sources in the source category. We also consider the standards 
applicable to major sources in the analogous source category to 
determine if the control technologies and management practices are 
transferable and generally available to area sources. In appropriate 
circumstances, we may also consider technologies and practices at area 
and major sources in similar categories to determine whether such 
technologies and practices could be considered generally available for 
the area source categories at issue. Finally, as noted above, in 
determining GACT for a particular area source category, we consider the 
costs and economic impacts of available control technologies and 
management practices on that category.
    While GACT may be a basis for standards for most types of HAP 
emitted from area sources, CAA section 112(c)(6) requires that EPA list 
categories and subcategories of sources assuring that sources 
accounting for not less than 90 percent of the aggregate emissions of 
each of the seven specified hazardous air pollutants (HAP) are subject 
to standards under section 112(d)(2) or (d)(4). The seven HAP specified 
in section 112(c)(6) are as follows: alkylated lead compounds, 
polycyclic organic matter, hexachlorobenzene, mercury, polychlorinated 
biphenyls, 2,3,7,9-tetrachlorodibenzofurans, and 2,3,7,8-
tetrachloridibenzo-p-dioxin.
    The CAA section 112(c)(6) list of source categories currently 
includes industrial coal combustion, industrial oil combustion, 
industrial wood combustion, commercial coal combustion, commercial oil 
combustion, and commercial wood combustion. See 63 FR 17849. We listed 
these source categories under CAA section 112(c)(6) based on the source 
categories' contribution of mercury and polycyclic organic matter 
(POM). In the documentation for the CAA section 112(c)(6) listing, the 
commercial fuel combustion categories included institutional fuel 
combustion (see ``1990 Emissions Inventory of Section 112(c)(6) 
Pollutants, Final Report,'' April 1998). As discussed in greater detail 
below, we re-examine the emission inventory and the need to address 
categories under CAA section 112(c)(6) during the rule development 
process. Based on this re-examination, we now believe we will only need 
to address the coal-fueled portion of these categories under CAA 
section 112(c)(6).
    With this proposed rule and the major source boilers rule, we 
currently believe that we have subjected to regulation or proposed to 
regulate at least 90 percent of the 1990 section 112(c)(6) emissions 
inventory for mercury. Coal-fired area source boilers represent 
approximately 4.3 percent of the 1990 section 112(c)(6) emissions 
inventory for mercury. In contrast, biomass- and oil-fired boilers 
represent approximately 0.34 percent. Consequently, we are proposing to 
regulate coal-fired boilers under MACT because we need these sources to 
meet the 90 percent requirement for mercury in section 112(c)(6). We 
are proposing to regulate biomass-fired and oil-fired types of boilers 
under GACT to meet the 90 percent requirement for mercury in section 
112(c)(3).
    We solicit comment on whether we should nevertheless establish 
MACT-based mercury emission standards for all boilers in this category. 
In your comments, please explain the basis for your position and 
provide any supporting documentation.
    The ``maximum achievable control technology'' or ``MACT'' 
regulation required by CAA section 112(d)(2) or (4) can be based on the 
emissions reductions achievable through application of measures, 
processes, methods, systems, or techniques including, but not limited 
to: (1)

[[Page 31899]]

Reducing the volume of, or eliminating emissions of, such pollutants 
through process changes, substitutions of materials, or other 
modifications; (2) enclosing systems or processes to eliminate 
emissions; (3) collecting, capturing, or treating such pollutants when 
released from a process, stack, storage or fugitive emission point; (4) 
design, equipment, work practices, or operational standards as provided 
in CAA section 112(h); or (5) a combination of the above.
    The MACT floor is the minimum control level allowed for NESHAP and 
is defined under CAA section 112(d)(3). For new sources, MACT based 
standards cannot be less stringent than the emission control achieved 
in practice by the best-controlled similar source, as determined by the 
Administrator. The MACT based standards for existing sources can be 
less stringent than standards for new sources, but they cannot be less 
stringent than the average emission limitation achieved by the best 
performing 12 percent of existing sources in the category or 
subcategory (for which the Administrator has emission information) for 
source categories and subcategories with 30 or more sources, or the 
best performing 5 sources for categories and subcategories with fewer 
than 30 sources (CAA section 112(d)(3)(A) and (B)).
    Although emission standards are often structured in terms of 
numerical emissions limits, alternative approaches are sometimes 
necessary and authorized pursuant to CAA section 112. For example, in 
some cases, physically measuring emissions from a source may be not 
practicable due to technological and economic limitations. CAA section 
112(h) authorizes the Administrator to promulgate a design, equipment, 
work practice, or operational standard, or combination thereof, 
consistent with the provisions of CAA sections 112(d) or (f), in those 
cases where, in the judgment of the Administrator, it is not feasible 
to prescribe or enforce an emission standard. CAA section 112(h)(2) 
provides that the phrase ``not feasible to prescribe or enforce an 
emission standard'' includes the situation in which the Administrator 
determines that * * * the application of measurement methodology to a 
particular class of sources is not practicable due to technological and 
economic limitations.
    As noted above, we listed industrial coal combustion, industrial 
oil combustion, industrial wood combustion, commercial coal combustion, 
commercial oil combustion, and commercial wood combustion under CAA 
section 112(c)(6) based on the source categories' contribution of 
mercury and polycyclic organic matter (POM). We listed these same 
categories under section 112(c)(3) for their contribution of mercury, 
arsenic, beryllium, cadmium, lead, chromium, manganese, nickel, 
polycyclic organic matter (POM) (as 7-PAH (polynuclear aromatic 
hydrocarbons)), ethylene dioxide, and polychlorinated biphenyls (PCB).
    We have developed proposed standards to reflect the application of 
MACT for mercury from coal-fired area source boilers and POM from all 
area source boilers under section 112(c)(6) and have applied GACT for 
the other pollutants noted above.

B. What source categories are affected by the proposed standards?

    The source categories affected by the proposed standards are 
industrial boilers and commercial and institutional boilers. Both 
source categories were included in the area source list published on 
July 19, 1999 (64 FR 38721). The inclusion of these two source 
categories on the CAA section 112(c)(3) area source category list is 
based on 1990 emissions data, as EPA used 1990 as the baseline year for 
that listing. We describe above the pollutants that formed the basis of 
the listings.
    This proposed rule would apply to all existing and new industrial 
boilers, institutional boilers, and commercial boilers located at area 
sources. The industrial boiler source category includes boilers used in 
manufacturing, processing, mining, refining, or any other industry. The 
commercial boiler source category includes boilers used in commercial 
establishments such as stores/malls, laundries, apartments, 
restaurants, and hotels/motels. The institutional boiler source 
category includes boilers used in medical centers (e.g., hospitals, 
clinics, nursing homes), educational and religious facilities (e.g., 
schools, universities, churches), and municipal buildings (e.g., 
courthouses, prisons).
    Boiler means an enclosed combustion device having the primary 
purpose of recovering thermal energy in the form of steam or hot water.

C. What is the relationship between this proposed rule and other 
related national emission standards?

    This proposed rule regulates industrial boilers and institutional/
commercial boilers that are area sources of HAP. Today, in a parallel 
action, a NESHAP for industrial, commercial, and institutional boilers 
located at major sources is being proposed reflecting application of 
MACT. The major source NESHAP regulates emissions of particulate matter 
(PM) (as a surrogate for non-mercury metals), mercury, hydrogen 
chloride (HCl)(as a surrogate for acid gases), dioxins/furans, and 
carbon monoxide (CO) (as a surrogate for non-dioxin organic HAP) from 
existing and new major source boilers.
    This proposed rule covers boilers located at area source 
facilities. In addition to the major source MACT for boilers being 
issued today and this rule, the Agency is also issuing emission 
standards today pursuant to CAA section 129 for commercial and 
industrial solid waste incineration units. In a parallel action, EPA is 
proposing a solid waste definition rulemaking pursuant to Subtitle D of 
RCRA. That action is relevant to this proceeding because if an 
industrial, commercial, or institutional unit located at an area source 
combusts secondary materials that are ``solid waste,'' as that term is 
defined by the Administrator under RCRA, those units would be subject 
to section 129 of the CAA, not section 112.
    As background, in 2007, the United States Court of Appeals for the 
District of Columbia Circuit (DC Circuit) vacated the CISWI Definitions 
Rule, which EPA issued pursuant to CAA section 129. The court found 
that the definitions in that rule were inconsistent with the CAA. 
Specifically, the Court held that the term ``solid waste incineration 
unit'' in CAA Section 129(g)(1) ``unambiguously include[s] among the 
incineration units subject to its standards any facility that combusts 
any commercial or industrial solid waste material at all--subject to 
the four statutory exceptions identified [in CAA Section 129(g)(1)].'' 
NRDC v. EPA, 489 F.3d at 1257-58.
    Based on the information available to the Agency, we believe that 
the boilers that are subject to this area source rule combust coal, 
oil, and biomass. EPA does not believe that the boilers subject to this 
rule combust any non-hazardous secondary materials, whether they are 
considered a solid waste or not. If you are aware of such materials 
being combusted at these boilers, please provide specific information 
as to the type of secondary material being combusted and at what type 
of facilities and in what quantities. If the final form of the solid 
waste definition results in any secondary materials being considered 
solid waste it will be important to know whether units are burning 
those materials, because that would result in those units becoming 
incinerators subject to regulation under

[[Page 31900]]

section 129 and no longer being considered boilers.
    There is also another CAA regulation that is relevant in that they 
apply to some of the affected sources in this rule. For example, in 
1986, EPA codified new source performance standards (NSPS) for 
industrial, commercial, and institutional boilers (40 CFR part 60, 
subparts Db and Dc) and revised portions of them in 1999 and 2006. The 
NSPS regulates emissions of PM, sulfur dioxide (SO2), and 
nitrogen oxides from boilers constructed after June 19, 1984. Sources 
subject to the NSPS that are located at area source facilities are also 
subject to this proposed rule because this proposed rule regulates HAP. 
In developing this proposal, we have streamlined the monitoring and 
recordkeeping requirements to avoid duplicating requirements in the 
NSPS.

D. How did we gather information for this proposed rule?

    We gathered information for this proposed rule from States' boiler 
inspection lists, company Web sites, published literature, State 
permits, current State and Federal regulations, and from an Information 
Collection Request (ICR) conducted for the major source NESHAP.
    We developed an initial nationwide population of area source 
boilers based on boiler inspector databases from 13 States. The boiler 
inspector databases include steam boilers that are required to be 
inspected for safety or insurance purposes. We classified the area 
source boilers to NAICS codes based on the ``name'' of the facility at 
which the boiler was located. However, many of the boilers in the 
boiler inspector database could not be readily assigned to an NAICS 
code.
    We reviewed State and other Federal regulations that apply to the 
area sources in the source categories for information concerning 
existing HAP emission control approaches. For example, as noted above, 
the NSPS for small industrial, commercial, and institutional boilers in 
40 CFR part 60, subpart Dc apply to boilers at some area sources. 
Similarly, permit requirements established by the Ohio, Illinois, 
Vermont, New Hampshire, and Maine air regulatory agencies apply to some 
area sources. We also reviewed standards for boilers at major sources 
that would be appropriate for and transferable to boilers at area 
sources. For example, we determined that management practices, such as, 
annual tune-ups and operator training applicable to major source 
boilers are equally feasible for boilers at area sources.

E. How are the area source boiler HAP addressed by this proposed rule?

    As explained above, industrial coal combustion, industrial oil 
combustion, industrial wood combustion, commercial coal combustion, 
commercial oil combustion, and commercial wood combustion are listed 
under CAA section 112(c)(6) due to contributions of mercury and POM and 
these same categories are listed under CAA section 112(c)(3) for their 
contribution of mercury, arsenic, beryllium, cadmium, lead, chromium, 
manganese, nickel, POM, ethylene dioxide, and PCB.
    With respect to the 112(c)(3) pollutants, we used surrogates 
because, as explained below, it was not practical to establish 
individual standards for each specific HAP. We grouped the 112(c)(3) 
pollutants, which formed the basis for the listing of these two source 
categories, into three common groupings: mercury, non-mercury metallic 
HAP (arsenic, beryllium, cadmium, chromium, lead, manganese, and 
nickel), and organic HAP (POM, ethylene dichloride, and PCB). In 
general, the pollutants within each group have similar characteristics 
and can be controlled with the same techniques.
    For the non-mercury metallic HAP, we selected PM as a surrogate. 
The inherent variability and unpredictability of the non-mercury metal 
HAP compositions and amounts in fuel has a material effect on the 
composition and amount of non-mercury metal HAP in the emissions from 
the boiler. As a result, establishing individual numerical emissions 
limits for each non-mercury HAP metal species is difficult given the 
level of uncertainty about the individual non-mercury metal HAP 
compositions of the fuels that will be combusted. An emission 
characteristic common to all boilers is that the non-mercury metal HAP 
are a component of the PM contained in the fly ash emitted from the 
boiler. A sufficient correlation exists between PM and non-mercury 
metallic HAP to rely on PM as a surrogate for these HAP and for their 
control. Therefore, the same control techniques that would be used to 
control the fly-ash PM will control non-mercury metallic HAP. Emissions 
limits established to achieve control of PM will also achieve control 
of non-mercury metal HAP. Furthermore, establishing separate standards 
for each individual HAP would impose costly and significantly more 
complex compliance and monitoring requirements and achieve little, if 
any, HAP emissions reductions beyond what would be achieved using the 
surrogate pollutant approach.
    For organic HAP, we selected CO as a surrogate for organic 
compounds, including POM, emitted from the various fuels burned in 
boilers. The presence of CO is an indicator of incomplete combustion. A 
high level of CO in emissions is an indicator of incomplete combustion 
and, thus, a potential indication of elevated organic HAP emissions. 
Monitoring equipment for CO is readily available, which is not the case 
for organic HAP. Also, it is significantly easier and less expensive to 
measure and monitor CO emissions than to measure and monitor emissions 
of each individual organic HAP. We considered other surrogates, such as 
total hydrocarbon (THC), but lacked data on emissions and permit limits 
for area source boilers. Therefore, using CO as a surrogate for organic 
urban HAP is a reasonable approach because minimizing CO emissions will 
result in minimizing organic urban HAP emissions.
    Based on these considerations, we are proposing GACT standards for 
PM (as a surrogate for the individual urban metal HAP), CO (as a 
surrogate pollutant for the individual urban organic HAP), and mercury 
from biomass-fired and oil-fired boilers. We are proposing MACT 
standards for mercury from coal-fired boilers and for POM from all 
boilers.

III. Clarification of the Source Category List

    The Industrial Boilers and the Institutional/Commercial Boilers 
area source categories were listed under section 112(c)(3) of the CAA. 
EPA needs to establish emission standards for area source boilers for 
the following urban HAP in order to meet the section 112(c)(3) 90 
percent requirement for these HAP: mercury, arsenic, beryllium, 
cadmium, lead, chromium, manganese, nickel, POM (as 7-PAH), ethylene 
dioxide, and PCB. Natural gas-fired area source boilers do not emit any 
of the urban HAP identified above. Therefore, regulation of gas-fired 
area source boilers is not necessary to meet the 90 percent requirement 
under section 112(c)(3) for these HAP. For the reason stated above, 
pursuant to section 112(c)(3) of the CAA, we are proposing emission 
standards for the above mentioned HAP for area source boilers fired by 
coal, oil, and wood, but not standards for boilers fired by natural 
gas.

[[Page 31901]]

IV. Summary of This Proposed Rule

A. Do the proposed standards apply to my source?

    This proposed rule applies to you if you own or operate a boiler 
combusting coal, biomass, or oil located at an area source. The 
standards do not apply to boilers that are subject to another standard 
under 40 CFR part 63 or to a standard developed under CAA section 129.
    This proposed rule applies to you if you own or operate a boiler 
combusting natural gas, located at an area source, which switches to 
combusting coal, biomass, or oil after the date of proposal.

B. What is the affected source?

    The affected source is the collection of all existing boilers 
within a subcategory located at an area source facility or each new 
boiler located at an area source facility.

C. When must I comply with the proposed standards?

    The owner or operator of an existing source would be required to 
comply with the rule no later than 3 years after the date of 
publication of the final rule in the Federal Register. The owner or 
operator of a new source would be required to comply upon the date of 
publication of the final rule in the Federal Register or startup of the 
facility, whichever is later.

D. What are the proposed MACT and GACT standards?

    Emission standards expressed in the form of emission limits are 
being proposed for new and existing area source boilers. The proposed 
MACT emission limits for mercury and CO (as a surrogate for POM) are 
presented, along with the proposed GACT standards for PM (as a 
surrogate for urban metals), in Table 1 of this preamble.

                                Table 1--Emission Limits for Area Source Boilers
                              [Pounds per million British thermal units heat input]
----------------------------------------------------------------------------------------------------------------
                                                          Particulate                          Carbon monoxide
             Source                   Subcategory         matter  (PM)         Mercury            (CO) (ppm)
----------------------------------------------------------------------------------------------------------------
New Boiler......................  Coal...............               0.03            3.0E-06  310 (@ 7% oxygen).
                                  Biomass............               0.03  .................  100 (@ 7% oxygen).
                                  Oil................               0.03  .................  1 (@ 3% oxygen).
Existing Boiler.................  Coal...............  .................            3.0E-06  310 (@ 7% oxygen).
                                  Biomass............  .................  .................  160 (@ 7% oxygen).
                                  Oil................  .................  .................  2 (@ 3% oxygen).
----------------------------------------------------------------------------------------------------------------

    The emission limits for existing area source boilers are only 
applicable to area source boilers that have a designed heat input 
capacity of 10 million British thermal units per hour (MMBtu/h) or 
greater. If your boiler burns at least 10 percent coal on a total fuel 
annual heat input basis, the boiler is in the coal fuel subcategory. If 
your boiler burns biomass or biomass in combination with a liquid or 
gaseous fuel, the unit is in the biomass subcategory. If your boiler 
burns oil, or oil in combination with a gaseous fuel, the unit is in 
the oil subcategory, except if the unit burns oil only during periods 
of gas curtailment.
    As allowed under CAA section 112(h), a work practice standard is 
being proposed for existing area source boilers that are units with 
designed heat input capacity of less than 10 MMBtu/h. The work practice 
standard for existing small area source boilers requires the 
implementation of a tune-up program.
    An additional standard is being proposed for existing area source 
facilities having an affected boiler with a designed heat input 
capacity of 10 MMBtu/h or greater that requires the performance of an 
energy assessment, by qualified personnel, on the boiler and the 
facility to identify cost-effective energy conservation measures.

E. What are the Startup, Shutdown, and Malfunction (SSM) requirements?

    The United States Court of Appeals for the District of Columbia 
Circuit vacated portions of two provisions in EPA's CAA section 112 
regulations governing the emissions of HAP during periods of startup, 
shutdown, and malfunction (SSM). Sierra Club v. EPA, 551 F.3d 1019 
(D.C. Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010). 
Specifically, the Court vacated the SSM exemption contained in 40 CFR 
63.6(f)(1) and 40 CFR 63.6(h)(1), that are part of a regulation, 
commonly referred to as the ``General Provisions Rule,'' that EPA 
promulgated under section 112 of the CAA. When incorporated into CAA 
Section 112(d) regulations for specific source categories, these two 
provisions exempt sources from the requirement to comply with the 
otherwise applicable CAA section 112(d) emission standard during 
periods of SSM.
    Consistent with Sierra Club v. EPA, EPA has established standards 
in this rule that apply at all times. EPA has attempted to ensure that 
we have not incorporated into proposed regulatory language any 
provisions that are inappropriate, unnecessary, or redundant in the 
absence of an SSM exemption. We are specifically seeking comment on 
whether there are any such provisions that we have inadvertently 
incorporated or overlooked. We also request comment on whether there 
are additional provisions that should be added to regulatory text in 
light of the absence of an SSM exemption and provisions related to the 
SSM exemption (such as the SSM plan requirement and SSM recordkeeping 
and reporting provisions).
    In establishing the standards in this rule, EPA has taken into 
account startup and shutdown periods and, for the reasons explained 
below, has not established different standards for those periods. The 
standards that we are proposing are daily or monthly averages. Based 
upon continuous emission monitoring data, obtained as part of the 
information collection effort for the major source boiler and process 
heater rulemaking, which included periods of startup and shutdown, over 
long averaging periods, startups and shutdowns will not affect the 
achievability of the standard. Boilers, especially solid fuel-fired 
boilers, do not normally startup and shutdown more than once per day. 
Thus, we are not establishing a separate emission standard for these 
periods because startup and shutdown are part of their routine 
operations and, therefore, are already addressed by the standards.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is

[[Page 31902]]

defined as a ``sudden, infrequent, and not reasonably preventable 
failure of air pollution control and monitoring equipment, process 
equipment or a process to operate in a normal or usual manner * * *'' 
(40 CFR 63.2). EPA has determined that malfunctions should not be 
viewed as a distinct operating mode and, therefore, any emissions that 
occur at such times do not need to be factored into development of CAA 
section 112(d) standards, which, once promulgated, apply at all times. 
It is reasonable to interpret section 112(d) as not requiring EPA to 
account for malfunctions in setting emissions standards. For example, 
we note that CAA section 112 uses the concept of ``best performing'' 
sources in defining MACT, the level of stringency that major source 
standards must meet. Applying the concept of ``best performing'' to a 
source that is malfunctioning presents significant difficulties. The 
goal of best performing sources is to operate in such a way as to avoid 
malfunctions of their units. Similarly, although standards for area 
sources are generally not required to be set based on ``best 
performers,'' we believe that what is ``generally available'' should 
not be based on periods in which there is a ``failure to operate.''
    Moreover, even if malfunctions were considered a distinct operating 
mode, we believe it would be impracticable to take malfunctions into 
account in setting CAA section 112(d) standards for area source 
boilers. As noted above, by definition, malfunctions are sudden and 
unexpected events and it would be difficult to set a standard that 
takes into account the myriad different types of malfunctions that can 
occur across all sources in the category. Moreover, malfunctions can 
vary in frequency, degree, and duration, further complicating standard 
setting.
    In the event that a source fails to comply with the applicable CAA 
section 112(d) standards as a result of a malfunction event, EPA would 
determine an appropriate response based on, among other things, the 
good faith efforts of the source to minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses to ascertain and rectify excess emissions. 
EPA would also consider whether the source's failure to comply with the 
CAA section 112(d) standard was, in fact, ``sudden, infrequent, not 
reasonably preventable'' and was not instead ``caused in part by poor 
maintenance or careless operation.'' 40 CFR 63.2 (definition of 
malfunction).

F. What are the proposed initial compliance requirements?

    For new and existing area source boilers with applicable emission 
limits, we are proposing that you must conduct initial stack tests or 
fuel analysis (for mercury) to determine compliance with the PM, 
mercury, and CO emission limits.
    As part of the initial compliance demonstration, we are proposing 
that you must monitor specified operating parameters during the initial 
performance tests that demonstrate compliance with the PM and mercury 
emission limits for area source boilers with wet or dry scrubbers. The 
test average establishes your site-specific operating levels.
    For owners or operators of existing area source boilers having a 
heat input capacity of less than 10 MMBtu/h, we are proposing that you 
must submit to the delegated authority or EPA, as appropriate, 
documentation that a tune-up was conducted.
    For owners or operators of existing area source facilities having a 
boiler with a heat input capacity of 10 MMBtu/h or greater and subject 
to this rule, we are proposing that you submit to the delegated 
authority or EPA, as appropriate, documentation that the energy 
assessment was performed and the cost-effective energy conservation 
measures identified.

G. What are the proposed continuous compliance requirements?

    If you demonstrate initial compliance with the emission limits by 
performance (stack) tests, we are proposing that you conduct stack 
tests on an annual basis. Furthermore, to demonstrate continuous 
compliance with the PM and mercury emission limits, we are proposing 
that you must monitor and comply with the applicable site-specific 
operating limits.
    For area source boilers without wet scrubbers that must comply with 
the PM and mercury emission limits, we are proposing that you must 
continuously monitor opacity and maintain the opacity at or below ten 
percent (daily block average). Or, if the unit is controlled with a 
fabric filter, instead of continuously monitoring opacity, we are 
proposing that the fabric filter may be continuously operated such that 
the bag leak detection system alarm does not sound more than 5 percent 
of the operating time during any 6-month period.
    For boilers with wet scrubbers that must comply with the PM and 
mercury emission limits, we are proposing that you must monitor 
pressure drop and liquid flow rate of the scrubber and maintain the 
daily block averages at or above the minimum operating limits 
established during the performance test.
    If you elected to demonstrate initial compliance with the mercury 
emission limit by fuel analysis, we are proposing that you conduct a 
monthly fuel analysis and maintain the annual average at or below the 
limit indicated in Table 1 of this preamble.
    For boilers that demonstrate compliance with the PM and mercury 
emission limits by performance (stack) tests, we propose that you must 
maintain monthly fuel records that demonstrate that you burned no new 
fuel type or new mixture (monthly average) as set during the 
performance test. If you plan to burn a new fuel type or new mixture 
than what was burned during the initial performance test, then we are 
proposing that you must conduct a new performance test to demonstrate 
continuous compliance with the PM emission limit and mercury emission 
limit.
    For boilers with heat input capacities equal to or greater than 100 
MMBtu/hr, we propose that you must continuously monitor CO and maintain 
the daily average CO emissions at or below the limits indicated in 
Table 1 to demonstrate compliance with the CO emission limits at all 
times.

H. What are the proposed notification, recordkeeping and reporting 
requirements?

    All new and existing sources would be required to comply with some 
requirements of the General Provisions (40 CFR part 63, subpart A), 
which are identified in Table 6 of this proposed rule. The General 
Provisions include specific requirements for notifications, 
recordkeeping, and reporting. If performance tests are required under 
this proposed rule, then the notification and reporting requirements 
for performance tests in the General Provisions would also apply.
    Each owner or operator would be required to submit a notification 
of compliance status report, as required by 40 CFR 63.9(h) of the 
General Provisions. This proposed rule requires the owner or operator 
to include in the notification of compliance status report 
certifications of compliance with rule requirements.
    Semiannual compliance reports, as required by 40 CFR 63.10(e)(3) of 
subpart A, would be required only for semiannual reporting periods when 
a deviation from any of the requirements in the rule occurred, or any 
process changes occurred and compliance certifications were 
reevaluated.

[[Page 31903]]

    This proposed rule would require records to demonstrate compliance 
with each emission limit, work practice standard, or management 
practice. These recordkeeping requirements are specified directly in 
the General Provisions to 40 CFR part 63.
    Records for applicable management practices must be maintained. 
Specifically, the owner or operator must keep records of the dates and 
the results of each boiler tune-up.
    Records of either continuously monitored parameter data for a 
control device if a device is used to control the emissions or 
continuous emission monitoring system (CEMS) data would be required.
    Each owner and operator would be required to keep the following 
records:
    (1) All reports and notifications submitted to comply with the 
rule;
    (2) Continuous monitoring data as required in the rule;
    (3) Each instance in which you did not meet each emission limit, 
work/management practice, and operating limit (i.e., deviations from 
the rule);
    (4) Monthly fuel use by each boiler including a description of the 
type(s) of fuel(s) burned, amount of each fuel type burned, and units 
of measure;
    (5) A copy of the results of all performance tests, energy 
assessments, opacity observations, performance evaluations, or other 
compliance demonstrations conducted to demonstrate initial or 
continuous compliance with the rule; and
    (6) A copy of your site-specific monitoring plan developed for the 
rule, if applicable.
    Typically, records would be retained for at least 5 years. In 
addition, monitoring plans, operating and maintenance plans, and other 
plans would be updated as necessary and kept for as long as they are 
still current.

I. Submission of Emissions Test Results to EPA

    Compliance test data are necessary for many purposes including 
compliance determinations, development of emission factors, and 
determining annual emission rates. EPA has found it burdensome and time 
consuming to collect emission test data because of varied locations for 
data storage and varied data storage methods.
    One improvement that has occurred in recent years is the 
availability of stack test reports in electronic format as a 
replacement for bulky paper copies.
    In this action, we are taking a step to improve data accessibility 
for stack tests (and in the future continuous monitoring data). Boiler 
area sources would be required to submit to WebFIRE (an EPA electronic 
database) an electronic copy of stack test reports as well as process 
data. Data entry requires only access to the Internet and is expected 
to be completed by the stack testing company as part of the work that 
it is contracted to perform.
    Please note that the proposed requirement to submit source test 
data electronically to EPA would not require any additional performance 
testing. In addition, when a facility submits performance test data to 
WebFIRE, there would be no additional requirements for data 
compilation; instead, we believe industry would greatly benefit from 
improved emissions factors, fewer information requests, and better 
regulation development as discussed below. Because the information that 
would be reported is already required in the existing test methods and 
is necessary to evaluate the conformance to the test methods, 
facilities would already be collecting and compiling these data. One 
major advantage of submitting source test data through the Electronic 
Reporting Tool (ERT), which was developed with input from stack testing 
companies (who already collect and compile performance test data 
electronically), is that it would provide a standardized method to 
compile and store all the documentation required by this proposed rule. 
Another important benefit of submitting these data to EPA at the time 
the source test is conducted is that these data should reduce the 
effort involved in data collection activities in the future for these 
source categories. This results in a reduced burden on both affected 
facilities (in terms of reduced manpower to respond to data collection 
requests) and EPA (in terms of preparing and distributing data 
collection requests). Finally, another benefit of submitting these data 
to WebFIRE electronically is that these data will greatly improve the 
overall quality of the existing and new emissions factors by 
supplementing the pool of emissions test data upon which emissions 
factors are based and by ensuring that data are more representative of 
current industry operational procedures. A common complaint we hear 
from industry and regulators is that emissions factors are out-dated or 
not representative of a particular source category. Receiving recent 
performance test results would ensure that emissions factors are 
updated and more accurate. In summary, receiving these test data 
already collected for other purposes and using them in the emissions 
factors development program will save industry, State/local/tribal 
agencies, and EPA time and money.
    As mentioned earlier, the electronic data base that will be used is 
EPA's WebFIRE, which is a Web site accessible through EPA's TTN 
(technology transfer network). The WebFIRE Web site was constructed to 
store emissions test data for use in developing emission factors. A 
description of the WebFIRE data base can be found at http://
cfpub.epa.gov/oarweb/index.cfm?action=fire.main. The ERT will be able 
to transmit the electronic report through EPA's Central Data Exchange 
(CDX) network for storage in the WebFIRE data base. Although ERT is not 
the only electronic interface that can be used to submit source test 
data to the CDX for entry into WebFIRE, it makes submittal of data very 
straightforward and easy. A description of the ERT can be found at 
http://www.epa.gov/ttn/chief/ert/ert_tool.html.
    The ERT can be used to document the conducting of stack tests data 
for various pollutants including PM, mercury, dioxin/furan, and HCl. 
Presently, the ERT does not accept opacity data or CEMS data.
    EPA specifically requests comment on the utility of this electronic 
reporting requirement and the burden that owners and operators of 
boiler area source facilities estimate would be associated with this 
requirement.

V. Rationale of This Proposed Rule

A. How did EPA determine which pollution sources would be regulated 
under this proposed rule?

    This proposed rule regulates industrial boilers (fired by coal, 
biomass, or oil) and institutional and commercial boilers (fired by 
coal, biomass, or oil) that are located at area sources of HAP.
    Boilers that are used specifically for research and development are 
not regulated. However, boilers that only provide steam to a process or 
for heating at a research and development facility are still subject to 
this proposed rule.

B. How did EPA determine the subcategories for this proposed rule?

    The CAA allows EPA to divide source categories into subcategories 
when differences between given types of units lead to corresponding 
differences in the nature of emissions or the technical feasibility of 
applying emission control techniques. The design, operating, and 
emissions information that EPA reviewed during the major source 
rulemaking indicates the need to subcategorize boilers based on the 
boiler type.

[[Page 31904]]

    Boiler systems are designed for specific fuel types (e.g., coal, 
biomass, or oil) and will encounter problems if a fuel with 
characteristics other than those originally specified is fired. Most 
boilers can only achieve full load on the fuel or fuels for which they 
were specifically designed. Changes to the fuel type would often 
require extensive changes to the fuel handling and feeding system. 
Additionally, the burners and combustion chamber would need to be 
redesigned and modified to handle different fuel types and account for 
increases or decreases in the fuel volume and shape. In some cases, the 
changes may reduce the capacity and efficiency of the boiler. An 
additional effect of these changes would be extensive retrofit costs.
    Emissions from boilers burning coal, biomass, and oil will also 
differ. Boilers emit a number of urban HAP. In general, HAP formation 
is dependent upon the composition of the fuel. The combustion quality 
and temperature also play an important role. The fuel dependent urban 
HAP emissions from boilers are metals, including mercury. These fuel 
dependent HAP emissions generally can be controlled by either changing 
the fuel property before combustion or by removing the HAP from the 
flue gas after combustion. Organic HAP, on the other hand, are formed 
from incomplete combustion and are much less influenced by the 
characteristics of the fuel being burned. The degree of combustion may 
be greatly influenced by three general factors: time, turbulence, and 
temperature. These factors are a function of the design of the boiler 
which is dependent in part on the type of fuel being burned.
    Because these different types of boilers have different emission 
characteristics which may influence the feasibility and effectiveness 
of emission control, we are proposing to subcategorize them as follows: 
boilers designed to fire coal, boilers designed to fire biomass, and 
boilers designed to fire oil in order to account for these differences 
in emissions. The coal-fired subcategory includes boilers burning 
greater than 10 percent coal on an annual fuel heat input basis. The 
biomass fuel subcategory includes units burning any biomass but not 
more than 10 percent coal on an annual fuel heat input basis. The oil 
subcategory includes all remaining boilers.
    In summary, we have identified three subcategories of boilers 
located at area sources: (1) Boilers designed for coal firing, (2) 
boilers designed for biomass firing, and (3) boilers designed for oil 
firing.

C. What surrogates are we using?

    As explained above, EPA is proposing emission standards for the two 
source categories in this proposed rule. For mercury from coal-fired 
area source boilers and POM from all area source boilers, EPA is 
proposing these standards under CAA sections 112(d)(2) and 112(h). For 
the other urban HAP which formed the basis of the CAA section 112(c)(3) 
listing, EPA is proposing standards pursuant to CAA section 112(d)(5).
    In selecting the proposed emission standards, we are using PM as a 
surrogate for the non-mercury metallic urban HAP (arsenic, beryllium, 
cadmium, chromium, lead, manganese, and nickel). The inherent 
variability and unpredictability of the non-mercury metal HAP 
compositions and amounts in fuel have a material effect on the 
composition and amount of non-mercury metal HAP in the emissions from 
the boiler. As a result, establishing individual numerical emissions 
limits for each non-mercury HAP metal species is difficult given the 
level of uncertainty about the individual non-mercury metal HAP 
compositions of the fuels that will be combusted. An emission 
characteristic common to all boilers is that the non-mercury metal HAP 
are a component of the PM contained in the fly ash emitted from the 
boiler. A sufficient correlation exists between PM and non-mercury 
metallic HAP to rely on PM as a surrogate for these HAP and for their 
control. Therefore, the same control techniques that would be used to 
control the fly-ash PM will control non-mercury metallic HAP. Emissions 
limits established to achieve control of PM will also achieve control 
of non-mercury metal HAP. Consequently, we used PM as a surrogate for 
the non-mercury metal urban HAP in establishing emissions limits. The 
use of PM as a surrogate will also eliminate the cost of performance 
testing to comply with numerous standards for individual non-mercury 
metals.
    We looked at mercury separately from other metallic urban HAP due 
to its different chemical characteristics and applicable controls.
    For the organic urban HAP listed for these source categories (POM, 
acetaldehyde, acrolein, dioxins, PCB, and formaldehyde), we used CO as 
a surrogate to represent the organic urban HAP emitted from the 
boilers. The presence of CO is an indicator of incomplete combustion. A 
high level of CO in emissions is an indicator of incomplete combustion 
and, thus, a potential indication of elevated organic HAP emissions. 
Monitoring equipment for CO is readily available, which is not the case 
for organic HAP. Also, it is significantly easier and less expensive to 
measure and monitor CO emissions than to measure and monitor emissions 
of each individual organic HAP. We considered other surrogates, such as 
THC, but lacked data on emissions and permit limits for area source 
boilers. Therefore, using CO as a surrogate for organic urban HAP is a 
reasonable approach because minimizing CO emissions will result in 
minimizing organic urban HAP emissions.

D. How did EPA determine the proposed standards for existing units?

    Both industrial boilers and institutional/commercial boilers have 
been on the list of CAA section 112(c)(6) source categories for mercury 
and POM. That section requires MACT standards for each of the 
pollutants needed to achieve regulation of 90 percent of the emissions 
of the relevant pollutant. As previously noted, the CAA allows EPA to 
establish standards under GACT instead of MACT for urban HAP we propose 
to regulate to fulfill CAA section 112(c)(3).
    As discussed previously, CAA section 112(h) allows the 
Administrator to promulgate a design, equipment, work practice, or 
operational standard, or combination thereof, in certain cases where, 
in the judgment of the Administrator, it is not feasible to prescribe 
or enforce an emission standard under CAA section 112(d). These cases 
include the situation in which the application of measurement 
methodology to a particular class of sources is not practicable due to 
technical and economic limitations.
    As we establish emission standards for each source category listed 
pursuant to CAA section 112(c)(6), we learn more about the source 
category. As part of our analysis, we examine the available information 
about the source category, and we re-examine the inventory associated 
with the original listing. We continue to believe that we must regulate 
POM from coal-fired, biomass-fired, and oil-fired area source boilers 
in order to meet the requirement in section 112(c)(6), and propose 
below MACT-based limits for POM for all categories. However, based on 
the information we have learned to date as we are developing standards 
for various source categories, such as major source boilers, gold 
mines, commercial and industrial solid waste incinerators, and other 
categories, we believe that we only need coal-fired area source boilers 
to meet the 90 percent requirement set forth in section 112(c)(6) for 
mercury. Therefore,

[[Page 31905]]

we propose as our primary option MACT-based controls for mercury only 
for coal-fired boilers.
    With respect to mercury from area source boilers classified as 
biomass-fired or oil-fired, as well as with respect to other urban HAP 
besides POM, we have developed proposed standards that reflect GACT for 
these two area source categories.
1. MACT Analysis for Mercury From Coal-Fired Boilers and POM
    All standards established pursuant to CAA section 112(d)(2) must 
reflect MACT, the maximum degree of reduction in emissions of air 
pollutants that the Administrator, taking into consideration the cost 
of achieving such emissions reductions, and any non-air quality health 
and environmental impacts and energy requirements, determined is 
achievable for each category or subcategory. For existing sources, MACT 
cannot be less stringent than the average emission limitation achieved 
by the best performing 12 percent of existing sources in the category 
or subcategory for categories or subcategories with 30 or more sources. 
This requirement constitutes the ``MACT floor'' for existing area 
source boilers. EPA may not consider cost in determining the MACT 
floor. EPA must consider cost, non-air quality health and environmental 
impacts, and energy requirements in evaluating whether it is 
appropriate to set a standard more stringent than the MACT floor 
(beyond-the-floor controls).
a. MACT Floor Analysis for Mercury and POM
    The approach selected for determining the MACT floors is based on 
estimating the emissions levels achieved on average by the best 12 
percent of existing sources, for which we have information. In terms of 
developing MACT emission limits for area source boilers, we have:

--No emission data for POM,
--Limited emission data (nine coal-fired boilers) for mercury,
--No State regulations applicable for mercury or POM,
--No State permits specific for mercury or POM,
--No surrogate for mercury, but CO as a surrogate for POM,
--Emission data on four coal-fired area source boilers using add-on 
control technology for mercury,
--Limited emission data for CO (5 coal-fired boilers, 30 wood-fired 
boilers, 68 oil-fired boilers),
--A few State permits with CO limits for coal, oil, and wood-fired area 
source boilers,
    The MACT floor limits for each of the HAP and HAP surrogates 
(mercury and CO) are calculated based on the performance of the lowest 
emitting (best performing) sources in each of the subcategories. We 
ranked all of the sources for which we had data based on their 
emissions and identified the lowest emitting 12 percent of the sources 
for each HAP.
    We first considered whether fuel switching would be an appropriate 
control option for sources in each subcategory. We considered the 
feasibility of fuel switching to other fuels used in the subcategory 
and to fuels from other subcategories. This consideration included 
determining whether switching fuels would achieve lower HAP emissions. 
A second consideration was whether fuel switching could be technically 
achieved by boilers in the subcategory considering the existing design 
of boilers. We also considered the availability of various types of 
fuel.
    After considering these factors, we determined that fuel switching 
was not an appropriate control technology for purposes of determining 
the MACT floor level of control for any subcategory. This decision was 
based on the overall effect of fuel switching on HAP emissions, 
technical and design considerations discussed previously in this 
preamble, and concerns about fuel availability. This determination is 
discussed in the memorandum ``Development of Fuel Switching Costs and 
Emission Reductions for Industrial, Commercial, and Institutional 
Boilers and Process Heaters National Emission Standards for Hazardous 
Air Pollutants--Area Source'' located in the docket.
    We used the emissions data for those best performing affected 
sources to determine the emission limits to be proposed, with an 
accounting for variability. EPA must exercise its judgment, based on an 
evaluation of the relevant factors and available data, to determine the 
level of emissions control that has been achieved by the best 
performing sources under variable conditions. The Court has recognized 
that EPA may consider variability in estimating the degree of emission 
reduction achieved by best-performing sources and in setting MACT 
floors. See Mossville Envt'l Action Now v. EPA, 370 F.3d 1232, 1241-42 
(DC Cir 2004) (holding EPA may consider emission variability in 
estimating performance achieved by best-performing sources and may set 
the floor at level that best-performing source can expect to meet 
``every day and under all operating conditions'').
    To calculate the achieved emission limit, including variability, we 
used the equation:
[GRAPHIC] [TIFF OMITTED] TP04JN10.000

Where:

n = the number of test runs
m = the number of test runs in the compliance average
s = standard deviation of emission data
t(0.99, n-1) = the t-statistic
x = emissions data average

Specifically, the MACT floor limit is an upper prediction limit (UPL) 
calculated with the Student's t-test using the TINV function in 
Microsoft Excel. The Student's t-test has also been used in other EPA 
rulemakings in accounting for variability. A prediction interval for a 
future observation is an interval that will, with a specified degree of 
confidence, contain the next (or some other pre-specified) randomly 
selected observation from a population. In other words, the prediction 
interval estimates what future values will be, based upon present or 
past background samples taken. Given this definition, the UPL 
represents the value which we can expect the mean of 3 future 
observations (3-run average) to fall below, based upon the results of 
an independent sample from the same population. That is, if we were to 
randomly select a future test condition from any of these sources 
(i.e., average of 3 runs), we can be 99 percent confident that the 
reported level will fall at or below the UPL value. To calculate the 
UPL, we used the average (or sample mean) and sample standard deviation 
(SD), which are two statistical measures calculated from the sample 
data. The average is the central value of a data set, and the SD is the 
common measure of the dispersion of the data set around the average.

    Based on this limited available information, the MACT floor 
analyses for the three subcategories (coal, biomass, and oil) are 
discussed below.
    1. Existing area source boilers designed for coal firing:
    Mercury--The total number of coal-fired area source boilers for 
which we have actual mercury emission data is 9. Thus, the top 12 
percent is based on emissions from two boilers. The average mercury 
emission level of the top 12 percent is 1.3 pounds per trillion Btu 
(lb/TBtu). The SD of test runs in the top 12 percent boilers is 0.322. 
Therefore, the 99 percent UPL level is 2.5 lb/TBtu. The resulting MACT 
floor mercury limit for existing coal-fired area source boilers is 2.5 
lb/T Btu (rounded to 0.000003 lb/

[[Page 31906]]

million Btu). No fuel analysis data from boilers in the top 12 percent 
were available for assessing the impact of fuel variability on mercury 
emissions.
    POM--None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. However, one 
State (New Jersey) does have standards for CO, but for boilers the size 
of coal-fired area source boilers, the requirement is actually a work 
practice standard for CO (i.e., boiler tune-up). For small (less than 
50 MMBtu/h) boilers, the New Jersey requirement is to maintain and 
operate the source in accordance with manufacturer specifications.
    The available State permits obtained for coal-fired area source 
boilers limiting CO emissions were for 12 units located in Ohio (3 
units), California (1 unit), and Illinois (8 units). We also obtained 
CO emission data from 5 coal-fired area source boilers as part of the 
information collection effort for the major source NESHAP. Therefore, 
the top 12 percent is made up of three boilers. The average CO level of 
the top 12 percent is 162 parts per million (ppm) at 3 percent oxygen. 
The SD of the run data in top 12 percent boilers is 92.1 ppm. 
Therefore, the 99 percent UPL level is 390 ppm at 3 percent oxygen. The 
resulting MACT floor CO limit for existing coal-fired area source 
boilers is 310 ppm at 7 percent oxygen. We correct to 7 percent oxygen 
because that is typically in the oxygen range that coal-fired boilers 
operate and we rounded up to the nearest 10 ppm.
    2. Existing area source boilers designed for biomass firing:
    POM--None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. Actual CO 
emission data were available from the National Forest Service's Fuels 
for Schools program for 14 wood-fired boilers. Also, State permits 
limiting CO emissions from biomass boilers were obtained on another 24 
biomass-fired area source boilers. We also obtained CO emission test 
data from 26 biomass-fired area source boilers as part of the major 
source ICR survey.
    The top 12 percent is made up of 8 boilers. The average CO level of 
the top 12 percent is 80.6 ppm at 3 percent oxygen. The SD of the top 
12 percent boilers is 73.5 ppm. The 99 percent UPL is 192 ppm at 3 
percent oxygen, rounded up to 200 ppm. Biomass-fired boilers typically 
operate at around 7 percent oxygen. Therefore, the MACT floor level is 
160 ppm CO at 7 percent oxygen.
    3. Existing area source boilers designed for oil firing:
    POM--None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. Actual CO 
emission data were available from 68 oil-fired area source boilers 
responding to the Boiler MACT ICR. State permits limiting CO emissions 
from oil-fired area source boilers were obtained on 56 oil-fired area 
source boilers.
    The top 12 percent is made up of 15 boilers. The average CO level 
of the top 12 percent is 1 ppm at 3 percent oxygen. Based on the test 
runs from these 15 best performing units, the 99 percent UPL level is 2 
ppm at 3 percent oxygen. Therefore, the MACT floor level is 2 ppm CO at 
3 percent oxygen. Because oil-fired boilers typically operate at around 
3 percent oxygen, additional oxygen content correction was not 
necessary.
4. Work Practice Standards for Smaller Boilers
    As previously discussed, CAA section 112(h)(1) states that the 
Administrator may prescribe a work practice standard or other 
requirements, consistent with the provisions of CAA sections 112(d) or 
(f), in those cases where, in the judgment of the Administrator, it is 
not feasible to enforce an emission standard. CAA section 112(h)(2)(B) 
further defines the term ``not feasible'' to mean when ``the 
application of measurement technology to a particular class of sources 
is not practicable due to technological and economic limitations.''
    The standard reference methods for measuring emissions of mercury, 
CO (as a surrogate for POM), and PM (as a surrogate for urban non-
mercury metals) are EPA Methods 29, 10, and 5 of 40 CFR part 60 
appendices A-8, A-4, and A-3, respectively. These methods are reliable 
and relatively inexpensive. However, the methods are not applicable for 
sampling small diameter (less than 12 inches) stacks. For example, in 
these small diameter stacks, the conventional Method 5 stack assembly 
blocks a significant portion of the cross-section of the duct and 
causes inaccurate measurements. Many existing area source boilers have 
stacks with diameters less than 12 inches. The stack diameter is 
generally related to the size of the boiler. Boilers that have a 
capacity below 10 MMBtu/h generally have stacks with diameters less 
than 12 inches. Also, many area source boilers do not currently have 
sampling ports or a platform for accessing the exhaust stack which 
would require an expensive modification to install sampling ports and a 
platform.
    We conducted a cost-to-sales analysis to evaluate the economic 
impact of the testing and monitoring costs that area source boiler 
facilities would incur to demonstrate compliance with the proposed 
emission limits. The annual compliance costs imposed on each source is 
for the costs of a stack test for mercury and PM emissions and a 
continuous emission monitor (CEM) for CO emissions. We assumed that 
each establishment in each industry, commercial, or institutional 
sector would be associated with a single boiler. The financial impacts 
of potential compliance costs are assessed for representative entities 
in each entity sector using the ratio of compliance costs to the 
average representative entity revenue (cost-to-sales ratio or CSR).
    The results of the analysis indicate that total compliance costs 
exceed 3 percent (and can reach as high as 19 percent) of the average 
firm revenues for 79 percent of the facilities. This indicates that the 
annual costs for testing and monitoring alone would have a significant 
adverse economic impact on these facilities. The severity of the 
economic impact would depend on the size of the facility. For small 
institutional (schools) and commercial (farms) facilities the costs 
would be prohibitive. This analysis is discussed in the memorandum 
``Cost-to-Sales Analysis of Testing and Monitoring Costs'' located in 
the docket.
    Based on this analysis, pursuant to CAA section 112(h), EPA is 
proposing that it is not feasible to enforce emission standards for 
area source boilers having a heat input capacity of less than 10 MMBtu/
h because of the technological and economic limitations described 
above. Thus, a work practice, as discussed below, is being proposed to 
limit the emissions of mercury and CO (as a surrogate for POM) for 
existing area source boilers having a heat input capacity of less than 
10 MMBTU/h. We are specifically requesting comment on whether a 
threshold higher than 10 MMBtu/h meets the technical and economic 
limitations as specified in section 112(h).
    For existing area source boilers, the only work practice being used 
that potentially controls mercury and POM emissions is a boiler tune-
up. Mercury is a fuel dependent HAP. That is, the amount of mercury 
emitted from the boiler depends on the amount of mercury contained in 
the fuel. Fuel usage can be reduced by improving the combustion 
efficiency of the boiler. At best, boilers may be 85 percent efficient 
and untuned boilers may have combustion efficiencies of 60 percent or 
lower. As combustion efficiency

[[Page 31907]]

decreases, fuel usage increases to maintain energy output resulting in 
increased emissions.
    On the other hand, POM is formed from incomplete combustion of the 
fuel. The objective of good combustion is to release all the energy in 
the fuel while minimizing losses from combustion imperfections and 
excess air. The combination of the fuel with the oxygen requires 
temperature (high enough to ignite the fuel constituents), mixing or 
turbulence (to provide intimate oxygen-fuel contact), and sufficient 
time (to complete the process), sometimes referred to as the three Ts 
of combustion. Good combustion practice (GCP), in terms of boilers, 
could be defined as the system design and work practices expected to 
minimize organic HAP emissions.
    We have obtained information on area source boilers reported using 
GCP, as part of the information collection effort for the major source 
NESHAP. The data that we have suggests that area source boilers 
typically conduct boiler tune-ups. We also reviewed State regulations 
and permits applicable to area source boilers. The work practices 
listed in State regulations includes tune-ups (10 States), operator 
training (1 State), periodic inspections (2 States), and operation in 
accordance with manufacturer specifications (1 State). Of the 44 area 
source boilers with a capacity of less than 10 MMBtu/h that responded 
to EPA's information collection effort for major source NESHAP, 28 (or 
64 percent) reported conducting a boiler tune-up program. Ultimately, 
we determined that at least 6 percent of the boilers in each of the 
subcategories are subject to a tune-up requirement. Therefore, the work 
practice of a tune-up does establish the MACT floor for mercury and POM 
emissions from existing area source boilers with a heat input capacity 
of less than 10 MMBtu/h.
    A detailed discussion of the MACT floor methodology is presented in 
the memorandum ``MACT Floor Analysis for the Industrial, Commercial, 
and Institutional Area Source Boilers'' in the docket.
    b. Beyond-the-Floor Determination for Mercury and POM.
    We considered the pollution prevention and energy conservation 
measure of an energy assessment as a beyond-the-floor option for 
mercury and POM emissions. An energy assessment provides valuable 
information on improving energy efficiency. An energy assessment, or 
energy audit, is an in-depth energy study identifying all energy 
conservation measures appropriate for a facility given its operating 
parameters. An energy assessment refers to a process which involves a 
thorough examination of potential savings from energy efficiency 
improvements, pollution prevention, and productivity improvement. It 
leads to the reduction of emissions of pollutants through process 
changes and other efficiency modifications. Besides reducing operating 
and maintenance costs, improving energy efficiency reduces negative 
impacts on the environment. Improvement in energy efficiency results in 
decreased fuel use which results in a corresponding decrease in 
emissions (both HAP and non-HAP) from the boiler, but not necessarily 
all those present. The Department of Energy (DOE) has conducted energy 
assessments at selected manufacturing facilities and reports that 
facilities can reduce fuel/energy use by 10 to 15 percent by using best 
practices to increase their energy efficiency. Many best practices are 
considered pollution prevention because they reduce the amount of fuel 
combusted which results in a corresponding reduction in emissions from 
the fuel combustion. The most common best practice is simply tuning the 
boiler to the manufacturer's specification.
    The one-time cost of an energy assessment ranges from $2500 to 
$55,000 depending on the size of the facility. If a facility elected to 
implement the cost-effective energy conservation measures identified in 
the energy assessment, it would potentially result in greater mercury 
and POM reduction than achieved by a boiler tune-up alone. In addition, 
the cost of an energy assessment is minimal, in most cases, compared to 
the cost for testing and monitoring to demonstrate compliance with an 
emission limit. Furthermore, the costs of any energy conservation 
improvement will be offset by the cost savings in lower fuel costs. 
Therefore, we decided to go beyond the MACT floor for this proposed 
rule for the existing area source boilers. The proposed standards for 
existing area source facilities with a boiler that has a capacity equal 
to or greater than 10 MMBtu/h for mercury and POM include the 
requirement of a performance of an energy assessment to identify energy 
conservation measures. Since there was insufficient information to 
determine if requiring implementation of cost-effective measures were 
economically feasible, we are seeking comment on this point.
    In this proposed rule, we are defining a cost-effective energy 
conservation measure to be any measure that has a payback (return of 
investment) period of two years or less. This payback period was 
selected based on section 325(o)(2)(B)(iii) of the Energy Policy and 
Conservation Act which states that there is a presumption that an 
energy conservation standard is economically justified if the increased 
installed cost for a measure is less than three times the value of the 
first-year energy savings resulting from the measure.
    We believe that an energy assessment is an appropriate beyond-the-
floor control technology because it is one of the measures identified 
in CAA section 112(d)(2). CAA section 112(d)(2) states that ``Emission 
standards promulgated * * * and applicable to new or existing sources * 
* * is achievable * * * through application of measures, processes, 
methods, systems or techniques including, but not limited to measures 
which--
    (A) reduce the volume of, or eliminate emissions of, such 
pollutants through process changes, substitution of materials or other 
modifications,

The purpose of an energy assessment is to identify energy conservation 
measures (such as process changes or other modifications to the 
facility) that can be implemented to reduce the facility energy demand 
which would result in reduced fuel use. Reduced fuel use will result in 
a corresponding reduction in HAP, and non-HAP, emissions. Thus, an 
energy assessment, in combination with the MACT emission limits will 
result in the maximum degree of reduction in emissions as required by 
112(d)(2). Therefore, we are proposing to require all existing sources 
to conduct a one-time energy assessment to identify cost-effective 
energy conservation measures on the boiler's energy consuming systems.
    We are proposing that the energy assessment be conducted by energy 
professionals and/or engineers that have expertise that cover all 
energy using systems, processes, and equipment. We are aware of at 
least two organizations that provide certification of specialists in 
evaluating energy systems. We are proposing that a qualified specialist 
is someone who has successfully completed the Department of Energy's 
Qualified Specialist Program for all systems or a professional engineer 
certified as a Certified Energy Manager by the Association of Energy 
Engineers.
    We are specifically requesting comment on: (1) Whether our 
estimates of the assessment costs are correct; (2) is there adequate 
access to certified assessors; (3) are there other organizations for 
certifying energy engineers; (4) are online tools adequate

[[Page 31908]]

to inform the facility's decision to make efficiency upgrades; (5) is 
the definition of ``cost-effective'' appropriate in this context since 
it refers to payback of energy saving investments without regard to the 
impact on HAP reduction; and (6) what rate of return should be used.
    A detailed description of the beyond-the-floor consideration is in 
the memorandum ``Methodology for Estimating Cost and Emissions Impacts 
for Industrial, Commercial, Institutional Area Source Boilers'' in the 
docket.
2. GACT Determination for Existing Area Source Boilers
    As provided in CAA section 112(d)(5), we are proposing standards 
representing GACT for these area source boilers.
    For existing coal and biomass-fired area source boilers, the add-on 
control technology generally being used is multiclones. We found that 
this technology is minimally effective in controlling urban metal HAP 
and has no effect on urban organic HAP.
    Multiclones are mechanical separators that use velocity 
differential across the cyclones to separate particles. A multiclone 
uses several smaller diameter cyclones to improve efficiency. 
Multiclones have a control efficiency for PM emissions of about 75 
percent. Multiclones are more efficient in collecting larger particles 
and their collection efficiency falls off at small particle sizes. This 
is a disadvantage because non-mercury metallic HAP tend to be on small 
size particles (i.e., fine particle enrichment). Based on emission data 
obtained during the major source NESHAP development, multiclones have a 
control efficiency for non-mercury metallic HAP of only about 10 
percent and have no effect on reducing mercury emissions. The cost of 
using multiclones (capital, testing, and monitoring) is estimated to be 
between $50,000 and $100,000 depending on the size of the boiler.
    We also considered various pollution prevention and energy 
conservation options as the potential basis for GACT for the urban 
metal HAP and the organic urban HAP. The most common options, and 
generally available, are simply tuning the boiler to the manufacturer's 
specification. A boiler tune-up provides potential savings from energy 
efficiency improvements and pollution prevention. Besides reducing 
operating and maintenance costs, improving energy efficiency reduces 
negative impacts on the environment. Improvement in energy efficiency 
results in decreased fuel use which results in a corresponding decrease 
in emissions (both HAP and non-HAP) from the boiler. A boiler tune-up 
requirement would potentially result in the same non-mercury metallic 
HAP reduction as a PM emission limit based on performance of 
multiclones but would also reduce emissions of organic HAP. In 
addition, the cost of a boiler tune-up appears minimal compared to the 
cost for testing and monitoring to demonstrate compliance with an 
emission limit.
    For existing oil-fired area source boilers, we found no add-on 
control technology being used.
    Therefore, we determined that GACT for existing area source boilers 
with heat input capacities of 10 MMBtu/hour or greater is a management 
practice requiring the implementation of a boiler tune-up program. 
Thus, for existing area source boilers, we are proposing GACT for HAP 
other than mercury and POM to be a management practice requiring the 
implementation of a boiler tune-up program.
    If we conclude that our obligations under section 112(c)(6) for 
mercury can be met without mercury emissions from biomass-fired or oil-
fired area source boilers, we believe that several requirements of this 
proposed rule would be generally available to the regulated community 
and would provide some control of mercury and other fuel-bound 
pollutants at existing sources with larger boilers. For example, the 
requirements to optimize combustion, conduct an energy assessment, and 
conduct biennial tune-ups would decrease emissions of mercury because 
less fuel would be burned. In contrast, we do not believe that fabric 
filters are widely used now, would be expensive to install for small 
businesses, and therefore would not be considered GACT. Therefore, we 
seek comment on whether the various measures discussed in this preamble 
to reduce fuel consumption in connection with POM control and control 
of urban metal HAP and organic urban HAP would represent GACT for 
mercury emitted from biomass-fired and oil-fired area source boilers.

E. How did EPA determine the proposed standards for new units?

    As noted above, we have developed the proposed standards to reflect 
the application of MACT for mercury and POM, and GACT for arsenic, 
beryllium, cadmium, lead, chromium, manganese, nickel, ethylene 
dioxide, and polychlorinated biphenyls (PCB).\1\
---------------------------------------------------------------------------

    \1\ The proposed emission standards will also reduce emissions 
of other urban HAP, which did not form the basis of the listing. 
Those urban HAP include benzene, acetaldehyde, acrolein, dioxins, 
and formaldehyde.
---------------------------------------------------------------------------

1. MACT Analysis for Mercury From Coal-fired Boilers and POM
    The CAA specifies that MACT for new boilers shall not be less 
stringent than the emission control that is achieved in practice by the 
best-controlled similar source, as determined by the Administrator. 
This minimum level of stringency is the MACT floor for new units. EPA 
may not consider costs or other impacts in determining the MACT floor. 
However, EPA must consider cost, non-air quality health and 
environmental impacts, and energy requirements in evaluating whether it 
is appropriate to set a standard that is more stringent than the MACT 
floor (beyond-the-floor controls).
    a. MACT Floor Analysis for Mercury and POM. Similar to the MACT 
floor process used for existing area source boilers, the approach used 
for determining the MACT floors for new units is based on estimating 
the emissions levels achieved by the best-controlled similar source, 
for which we have information.
    1. New area source boilers designed for coal firing:
    Mercury--We determined in the context of the major source 
rulemaking for boilers that fabric filters are the most effective 
technology employed by coal-fired industrial, commercial, and 
institutional boilers for controlling mercury emissions. Five coal-
fired area source boilers have been identified as having a fabric 
filter. Based on available emission data, the best performing unit 
(i.e., the unit having the reported lowest mercury level based on a 
three run test) is an area source coal-fired boiler equipped with an 
electrostatic precipitator (ESP). The boiler had a test average for 
mercury of 1.4 lb/TBtu with a SD of 0.307 to account for variability. 
Therefore, the resulting MACT floor mercury limit for new coal-fired 
area source boilers is determined to be 3.2 lb/T Btu. Since this 
calculated value is less stringent than the MACT floor for mercury at 
existing boilers designed for coal firing, the MACT floor for new 
sources was established to be equal to the floor for existing sources 
(0.000003 lb/million Btu).
    POM--For POM emissions, the only control technology identified as 
being used on area source boilers is monitoring and maintaining CO 
emission levels which is associated with minimizing emissions of 
organic HAP (including POM). Carbon monoxide is generally an indicator 
of incomplete combustion because CO will oxidize to carbon dioxide if 
adequate oxygen is available. Therefore, controlling CO emissions can 
be a mechanism for

[[Page 31909]]

ensuring combustion efficiency and may be viewed as a GCP. As discussed 
previously in this preamble, CO is considered a surrogate for organic 
HAP (including POM) emissions in this proposed rule.
    None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. However, one 
State (New Jersey) does have standards for CO, but for boilers the size 
of coal-fired area source boilers, it is actually a work practice 
standard for CO (i.e., tune-up). For small (less than 50 MMBtu/h) 
boilers, New Jersey's requirement is to maintain and operate the source 
in accordance with manufacturers' specifications.
    Considering available State permit data and emission test data for 
coal-fired area source boilers the best controlled similar source is a 
coal-fired area source boiler having an average three run CO test 
emission level of 216 ppm at 3 percent oxygen. The calculated 99 
percent UPL, to account for variability, is 640 ppm at 3 percent 
oxygen. Since this calculated value is less stringent than the MACT 
floor for CO at existing boilers designed for coal firing, the MACT 
floor for new sources was established to be equal to the floor for 
existing sources (310 ppm at 7 percent oxygen).
    2. New area source boilers designed for biomass firing:
    POM--None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. Actual CO 
emission data were available from the Fuels for Schools program for 14 
biomass-fired boilers and from 29 biomass-fired area source boilers as 
part of the major source ICR survey. Also, State permits limiting CO 
emissions from biomass boilers were obtained on another 27 biomass-
fired area source boilers. Therefore, the MACT floor for POM achieved 
by the best controlled similar source is based on actual CO emission 
data.
    The average 3-run test CO level of the best controlled similar 
source is 38.6 ppm at 3 percent oxygen. The SD for the test runs is 14 
ppm. Therefore, the 99 percent UPL is 120 ppm at 3 percent oxygen, 
rounded up to the nearest 10 ppm. Thus, the proposed MACT floor level 
is 100 ppm CO at 7 percent oxygen.
    3. New area source boilers designed for oil firing:
    POM--None of the States for which we have an inventory have an 
applicable emission limit specifically for POM or CO. Actual CO 
emission data were available on 66 oil-fired area source boilers. State 
permits limiting CO emissions from oil-fired area source boilers were 
obtained on 46 oil-fired area source boilers. Therefore, the proposed 
MACT floor for POM achieved by the best controlled similar source would 
be based on the boilers reporting the lowest CO emission level.
    The CO emission level of the best performing similar source is 0.6 
ppm at 3 percent oxygen. The SD of the test runs is 0.04 ppm. 
Therefore, the 99 percent UPL and the proposed MACT floor level is 1 
ppm CO at 3 percent oxygen, rounded up to the nearest whole ppm.
    A detailed description of the MACT floor determination is in the 
memorandum, ``MACT Floor Analysis for Industrial, Commercial, and 
Institutional Area Source Boilers'' in the docket.
    4. Appropriateness of Work Practice Standards for New Area Source 
Boilers:
    As previously discussed, CAA section 112(h) states that the 
Administrator may prescribe a work practice standard or other 
requirements, consistent with the provisions of CAA sections 112(d) or 
(f), in those cases where, in the judgment of the Administrator, it is 
not feasible to enforce an emission standard due to technical and 
economic limitations.
    As was the case for existing small area source boilers, total 
compliance costs would likely exceed 3 percent of the average firm 
revenues for some new facilities. This indicates that the annual costs 
for testing and monitoring alone may have a significant adverse 
economic impact on some new facilities.
    As discussed previously, the standard reference methods for 
measuring emissions of mercury, CO (as a surrogate for POM), and PM (as 
a surrogate for urban non-mercury metals) are EPA Methods 29, 10, and 5 
and are not applicable for sampling small diameter stacks. We solicit 
comment on whether it would be technically infeasible to design 
sampling ports adequate for the test methods in boilers that are below 
a certain size.
    Based on this analysis and the reason discussed below, we are not 
proposing a work practice under CAA section 112(h) for new area source 
boilers. New facilities, as opposed to existing facilities, have the 
added flexibility of including compliance costs into their design and 
planning. This would include the design and cost to provide a 
performance testing facility that has sampling ports adequate for the 
test methods and constructing the exhaust stack such that HAP emission 
rates can be accurately determined. In addition, a new facility has the 
option of fuel selection in minimizing their compliance costs.
    A detailed discussion of the MACT floor methodology is presented in 
the memorandum ``MACT Floor Analysis for the Industrial, Commercial, 
and Institutional Area Source Boilers'' in the docket.
    b. Beyond-the-floor Analysis for Mercury and POM for New Area 
Source Boilers. The MACT floor level of control for new units is based 
on the emission control that is achieved in practice by the best 
controlled similar source within each of the subcategories. No 
technologies or other HAP emission reduction approaches were identified 
that would achieve mercury or POM reduction greater than the new source 
floors for each of the subcategories.
    Therefore, we decided to not go beyond the MACT floor level of 
control for mercury and POM emissions for new area source boilers in 
this proposed rule. A detailed description of the beyond-the-floor 
consideration is in the memorandum ``Methodology for Estimating Cost 
and Emissions Impacts for Industrial, Commercial, Institutional Area 
Source Boilers'' in the docket.
2. GACT Determination for New Area Source Boilers
    The control technologies currently used by facilities in the source 
categories that reduce non-mercury metallic HAP and PM are fabric 
filters and ESP. We determined that these controls are generally 
available and cost effective for new area source boilers. New area 
source boilers with heat input capacity of 10 MMBtu/h or greater are 
subject to the NSPS for boilers (either subpart Db or Dc of 40 CFR part 
60) which regulate emissions of PM and require performance testing. 
Furthermore, new coal-fired area source boilers will likely require a 
PM control device to comply with the proposed mercury MACT standard.
    The emissions database contains PM test data for 82 area source 
boilers obtained from the ICR survey conducted for major sources. All 
of the boilers were greater than 10 million Btu per hour in size. In 
order to develop PM (as a surrogate for non-mercury metallic HAP) 
emission limits for the three subcategories, we compared the PM limits 
in NSPS subpart Dc with the obtained PM emission data. We considered 
this to be an appropriate methodology because many new area source 
boilers will be subject to NSPS subpart Dc. Consequently, we determined 
that the PM limits in the NSPS could be used to establish the PM GACT 
emission limit for area source boilers.

[[Page 31910]]

    The proposed GACT PM emission level based on NSPS subpart Dc for 
new area source boilers is 0.03 lb/million Btu. Of the 82 area source 
boilers for which we have PM emission data, 11 had reported PM emission 
levels below 0.03 lb/million Btu.
    For the organic urban HAP (acetaldehyde, acrolein, dioxins, and 
formaldehyde), the most effective control technology identified is 
minimizing CO emissions and we determined that this control is 
generally available and cost effective for new area source boilers. 
This determination is based on the fact there is no additional costs 
associated with proposing a CO emission limit (as a surrogate for the 
urban organic HAP) as GACT because it is the same as the MACT standard 
being proposed for these subcategories for POM.

F. How did we select the compliance requirements?

    We are proposing testing, monitoring, notification, and 
recordkeeping requirements that are adequate to assure continuous 
compliance with the requirement of the rule. Those requirements are 
described in detail in sections IV.F to IV.H. We selected these 
requirements based upon our determination of the information necessary 
to ensure that the emission standards, work practices, and management 
practices are being followed and that emission control devices and 
equipment are maintained and operated properly. The proposed 
requirements ensure compliance with this proposed rule without 
proposing a significant additional burden for facilities that must 
implement them.
    We are proposing that compliance with the PM and mercury emission 
limits be demonstrated by an initial performance test. To ensure 
continuous compliance with the proposed PM and mercury emission limits, 
this proposed rule would require continuous parameter monitoring of 
control devices and recordkeeping. Additionally, this proposed rule 
requires annual performance tests to ensure, on an ongoing basis, that 
the air pollution control device is operating properly and its 
performance has not deteriorated. If initial compliance with the 
mercury emission limit is demonstrated by a fuel analysis performance 
test, this proposed rule requires fuel analyses monthly, with 
compliance determined based on an annual average.
    We evaluated the cost of applying PM CEMS to area source boilers. 
For PM CEM monitoring, capital costs were estimated to be $88,000 per 
unit and annualized costs were estimated to be $33,000 per unit. The 
estimated national annual cost would be $4.5 billion. We determined the 
costs would make them an unreasonable monitoring option.
    We reviewed the cost information for CO CEMS provided by commenters 
on the NESHAP for major source boilers to make the determination on 
whether to require CO CEMS or conducting annual CO testing to 
demonstrate continuous compliance with the CO emission limit. In 
evaluating the available cost information, we determined that requiring 
CO CEMS for units with heat input capacities greater or equal to 100 
MMBtu/hr is reasonable. This proposed rule requires units with heat 
input capacities less than 100 MMBtu/hr to conduct initial and annual 
performance (stack) tests.

G. Alternative MACT Standards for Consideration

    Our analysis of the inventory for mercury under CAA section 
112(c)(6) has led us to believe that we do not need to regulate 
biomass-fired and oil-fired boilers under MACT in order to meet our 
statutory obligations under this provision. We solicit comment on 
whether we should require the MACT-based emission limits on mercury 
emissions from larger boilers in this category if we conclude that such 
controls are unnecessary to meet our obligations under section 
112(c)(6).
    We also solicit comment on MACT-based requirements for mercury 
emitted from biomass-fired and oil-fired area source boilers in the 
event comment and further analysis of the inventory demonstrates such 
regulation is necessary to fulfill the 90 percent requirement under CAA 
section 112(c)(6) or is otherwise appropriate. We present what would be 
MACT below.
    1. Existing area source boilers designed for biomass firing:
    Mercury--We obtained mercury emission data from two biomass-fired 
area source boilers as part of the information collection effort for 
the major source NESHAP. Thus, the top 12 percent would be comprised of 
one boiler. The average mercury level of the top 12 percent is 0.36 lb/
TBtu. All 3 test runs results were nondetect. The standard deviation 
for the three detection limits, when converted to lb/mmBtu using the 
heat input rates during each run, was 1.82E-09. Therefore, the 
resulting MACT floor mercury limit for existing biomass-fired area 
source boilers would be 0.37 lb/TBtu (rounded to 0.0000004 lb/MMBtu).
    2. Existing area source boilers designed for oil firing:
    Mercury--There are no available emission data, State regulations, 
or State permits regarding mercury emissions from oil-fired area source 
boilers. Available emission factors are generally the average of 
available data and would not reasonably represent the average of the 
top 12 percent best performing units. However, we have obtained mercury 
emission data on major source oil-fired boilers as part of the major 
source rulemaking. Since major source oil-fired boilers are similar in 
design and controls as compared to area source oil-fired boilers, we 
are applying the major source MACT limit of 4 lb/TBtu (0.000004 lb/
MMBtu) to existing oil-fired area source boilers.
    3. New area source boilers designed for biomass firing:
    Mercury--We determined in the context of the major source 
rulemaking for boilers that fabric filters are the most effective 
technology employed by biomass-fired boilers for controlling mercury 
emissions. However, there is no test information on biomass-fired 
boilers equipped with fabric filters in which to determine control 
efficiency.
    The average mercury level of the ``best controlled'' unit for which 
we have emission data is 0.36 lb/TBtu. All 3 test runs results were 
nondetect. The standard deviation for the three detection limits, when 
converted to lb/MMBtu using the heat input rates during each run, was 
1.82E-09. Therefore, the resulting MACT floor mercury limit for 
existing biomass-fired area source boilers would be 0.36 lb/TBtu 
(0.0000004 lb/MMBtu).
    4. New area source boilers designed for oil firing:
    Mercury--There are no available emission data, State regulations, 
or State permits regarding mercury emissions from oil-fired area source 
boilers. Available emission factors are generally the average of 
available data and would not reasonably represent the best performing 
unit. However, we have obtained mercury emission data on major source 
oil-fired boilers as part of the major source rulemaking. Since major 
source oil-fired boilers are similar in design and controls as compared 
to area source oil-fired boilers, we are applying the major source MACT 
limit for new oil-fired boilers of 0.3 lb/TBtu (0.0000003 lb/MMBtu) to 
new oil-fired area source boilers.

H. How did we decide to exempt these area source categories from title 
V permitting requirements?

    For the reasons described below, we are proposing to exempt from 
title V permitting requirements affected sources in the industrial 
boiler and the

[[Page 31911]]

institutional/commercial boiler area source categories that are not 
certain synthetic area sources. We estimate that at least 48 synthetic 
area sources reduced their HAP emissions to below the major source 
thresholds by installing air pollution control devices. We are not 
proposing to exempt from title V those synthetic area sources that have 
reduced their HAP emissions to below the major source thresholds by 
installing air pollution control devices.
    CAA section 502(a) provides that the Administrator may exempt an 
area source category (in whole or in part) from title V if the 
Administrator determines that compliance with title V requirements is 
``impracticable, infeasible, or unnecessarily burdensome'' on an area 
source category. See CAA section 502(a). In December 2005, in a 
national rulemaking, EPA interpreted the term ``unnecessarily 
burdensome'' in CAA section 502 and developed a four-factor balancing 
test for determining whether title V is unnecessarily burdensome for a 
particular area source category, such that an exemption from title V is 
appropriate. See 70 FR 75320, December 19, 2005 (Exemption Rule).
    The four factors that EPA identified in the Exemption Rule for 
determining whether title V is ``unnecessarily burdensome'' on a 
particular area source category include: (1) Whether title V would 
result in significant improvements to the compliance requirements, 
including monitoring, recordkeeping, and reporting, that are proposed 
for an area source category (70 FR 75323); (2) whether title V 
permitting would impose significant burdens on the area source category 
and whether the burdens would be aggravated by any difficulty the 
sources may have in obtaining assistance from permitting agencies (70 
FR 75324); (3) whether the costs of title V permitting for the area 
source category would be justified, taking into consideration any 
potential gains in compliance likely to occur for such sources (70 FR 
75325); and (4) whether there are implementation and enforcement 
programs in place that are sufficient to assure compliance with the 
NESHAP for the area source category, without relying on title V permits 
(70 FR 75326).
    In discussing these factors in the Exemption Rule, we further 
explained that we considered on ``a case-by-case basis the extent to 
which one or more of the four factors supported title V exemptions for 
a given source category, and then we assessed whether considered 
together those factors demonstrated that compliance with title V 
requirements would be `unnecessarily burdensome' on the category, 
consistent with section 502(a) of the Act.'' See 70 FR 75323. Thus, in 
the Exemption Rule, we explained that not all of the four factors must 
weigh in favor of exemption for EPA to determine that title V is 
unnecessarily burdensome for a particular area source category. 
Instead, the factors are to be considered in combination, and EPA 
determines whether the factors, taken together, support an exemption 
from title V for a particular source category.
    In the Exemption Rule, in addition to determining whether 
compliance with title V requirements would be unnecessarily burdensome 
on an area source category, we considered, consistent with the guidance 
provided by the legislative history of CAA section 502(a), whether 
exempting the area source category would adversely affect public 
health, welfare, or the environment. See 70 FR 15254-15255, March 25, 
2005. As explained below, we propose that title V permitting is 
unnecessarily burdensome for a majority of the area sources at issue in 
this proposed rule. We have also determined that the proposed 
exemptions from title V would not adversely affect public health, 
welfare, and the environment. Our rationale for this decision follows 
here.
    In considering the exemption from title V requirements for sources 
in the categories affected by this proposed rule, we first compared the 
title V monitoring, recordkeeping, and reporting requirements (factor 
one) to the requirements in the proposed NESHAP for the boiler area 
source categories. This proposed rule requires facilities to comply 
with either emission limits using add-on controls or process changes or 
implementation of certain work or management practices. This proposed 
rule would require direct monitoring of emissions or control device 
parameters, both continuous and periodic, recordkeeping that also may 
serve as monitoring, and deviation and other semi-annual reporting to 
assure compliance with this NESHAP.
    The monitoring component of the first factor favors title V 
exemption. For the work and management practices, this proposed 
standard provides monitoring in the form of recordkeeping that would 
assure compliance with the requirements of this proposed rule. 
Monitoring by means other than recordkeeping for the work and 
management practices is not practical or appropriate. Records are 
required to ensure that the work and management practices are followed. 
This proposed rule requires continuous parameter monitoring, with 
periodic recording of the parameter for the required control device, to 
assure compliance. The records are required to be maintained in a form 
suitable and readily available for expeditious review, and that they 
are kept for at least five years, the first two of which must be 
onsite.
    As part of the first factor, in addition to monitoring, we have 
considered the extent to which title V could potentially enhance 
compliance for area sources covered by this proposed rule through 
recordkeeping or reporting requirements. We have considered the various 
title V recordkeeping and reporting requirements, including 
requirements for a 6-month monitoring report, deviation reports, and an 
annual certification in 40 CFR 70.6 and 71.6.
    For any boiler area source, this proposed NESHAP requires an 
Initial Notification and a Notification of Compliance Status. This 
proposed rule also requires facilities to certify compliance with the 
emission limits, work practices, and management practices. In addition, 
facilities must maintain records showing compliance through the 
required parameter monitoring and deviation requirements. The 
information required in the deviation reports is similar to the 
information that must be provided in the deviation reports required 
under 40 CFR 70.6(a)(3) and 40 CFR 71.6(a)(3).
    We acknowledge that title V might require additional compliance 
requirements on these categories, but we have determined that the 
monitoring, recordkeeping and reporting requirements of the proposed 
NESHAP are sufficient to assure compliance with the provisions of the 
NESHAP. Given the nature of the operations at most area sources and the 
types of requirements in this rule, title V would not significantly 
improve those compliance requirements.
    For the second factor, we determine whether title V permitting 
would impose a significant burden on the area sources in the categories 
and whether that burden would be aggravated by any difficulty the 
source may have in obtaining assistance from the permitting agency. 
Subjecting any source to title V permitting imposes certain burdens and 
costs that do not exist outside of the title V program. EPA estimated 
that the average cost of obtaining and complying with a title V permit 
was $65,700 per source for a 5-year permit period, including fees. See 
Information Collection Request for Part 70 Operating Permit 
Regulations, January 2007, EPA ICR Number 1587.07. EPA does not have 
specific estimates for the burdens and costs of permitting industrial, 
commercial, and institutional boiler

[[Page 31912]]

area sources; however, there are certain activities associated with the 
part 70 and 71 rules. These activities are mandatory and impose burdens 
on the any facility subject to title V. They include reading and 
understanding permit program guidance and regulations; obtaining and 
understanding permit application forms; answering follow-up questions 
from permitting authorities after the application is submitted; 
reviewing and understanding the permit; collecting records; preparing 
and submitting monitoring reports on a 6-month or more frequent basis; 
preparing and submitting prompt deviation reports, as defined by the 
State, which may include a combination of written, verbal, and other 
communications methods; collecting information, preparing, and 
submitting the annual compliance certification; preparing applications 
for permit revisions every 5 years; and, as needed, preparing and 
submitting applications for permit revisions. In addition, although not 
required by the permit rules, many sources obtain the contractual 
services of consultants to help them understand and meet the permitting 
program's requirements. The ICR for part 70 provides additional 
information on the overall burdens and costs, as well as the relative 
burdens of each activity described here. Also, for a more comprehensive 
list of requirements imposed on part 70 sources (hence, burden on 
sources), see the requirements of 40 CFR 70.3, 70.5, 70.6, and 70.7.
    In assessing the second factor for facilities affected by this 
proposal, we found that most of the facilities that would be affected 
by this proposed rule are small entities. These small sources lack the 
technical resources that would be needed to comply with permitting 
requirements and the financial resources that would be needed to hire 
the necessary staff or outside consultants. As discussed above, title V 
permitting would impose significant costs on these area sources, and, 
accordingly, we conclude that title V is a significant burden for the 
sources in these categories that we propose to exempt. Furthermore, 
given the estimated 91,300 area source facilities (including schools, 
hospitals, and churches) in the categories, it would likely be 
difficult for them to obtain sufficient assistance from the permitting 
authority. Thus, we conclude that factor two supports title V exemption 
for the sources in these categories that we propose to exempt.
    The third factor, which is closely related to the second factor, is 
whether the costs of title V permitting for these area sources would be 
justified, taking into consideration any potential gains in compliance 
likely to occur for such sources. We explained above under the second 
factor that the costs of compliance with title V would impose a 
significant burden on many of the approximately 137,000 facilities 
affected by this proposed rule. We also concluded in considering the 
first factor that, while title V might impose additional requirements, 
the monitoring, recordkeeping and reporting requirements in this 
proposed NESHAP assure compliance with the emission standards, work 
practices, and management practices imposed in the NESHAP. In addition, 
below in our consideration of the fourth factor, we find that there are 
adequate implementation and enforcement programs in place to assure 
compliance with the NESHAP. Because the costs, both economic and non-
economic, of compliance with title V are high, and the potential for 
gains in compliance is low, title V permitting is not justified for the 
sources we propose to exempt. Accordingly, the third factor supports 
title V exemptions for these area source categories, except as 
discussed below.
    The fourth factor we considered in determining if title V is 
unnecessarily burdensome is whether there are implementation and 
enforcement programs in place that are sufficient to assure compliance 
with the NESHAP without relying on title V permits. EPA has implemented 
regulations that provide States the opportunity to take delegation of 
area source NESHAP, and we believe that State delegated programs are 
sufficient to assure compliance with this NESHAP. See 40 CFR part 63, 
subpart E (States must have adequate programs to enforce the CAA 
section 112 regulations and provide assurances that they will enforce 
the NESHP before EPA will delegate the program).
    We also note that EPA retains authority to enforce this NESHAP 
anytime under CAA sections 112, 113, and 114. Also, States and EPA 
often conduct voluntary compliance assistance, outreach, and education 
programs (compliance assistance programs), which are not required by 
statute. We determined that these additional programs will supplement 
and enhance the success of compliance with these proposed standards. We 
believe that the statutory requirements for implementation and 
enforcement of this NESHAP by the delegated States and EPA and the 
additional assistance programs described above together are sufficient 
to assure compliance with these proposed standards without relying on 
title V permitting.
    In light of all the information presented here, we believe that 
there are implementation and enforcement programs in place that are 
sufficient to assure compliance with the proposed standards without 
relying on title V permitting for the sources we are proposing to 
exempt.
    Balancing the four factors for these area source categories 
strongly supports the proposed finding that title V is unnecessarily 
burdensome for the sources we propose to exempt. While title V might 
add additional compliance requirements if imposed, we believe that 
there would not be significant improvements to the compliance 
requirements in this proposed rule because the proposed rule 
requirements are specifically designed to assure compliance with the 
emission standards imposed on the area sources we propose to exempt. We 
further maintain that the economic and non-economic costs of compliance 
with title V would impose a significant burden on the sources we 
propose to exempt. We determined that the high relative costs would not 
be justified given that there is likely to be little or no potential 
gain in compliance if title V were required. And, finally, there are 
adequate implementation and enforcement programs in place to assure 
compliance with these proposed standards. Thus, we propose that title V 
permitting is ``unnecessarily burdensome'' for these area source 
categories, except as discussed below.
    In addition to evaluating whether compliance with title V 
requirements is ``unnecessarily burdensome'', EPA also considered, 
consistent with guidance provided by the legislative history of CAA 
section 502(a), whether exempting these area source categories from 
title V requirements would adversely affect public health, welfare, or 
the environment. Exemption of these area source categories from title V 
requirements would not adversely affect public health, welfare, or the 
environment because the level of control would remain the same if a 
permit were required. The title V permit program does not impose new 
substantive air quality control requirements on sources, but instead 
requires that certain procedural measures be followed, particularly 
with respect to determining compliance with applicable requirements. As 
stated in our consideration of factor one for this category, title V 
would not lead to significant improvements in the compliance 
requirements applicable to existing or new area sources that we propose 
to exempt.

[[Page 31913]]

    Furthermore, we explained in the Exemption Rule that requiring 
permits for the large number of area sources could, at least in the 
first few years of implementation, potentially adversely affect public 
health, welfare, or the environment by shifting State agencies 
resources away from assuring compliance for major sources with existing 
permits to issuing new permits for these area sources, potentially 
reducing overall air program effectiveness. Based on the above 
analysis, we conclude that title V exemptions for these area sources 
would not adversely affect public health, welfare, or the environment 
for all of the reasons explained above.
    For the reasons stated here, we are proposing to exempt these area 
source categories, except for certain synthetic area sources, as 
explained below, from title V permitting requirements.
    We have determined that it is not appropriate to exempt from Title 
V requirements those synthetic area sources that installed air 
pollution controls. Unlike many other area source categories that we 
have exempted from title V while implementing the requirements of CAA 
sections 112(c)(3) and 112(k)(3)(B), the boiler area source categories 
include a number of synthetic area sources that installed air pollution 
controls to become area sources. Synthetic area sources that installed 
controls represent less than one percent of the total number of sources 
that will be subject to the final rule. In fact, these sources are much 
more like the major sources of HAP that will be subject to the Boiler 
MACT. In addition, many of these sources are located in cities, and 
often in close proximity to residential and commercial centers where 
large numbers of people live and work. The record also indicates that 
many of these synthetic area sources have significantly higher 
emissions potential when uncontrolled than the other sources in the 
boiler area source categories, even those that are synthetic minor 
sources that took operational limits to attain area source status.
    For these reasons, we believe that the additional public 
participation and compliance benefits of additional informational, 
monitoring, reporting, certification, and enforcement requirements that 
exist in title V should be the same for a major source that installed a 
control device after 1990 to become an area source as for a source that 
is major and installed a control device to comply with an applicable 
major source NESHAP, and thereby reduced emissions below major source 
levels (10 tpy of a single HAP and 25 tpy of total HAP). Many of the 
synthetic area sources that became area sources by virtue of installing 
add-on controls are large facilities with comprehensive compliance 
programs in place because their uncontrolled emissions would far exceed 
the major source threshold. We maintain that requiring additional 
public involvement and compliance assurance requirements through title 
V is important to ensure that these sources are maintaining their 
emissions at the area source level.
    For these reasons above, this proposed rule requires title V 
permits for major sources of HAP emissions that installed controls 
after 1990 to become area sources of HAP emissions. We estimate that 
approximately 170 sources that will be subject to this rule are either 
required to have title V permits because of criteria pollutants or the 
proposed rule will require the affected area sources to obtain title V 
permits.
    We are not requiring title V permits for sources that reduced their 
emissions to area source levels by taking operational restrictions, 
such as restricting hours of operation or production, or for natural 
area sources, for the reasons set forth above.

VI. Summary of the Impacts of This Proposed Rule

A. What are the air impacts?

    Table 2 of this preamble illustrates, for each subcategory, the 
estimated emissions reductions achieved by this proposed rule (i.e., 
the difference in emissions between an area source boiler controlled to 
the MACT/GACT level of control and boilers at the current baseline) for 
new and existing sources. Nationwide emissions of total HAP (hydrogen 
chloride, hydrogen fluoride, non-mercury metals, mercury, and VOC (for 
organic HAP) will be reduced by about 1,200 tpy for existing units and 
340 tpy for new units. Emissions of mercury will be reduced by about 
0.7 tpy per year for existing units and by 0.1 tpy for new units. 
Emissions of filterable PM will be reduced by about 6,300 tpy for 
existing units and 1,300 tpy for new units. Emissions of non-mercury 
metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, 
lead, manganese, nickel, and selenium) will be reduced by about 210 tpy 
for existing units and will be reduced by 40 tpy for new units. 
Additionally, EPA has estimated that conducting an annual tune-up could 
potentially reduce emissions of organic HAP as a result of improved 
combustion and reduced fuel use. POM reductions are represented by 7-
PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that 
the energy efficient work and management practices may reduce emissions 
of 7-PAH by 8 tpy for existing units and that the CO emission limit may 
reduce emissions of 7-PAH by 1 tpy for new units. A discussion of the 
methodology used to estimate baseline emissions and emissions 
reductions is presented in ``Estimation of Impacts for Industrial, 
Commercial, and Institutional Boilers Area Source NESHAP'' in the 
docket.

                 Table 2--Summary of HAP Emissions Reductions for Existing and New Sources (tpy)
----------------------------------------------------------------------------------------------------------------
                                                                    Non mercury
            Source                 Subcategory          PM          metals \a\        Mercury         POM \b\
----------------------------------------------------------------------------------------------------------------
Existing Units................  Coal............           5,350              24          0.6               0.2
                                Biomass.........             760              10          0.003             5
                                Oil.............             230             175          0.03              3
New Units.....................  Coal............             510               3          0.09              0.02
                                Biomass.........             690               8          0.0003            0.5
                                Oil.............             100              28          0.005             0.5
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ POM is represented by total emissions of polycyclic aromatic hydrocarbons (7-PAH). It is assumed that
  compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may
  reduce emissions of 7-PAH by an equivalent amount.

[[Page 31914]]

B. What are the cost impacts?

    To estimate the national cost impacts of this proposed rule for 
existing sources, EPA developed several model boilers and determined 
the cost of control for these model boilers. The EPA assigned a model 
boiler to each existing unit based on the fuel, size, and current 
controls. The analysis considered all air pollution control equipment 
currently in operation at existing boilers. Model costs were then 
assigned to all existing units that could not otherwise meet the 
proposed standards. The resulting total national cost impact of this 
proposed rule for existing units is $696 million dollars in total 
annualized costs. The total annualized costs (new and existing) for 
installing controls, conducting biennial tune-ups and an energy 
assessment, and implementing testing and monitoring requirements, is 
$1.0 billion. Table 3 of this preamble shows the total annualized cost 
impacts for each subcategory.

                          Table 3--Summary of Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                    Estimated/         Total
                                                                                     projected      annualized
                    Source                                 Subcategory               number of     cost (10\6\$/
                                                                                  affected units      yr) \a\
----------------------------------------------------------------------------------------------------------------
Existing Units................................  Coal............................           3,710             160
                                                Biomass.........................          10,958              48
                                                Oil.............................         168,003             436
Facility Energy Assessment....................  All.............................  ..............              52
New Units \b\.................................  Coal............................             155              54
                                                Biomass.........................             200              13
                                                Oil.............................           6,424             244
----------------------------------------------------------------------------------------------------------------
\a\ TAC does not include fuel savings from improving combustion efficiency.
\b\ Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013).

    Using DOE projections on fuel expenditures, as well as the history 
of installation dates of area source boilers in the dataset, the number 
of additional boilers that could be potentially constructed was 
estimated. The resulting total national cost impact of this proposed 
rule on new sources by the 3rd year, 2013, is $311 million dollars in 
total annualized costs. When accounting for a 1 percent fuel savings 
resulting from improvements to combustion efficiency, the total 
national cost impact on new sources is $260 million.
    A discussion of the methodology used to estimate cost impacts is 
presented in the memorandum ``Estimation of Impacts for Industrial, 
Commercial, and Institutional Boilers Area Source NESHAP'' in the 
Docket.

C. What are the economic impacts?

    The economic impact analysis (EIA) that is included in the RIA 
shows that the expected prices for industrial sectors could be 0.01 
percent higher and domestic production may fall by less than 0.01 
percent. Because of higher domestic prices imports may rise by less 
than 0.01 percent. Energy prices will not be affected.
    Social costs are estimated to also be $0.5 billion in 2008 dollars. 
This is estimated to made up of a $0.3 billion loss in domestic 
consumer surplus, a $0.3 billion loss in domestic producer surplus, a 
$0.1 billion increase in rest of the world surplus, and a $0.1 billion 
net loss associated with new source costs and fuel savings not modeled 
in a way that can be used to attribute it to consumers and producers.
    EPA performed a screening analysis for impacts on small entities by 
comparing compliance costs to sales/revenues (e.g., sales and revenue 
tests). EPA's analysis found the tests were typically higher than 3 
percent for small entities included in the screening analysis. EPA has 
prepared an Initial Regulatory Flexibility Analysis (IRFA) that 
discusses alternative regulatory or policy options that minimize the 
rule's small entity impacts. It includes key information about key 
results from the Small Business Advocacy Review (SBAR) panel.
    Precise job effect estimates cannot be estimated with certainty. 
Morgenstern et al. (2002) identify three economic mechanisms by which 
pollution abatement activities can indirectly influence jobs:
     Higher production costs raise market prices, higher prices 
reduce consumption, and employment within an industry falls (``demand 
effect'');
     Pollution abatement activities require additional labor 
services to produce the same level of output (``cost effect''); and
     Post regulation production technologies may be more or 
less labor intensive (i.e., more/less labor is required per dollar of 
output) (``factor-shift effect'').
    Several empirical studies, including Morgenstern et al. (2002), 
suggest the net employment decline is zero or economically small (e.g., 
Cole and Elliot, 2007; Berman and Bui, 2001). However, others show the 
question has not been resolved in the literature (Henderson, 1996; 
Greenstone, 2002). Morgenstern's paper uses a six-year panel (U.S. 
Census data for plant-level prices, inputs (including labor), outputs, 
and environmental expenditures) to econometrically estimate the 
production technologies and industry-level demand elasticities. Their 
identification strategy leverages repeat plant-level observations over 
time and uses plant-level and year fixed effects (e.g., plant and time 
dummy variables). After estimating their model, Morgenstern show and 
compute the change in employment associated with an additional $1 
million ($1987) in environmental spending. Their estimates covers four 
manufacturing industries (pulp and paper, plastics, petroleum, and 
steel) and Morgenstern, et al. present results separately for the cost, 
factor shift, and demand effects, as well as the net effect. They also 
estimate and report an industry-wide average parameter that combines 
the four industry-wide estimates and weighting them by each industry's 
share of environmental expenditures.
    EPA has most often estimated employment changes associated with 
plant closures due to environmental regulation or changes in output for 
the regulated industry (EPA, 1999a; EPA, 2000). This analysis goes 
beyond what EPA has typically done in two ways. First, because the 
multimarket model provides estimates for changes in output for sectors 
not directly regulated, we were able to estimate a more comprehensive 
``demand effect.'' Secondly, parameters estimated in the Morgenstern 
paper were used to

[[Page 31915]]

estimate all three effects (``demand,'' ``cost,'' and ``factor 
shift''). This transfer of results from the Morgenstern study is 
uncertain but avoids ignoring the ``cost effect'' and the ``factor-
shift effect.''
    We calculated ``demand effect'' employment changes by assuming that 
the number of jobs changes proportionally with multi-market model's 
simulated output changes. These results were calculated for all sectors 
in the EPA model that show a change in output. The total job losses are 
estimated to be approximately 1,000.
    We also calculated a similar ``demand effect'' estimate that used 
the Morgenstern paper. To do this, we multiplied the point estimate for 
the total demand effect (-3.56 jobs per million ($1987) of 
environmental compliance expenditure) by the total environmental 
compliance expenditures used in the partial equilibrium model. For 
example, the job loss estimate is approximately 1,000 jobs (-3.56 x 
$0.5 billion x 0.60).\2\
---------------------------------------------------------------------------

    \2\ Since Morgenstern's analysis reports environmental 
expenditures in $1987, we make an inflation adjustment to the 
engineering cost analysis using GDP implicit price deflator (64.76/
108.48) = 0.60).
---------------------------------------------------------------------------

    We also present the results of using the Morgenstern paper to 
estimate employment ``cost'' and ``factor-shift'' effects (Table 1). 
Although using the Morgenstern parameters to estimate these ``cost'' 
and ``factor-shift'' employment changes is uncertain, it is helpful to 
compare the potential job gains from these effects to the job losses 
associated with the ``demand'' effect. Table 1 shows that using the 
Morgenstern point estimates of parameters to estimate the ``cost'' and 
``factor shift'' employment gains may be greater than the employment 
losses using either of the two ways of estimating ``demand'' employment 
losses. The 95 percent confidence intervals are shown for all of the 
estimates based on the Morgenstern parameters. As shown, at the 95 
percent confidence level, we cannot be certain if net employment 
changes are positive or negative.
    Although the Morgenstern paper provides additional information 
about the potential job effects of environmental protection programs, 
there are several qualifications EPA considered as part of the 
analysis. First, EPA has used the weighted average parameter estimates 
for a narrow set of manufacturing industries (pulp and paper, plastics, 
petroleum, and steel). Absent other data and estimates, this approach 
seems reasonable and the estimates come from a respected peer-reviewed 
source. However, EPA acknowledges the proposed rule covers a broader 
set of industries not considered in original empirical study. By 
transferring the estimates to other industrial sectors, we make the 
assumption that estimates are similar in size. In addition, EPA assumes 
also that Morgenstern et al.'s estimates derived from the 1979-1991 
still applicable for policy taking place in 2013, almost 20 years 
later. Second, the multi-market model only considers near term 
employment effects in a U.S. economy where production technologies are 
fixed. As a result, the modeling system places more emphasis on the 
short term ``demand effect'' whereas the Morgenstern paper emphasizes 
other important long term responses. For example, positive job gains 
associated with ``factor shift effects'' are more plausible when 
production choices become more flexible over time and industries can 
substitute labor for other production inputs. Third, the Morgenstern 
paper estimates rely on sector demand elasticities that are different 
from the demand elasticity parameters used in the multi-market model. 
As a result, the demand effects are not directly comparable with the 
demand effects estimated by the multi-market model. Fourth, Morgenstern 
identifies the industry average as economically and statistically 
insignificant effect (i.e., the point estimates are small, measured 
imprecisely, and not distinguishable from zero). EPA acknowledges this 
fact and has reported the 95 percent confidence intervals in Table 1. 
Fifth, Morgenstern's methodology assumes large plants bear most of the 
regulatory costs. By transferring the estimates, EPA assumes a similar 
distribution of regulatory costs by plant size and that the regulatory 
burden does not disproportionately fall on smaller plants.

                    Table 4--Employment Changes: 2013
------------------------------------------------------------------------
              Estimation method                        1,000 jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets)   -1.
 (demand effect only).
Literature-based estimate (net effect [A + B   +1 (-1 to +2).
 + C below]).
A. Literature-based estimate: Demand effect..  -1 (-3 to 0).
B. Literature-based estimate: Cost effect....  +1 (0 to +2).
C. Literature-based estimate: Factor shift     +1 (0 to +2).
 effect.
------------------------------------------------------------------------
Note: Totals may not add due to independent rounding. 95 percent
  confidence intervals for literature-based estimates are shown in
  parenthesis.

D. What are the social costs and benefits of this proposed rule?

    We estimated the monetized benefits of this proposed regulatory 
action to be $1.0 billion to $2.4 billion (2008$, 3 percent discount 
rate) in the implementation year (2013). The monetized benefits of this 
proposed regulatory action at a 7 percent discount rate are $910 
million to $2.2 billion (2008$). Using alternate relationships between 
PM2.5 and premature mortality supplied by experts, higher 
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\3\ A summary of the 
monetized benefits estimates at discount rates of 3 percent and 7 
percent is in Table 5 of this preamble.
---------------------------------------------------------------------------

    \3\ Roman et al., 2008. ``Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S.'' Environ. Sci. Technol., 42, 7, 2268--2274.

[[Page 31916]]

      Table 5--Summary of the Monetized Benefits Estimates for the Proposed Boiler Area Source Rule in 2013
                                             [Billions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                             Estimated
                                             emission
                                            reductions     Total monetized benefits    Total monetized benefits
                                             (tons per        (3% discount rate)          (7% discount rate)
                                               year)
----------------------------------------------------------------------------------------------------------------
PM2.5...................................           2,682  $0.96 to $2.4.............  $0.88 to $2.1.
PM2.5 Precursors........................  ..............  ..........................  ..........................
SO2.....................................           1,539  $0.31 to $0.76............  $0.28 to $0.68.
VOC.....................................           1,179  $0.01 to $0.04............  $0.01 to $0.03.
    Total...............................  ..............  $1.0 to $2.4..............  $0.91 to $2.2.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers
  may not sum across rows. All fine particles are assumed to have equivalent health effects, but the benefit-per-
  ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form
  PM2.5. Benefits from reducing hazardous air pollutants (HAPs), ecosystem effects, and visibility impairment
  are not included.

    These benefits estimates represent the total monetized human health 
benefits for populations exposed to less PM2.5 in 2013 from 
controls installed to reduce air pollutants in order to meet these 
standards. These estimates are calculated as the sum of the monetized 
value of avoided premature mortality and morbidity associated with 
reducing a ton of PM2.5 and PM2.5 precursor 
emissions. To estimate human health benefits derived from reducing 
PM2.5 and PM2.5 precursor emissions, we utilized 
the general approach and methodology laid out in Fann et al. (2009).\4\
---------------------------------------------------------------------------

    \4\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The influence 
of location, source, and emission type in estimates of the human 
health benefits of reducing a ton of air pollution.'' Air Qual Atmos 
Health (2009) 2:169-176.
---------------------------------------------------------------------------

    To generate the benefit-per-ton estimates, we used a model to 
convert emissions of direct PM2.5 and PM2.5 
precursors into changes in ambient PM2.5 levels and another 
model to estimate the changes in human health associated with that 
change in air quality. Finally, the monetized health benefits were 
divided by the emission reductions to create the benefit-per-ton 
estimates. Even though we assume that all fine particles have 
equivalent health effects, the benefit-per-ton estimates vary between 
precursors because each ton of precursor reduced has a different 
propensity to form PM2.5. For example, SOX has a 
lower benefit-per-ton estimate than direct PM2.5 because it 
does not form as much PM2.5, thus the exposure would be 
lower, and the monetized health benefits would be lower.
    For context, it is important to note that the magnitude of the PM 
benefits is largely driven by the concentration response function for 
premature mortality. Experts have advised EPA to consider a variety of 
assumptions, including estimates based both on empirical 
(epidemiological) studies and judgments elicited from scientific 
experts, to characterize the uncertainty in the relationship between 
PM2.5 concentrations and premature mortality. For this 
proposed rule we cite two key empirical studies, one based on the 
American Cancer Society cohort study \5\ and the extended Six Cities 
cohort study.\6\ In the RIA for this proposed rule, which is available 
in the docket, we also include benefits estimates derived from expert 
judgments and other assumptions.
---------------------------------------------------------------------------

    \5\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary Mortality, 
and Long-term Exposure to Fine Particulate Air Pollution.'' Journal 
of the American Medical Association 287:1132-1141.
    \6\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    This analysis does not include the type of detailed uncertainty 
assessment found in the 2006 PM2.5 NAAQS RIA because we lack 
the necessary air quality input and monitoring data to run the benefits 
model. However, the 2006 PM2.5 NAAQS benefits analysis \7\ 
provides an indication of the sensitivity of our results to various 
assumptions.
---------------------------------------------------------------------------

    \7\ U.S. Environmental Protection Agency, 2006. Final Regulatory 
Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air 
and Radiation. October. Available on the Internet at http://
www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    It should be emphasized that the monetized benefits estimates 
provided above do not include benefits from several important benefit 
categories, including reducing other air pollutants, ecosystem effects, 
and visibility impairment. The benefits from reducing carbon monoxide 
and hazardous air pollutants have not been monetized in this analysis, 
including reducing 39,000 tons of carbon monoxide, 0.75 ton of mercury, 
and 130 tons of HCl, 5 tons of HF, and 460 grams of dioxins/furans each 
year. Although we do not have sufficient information or modeling 
available to provide monetized estimates for this rulemaking, we 
include a qualitative assessment of the health effects of these air 
pollutants in the Regulatory Impact Analysis (RIA) for this proposed 
rule, which is available in the docket.
    The social costs of this proposed rulemaking are estimated to be 
$0.5 billion (2008$) in the implementation year, and the monetized 
benefits are $1.0 billion to $2.4 billion (2008$, 3 percent discount 
rate) for that same year. The benefits at a 7 percent discount rate are 
$910 million to $2.2 billion (2008$). Thus, net benefits of this 
rulemaking are estimated at $500 million to $1.9 billion (2008$, 3 
percent discount rate) and $400 million to $1.7 billion (2008$, 7 
percent discount rate).
    A summary of the monetized benefits, social costs, and net benefits 
at discount rates of 3 percent and 7 percent is in Table 6 of this 
preamble.

[[Page 31917]]

    Table 6--Summary of the Monetized Benefits, Social Costs, and Net
            Benefits for the Boiler Area Source Rule in 2013
                         [Billions of 2008$] \1\
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
                             Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $1.0 to $2.4......  $0.91 to $2.2.
Total Social Costs \3\..........  $0.50.............  $0.5.
Net Benefits....................  $0.5 to $1.9......  $0.4 to $1.7.
                                 ---------------------------------------
Non-monetized Benefits..........  39,000 tons of carbon monoxide.
                                  130 tons of HCl.
                                  5 tons of HF.
                                  0.75 tons of mercury.
                                  250 tons of other metals.
                                  470 grams of dioxins/furans.
                                  Health effects from NO2 and SO2
                                   exposure.
                                  Ecosystem effects.
                                  Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
  rounded to two significant figures.
\2\ The total monetized benefits reflect the human health benefits
  associated with reducing exposure to PM2.5 through reductions of
  directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is
  important to note that the monetized benefits include many but not all
  health effects associated with PM2.5 exposure.
\3\ The methodology used to estimate social costs for one year in the
  multimarket model using surplus changes results in the same social
  costs for both discount rates.

    For more information on the benefits analysis, please refer to the 
RIA for this rulemaking, which is available in the docket.

E. What are the water and solid waste impacts?

    The EPA estimated that no additional water usage would result from 
the MACT floor level of control or GACT requirement. The fabric filter, 
multiclone or combustion control devices used to meet the standards of 
this proposed rule do not require any water to operate, nor do they 
generate any wastewater.
    The EPA estimated the additional solid waste that would result from 
this proposed rule to be 14,300 tpy for existing sources due to the 
dust and flyash captured by mercury and PM control devices. The cost of 
handling the additional solid waste generated from existing sources is 
$602,000 per year. For new sources installed by 2013, the EPA estimated 
the additional solid waste that would result from this proposed rule to 
be 1,800 tpy for new sources due to the dust and flyash captured by 
mercury and PM control devices. The cost of handling the additional 
solid waste generated from existing sources is $75,900 per year. These 
costs are also accounted for in the control costs estimates.
    A discussion of the methodology used to estimate impacts is 
presented in ``Estimation of Impacts for Industrial, Commercial, and 
Institutional Boilers Area Source NESHAP'' in the Docket.

F. What are the energy impacts?

    The EPA expects an increase of approximately 206 million kilowatt 
hours (kWh) in national annual energy usage from existing sources as a 
result of this proposed rule. The increase results from the electricity 
required to operate control devices installed to meet this proposed 
rule, such as fabric filters. Additionally, for new sources installed 
by 2013, EPA expects an increase of approximately 22 million kWh in 
national annual energy usage in order to operate the control devices.
    The Department of Energy has conducted energy assessments at 
selected manufacturing facilities and reports that facilities can 
reduce fuel/energy use by 10 to 15 percent by using best practices to 
increase their energy efficiency. Additionally, the EPA expects work 
practice standards such as boilers tune-ups and combustion controls 
such as new replacement burners and will improve the efficiency of 
boilers. The EPA estimates existing area source facilities can save 20 
trillion BTU of fuel each year. For new sources online by 2013, the EPA 
estimates 2.3 trillion BTU per year of fuel can be conserved. This fuel 
savings estimates includes only those fuel savings resulting from 
liquid and coal fuels and it is based on the assumption that the work 
practice standards will achieve 1 percent improvement in efficiency.

VII. Relationship of This Proposed Action to CAA Section 112(c)(6)

    CAA section 112(c)(6) requires EPA to identify categories of 
sources of seven specified pollutants to assure that sources accounting 
for not less than 90 percent of the aggregate emissions of each such 
pollutant are subject to standards under CAA Section 112(d)(2) or 
112(d)(4). EPA has identified ``Industrial Coal Combustion,'' 
``Industrial Oil Combustion,'' Industrial Wood/Wood Residue 
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
categories that emits two of the seven CAA Section 112(c)(6) 
pollutants: POM and mercury. (The POM emitted is composed of 16 
polyaromatic hydrocarbons (PAH) and extractable organic matter (EOM).) 
In the Federal Register notice Source Category Listing for Section 
112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 
17838, 17849, Table 2 (1998), EPA identified ``Industrial Coal 
Combustion,'' ``Industrial Oil Combustion,'' ``Industrial Wood/Wood 
Residue Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
category ``subject to regulation'' for purposes of CAA Section 
112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that 
these units emit.
    Specifically, as byproducts of combustion, the formation of POM is 
effectively reduced by the combustion and post-combustion practices 
required to comply with the CAA Section 112 standards. Any POM that do 
form during combustion are further

[[Page 31918]]

controlled by the various post-combustion controls. The add-on PM 
control systems (fabric filter) used to reduce mercury and/or PM 
emissions further reduce emissions of these organic pollutants, as is 
evidenced by performance data. Specifically, the emission tests 
obtained at currently operating major source boilers show that the 
proposed MACT regulations for area source boilers will reduce Hg 
emissions by about 86 percent. It is, therefore, reasonable to conclude 
that POM emissions will be substantially controlled. Thus, while this 
proposed rule does not identify specific numerical emission limits for 
POM, emissions of POM are, for the reasons noted below, nonetheless 
``subject to regulation'' for purposes of CAA section 112(c)(6).
    In lieu of establishing numerical emissions limits for pollutants 
such as POM, we regulate surrogate substances. While we have not 
identified specific numerical limits for POM, we believe CO serves as 
an effective surrogate for this HAP, because CO, like POM, is formed as 
a product of incomplete combustion.
    Consequently, we have concluded that the emissions limits for CO 
function as a surrogate for control of POM, such that it is not 
necessary to propose numerical emissions limits for POM with respect to 
boilers to satisfy CAA Section 112(c)(6).
    To further address POM and mercury emissions, this proposed rule 
also includes an energy assessment provision that encourages 
modifications to the facility to reduce energy demand that lead to 
these emissions.

VIII. Statutory and Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is an ``economically significant regulatory action'' because it 
is likely to have an annual effect on the economy of $100 million or 
more or adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities.
    Accordingly, EPA submitted this action to OMB for review under EO 
12866 and any changes in response to OMB recommendations have been 
documented in the docket for this action. For more information on the 
costs and benefits for this rule, please refer to Table 5 of this 
preamble.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to OMB under the Paperwork Reduction Act, 
44 U.S.C. 3501 et seq. The Information Collection Request (ICR) 
document prepared by EPA has been assigned EPA ICR number 2253.01.
    The recordkeeping and reporting requirements in this proposed rule 
would be based on the information collection requirements in EPA's 
NESHAP General Provisions (40 CFR part 63, subpart A). The 
recordkeeping and reporting requirements in the General Provisions are 
mandatory pursuant to section 114 of the CAA (42 U.S.C. 7414). All 
information other than emissions data submitted to EPA pursuant to the 
information collection requirements for which a claim of 
confidentiality is made is safeguarded according to CAA section 114(c) 
and EPA's implementing regulations at 40 CFR part 2, subpart B.
    This proposed NESHAP would require applicable one-time 
notifications according to the NESHAP General Provisions. Facility 
owners or operators would be required to include compliance 
certifications for the work practices and management practices in their 
Notifications of Compliance Status. Recordkeeping would be required to 
demonstrate compliance with emission limits, work practices, management 
practices, monitoring, and applicability provisions. New affected 
facilities would be required to comply with the requirements for 
startup, shutdown, and malfunction plans/reports and to submit a 
compliance report if a deviation occurred during the semiannual 
reporting period.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the standards) is estimated to be $523 million. This includes 3.6 
million labor hours per year at a cost of $336 million and total non-
labor capital costs of $186 million per year. This estimate includes 
initial and annual performance tests, conducting and documenting an 
energy assessment, conducting and documenting a tune-up, semiannual 
excess emission reports, maintenance inspections, developing a 
monitoring plan, notifications, and recordkeeping. Monitoring, testing, 
tune-up and energy assessment costs were also included in the cost 
estimates presented in the control costs impacts estimates in section 
VI.B of this preamble. The total burden for the Federal government 
(averaged over the first 3 years after the effective date of the 
standard) is estimated to be 767,403 hours per year at a total labor 
cost of $37.6 million per year.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless the collection 
displays a currently valid OMB control number. The OMB control numbers 
for EPA's regulations in 40 CFR part 63 are listed in 40 CFR part 9.
    To comment on EPA's need for this information, the accuracy of the 
provided burden estimates, and any suggested methods for minimizing 
respondent burden, including the use of automated collection 
techniques, EPA has established a public docket for this action, which 
includes this ICR, under Docket ID number EPA-HQ-OAR-2006-0790. Submit 
any comments related to the ICR to EPA and OMB. See ADDRESSES section 
at the beginning of this preamble for where to submit comments to EPA. 
Send comments to OMB at the Office of Information and Regulatory 
Affairs, Office of Management and Budget, 725 17th Street, NW., 
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is 
required to make a decision concerning the ICR between 30 and 60 days 
after June 4, 2010, a comment to OMB is best assured of having its full 
effect if OMB receives it by July 6, 2010. The final rule will respond 
to any OMB or public comments on the information collection 
requirements contained in this proposal.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a

[[Page 31919]]

significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business 
according to Small Business Administration (SBA) size standards by the 
North American Industry Classification System category of the owning 
entity. The range of small business size standards for the 40 affected 
industries ranges from 500 to 1,000 employees, except for petroleum 
refining and electric utilities. In these latter two industries, the 
size standard is 1,500 employees and a mass throughput of 75,000 
barrels/day or less, and 4 million kilowatt-hours of production or 
less, respectively; (2) a small governmental jurisdiction that is a 
government of a city, county, town, school district or special district 
with a population of less than 50,000; and (3) a small organization 
that is any not-for-profit enterprise which is independently owned and 
operated and is not dominant in its field.
    Because an initial screening analysis for impact on small entities 
indicated a likely significant impact for substantial numbers EPA 
convened a SBAR Panel to obtain advice and recommendation of 
representatives of the small entities that potentially would be subject 
to the requirements of this rule.
(1) Panel Process and Panel Outreach
    As required by section 609(b) of the RFA, as amended by SBREFA, EPA 
also has conducted outreach to small entities and. On January 22, 2009 
EPA's Small Business Advocacy Chairperson convened a Panel under 
section 609(b) of the RFA. In addition to the Chair, the Panel 
consisted of the Director of the Sector Policies and Programs Division 
within EPA's Office of Air and Radiation, the Chief Counsel for 
Advocacy of the Small Business Administration, and the Administrator of 
the Office of Information and Regulatory Affairs within the Office of 
Management and Budget.
    As part of the SBAR Panel process we conducted outreach with 
representatives from 14 various small entities that would be affected 
by this rule. The small entity representatives (SERs) included 
associations representing schools, churches, hotels/motels, wood 
product facilities and manufacturers of home furnishings. We met with 
these SERs to discuss the potential rulemaking approaches and potential 
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials 
included background on the rulemaking, possible regulatory approaches, 
preliminary cost and economic impacts, and possible rulemaking 
alternatives. The Panel met with SERs from the industries that will be 
impacted directly by this rule on February 10, 2009 to discuss the 
outreach materials and receive feedback on the approaches and 
alternatives detailed in the outreach packet. (EPA also met with SERs 
on November 13, 2008 for an initial outreach meeting.) The Panel 
received written comments from the SERs following the meeting in 
response to discussions at the meeting and the questions posed to the 
SERs by the Agency. The SERs were specifically asked to provide comment 
on regulatory alternatives that could help to minimize the rule's 
impact on small businesses.
(2) Panel Recommendations for Small Business Flexibilities
    The Panel recommended that EPA consider and seek comment on a wide 
range of regulatory alternatives to mitigate the impacts of the 
rulemaking on small businesses, including those flexibility options 
described below. The following section summarizes the SBAR Panel 
recommendations. EPA has proposed provisions consistent with each of 
the Panel's recommendations regarding area source facilities.
    Consistent with the RFA/SBREFA requirements, the Panel evaluated 
the assembled materials and small-entity comments on issues related to 
elements of the IRFA. A copy of the Final Panel Report (including all 
comments received from SERs in response to the Panel's outreach meeting 
as well as summaries of both outreach meetings that were held with the 
SERs is included in the docket for this proposed rule. A summary of the 
Panel recommendations is detailed below. As noted above, this proposal 
includes proposed provisions for each of the Panel recommendations 
regarding area source facilities.
(a) Work Practice Standards
    The panel recommended that EPA consider requiring annual tune-ups, 
including standardized criteria outlining proper tune-up methods 
targeted at smaller boiler operators. The panel further recommended 
that EPA take comment on the efficacy of energy assessments/audits at 
improving combustion efficiency and the cost of performing the 
assessments, especially to smaller boiler operators.
    A work practice standard, instead of MACT emission limits, may be 
proposed if it can be justified under CAA section 112(h), that is, it 
is impracticable to enforce the emission standards due to technical and 
economic limitations. Work practice standards could reduce fuel use and 
improve combustion efficiency which would result in reduced emissions.
    In general, SERs commented that a regulatory approach to improve 
combustion efficiency, such as work practice standards, would have 
positive impacts with respect to the environment and energy use and 
save on compliance costs. The SERs were concerned with work practice 
standards that would require energy assessments and implementation of 
assessment findings. The basis of these concerns rested upon the 
uncertainty that there is no guarantee that there are available funds 
to implement a particular assessment's findings.
(b) Subcategorization
    The Panel recommended that EPA allow subcategorizations suggested 
by the SERs, unless EPA finds that a subcategorization is inconsistent 
with the Clean Air Act.
    SERs commented that subcategorization is a key concept that could 
ensure that like boilers are compared with similar boilers so that MACT 
floors are more reasonable and could be achieved by all units within a 
subcategory using appropriate emission reduction strategies. SERs 
commented that EPA should subcategorize based on fuel type, boiler 
type, duty cycle, and location.
(c) Compliance Costs
    The Panel recommended that EPA carefully weigh the potential burden 
of compliance requirements and consider for small entities options such 
as, emission averaging within facility, reduced monitoring/testing 
requirements, or allowing more time for compliance.
    SERs noted that recordkeeping activities, as written in the vacated 
boiler MACT, would be especially challenging for small entities that do 
not have a dedicated environmental affairs department.

D. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, we 
generally must prepare a written statement, including a cost-benefit

[[Page 31920]]

analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
1 year. Before promulgating a rule for which a written statement is 
needed, section 205 of the UMRA generally requires us to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows us to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, we must develop a small 
government agency plan under section 203 of the UMRA. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    We have determined that this proposed rule contains a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and Tribal governments, in the aggregate, or the private 
sector in any 1 year. Accordingly, we have prepared a written statement 
entitled ``Unfunded Mandates Reform Act Analysis for the Proposed 
Industrial Boilers and Process Heaters NESHAP'' under section 202 of 
the UMRA which is summarized below.
1. Statutory Authority
    As discussed in section I of this preamble, the statutory authority 
for this proposed rulemaking is section 112 of the CAA. Title III of 
the CAA Amendments was enacted to reduce nationwide air toxic 
emissions. Section 112(b) of the CAA lists the 188 chemicals, 
compounds, or groups of chemicals deemed by Congress to be HAP. These 
toxic air pollutants are to be regulated by NESHAP.
    Section 112(d) of the CAA requires us to establish NESHAP for both 
major and area sources of HAP that are listed for regulation under CAA 
section 112(c). CAA section 112(k)(3)(B) calls for EPA to identify at 
least 30 HAP which, as the result of emissions from area sources, pose 
the greatest threat to public health in the largest number of urban 
areas. CAA section 112(c)(3) requires EPA to list sufficient categories 
or subcategories of area sources to ensure that area sources 
representing 90 percent of the emissions of the 30 urban HAP are 
subject to regulation.
    Under CAA section 112(d)(5), we may elect to promulgate standards 
or requirements for area sources based on GACT used by those sources to 
reduce emissions of HAP. Determining what constitutes GACT involves 
considering the control technologies and management practices that are 
generally available to the area sources in the source category. We also 
consider the standards applicable to major sources in the analogous 
source category and, as appropriate, the control technologies and 
management practices at area and major sources in similar categories, 
to determine if the standards, technologies, and/or practices are 
transferable and generally available to area sources. In determining 
GACT for a particular area source category, we consider the costs and 
economic impacts of available control technologies and management 
practices on that category.
    While GACT may be a basis for standards for most types of HAP 
emitted from area source, CAA section 112(c)(6) requires that source 
categories accounting for emissions of the HAP listed in CAA section 
112(c)(6) be subject to standards under CAA section 112(d)(2) for the 
listed pollutants. Thus, CAA section 112(c)(6) requires that emissions 
of each listed HAP for the listed categories be subject to MACT 
regulation. The CAA section 112(c)(6) list of source categories 
includes industrial boilers and institutional/commercial boilers. 
Within these two source categories, coal combustion, oil combustion, 
and wood combustion have been on the CAA section 112(c)(6) list because 
of emissions of mercury and POM. We currently believe that regulation 
of coal-fired boilers will ensure that we fulfill our obligation under 
CAA section 112(c)(6) with respect to mercury reductions. Consequently, 
we deem it reasonable to propose to regulate the coal-fired boilers 
under MACT, rather than the biomass and oil-fired boilers, to obtain 
additional mercury reductions towards achieving the CAA section 
112(c)(6) obligation. We propose to regulate biomass-fired and oil-
fired boilers under GACT.
    This proposed NESHAP would apply to all existing and new industrial 
boilers, institutional boilers, and commercial boilers located at area 
sources. In compliance with section 205(a) of the UMRA, we identified 
and considered a reasonable number of regulatory alternatives. 
Additional information on the costs and environmental impacts of these 
regulatory alternatives is presented in the docket.
    The regulatory alternative upon which the proposed standards are 
based represents the MACT floor for the listed CAA section 112(c)(6) 
pollutants (mercury and POM) and GACT for the other urban HAP which 
formed the basis for the listing of these two area source categories. 
The proposed standards would require new coal-fired boilers to meet 
MACT-based emission limits for mercury and CO (as a surrogate for POM) 
and GACT-based emission limits for PM (as a surrogate for urban 
metals). New biomass and oil-fired boilers would be required to meet 
MACT-based CO emission limits and GACT-based emission limits for PM. 
The emission limits for existing area source boilers are only 
applicable to area source boilers that have a designed heat input 
capacity of 10 MMBtu/h or greater. Existing large coal-fired boilers 
would be required to meet MACT-based emission limits for mercury and 
CO, and existing large biomass and oil-fired boilers would be subject 
to MACT-based CO emission limits. As allowed under CAA section 112(h), 
a work practice standard requiring the implementation of a tune-up 
program is being proposed for existing area source boilers with a 
designed heat input capacity of less than 10 MMBtu/h. An additional 
``beyond-the-floor'' standard is being proposed for existing area 
source facilities having an affected boiler with a heat input capacity 
of 10 MMBtu/h or greater that requires the performance of an energy 
assessment on the boiler and the facility to identify cost-effective 
energy conservation measures.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for the proposed rule 
including the Agency's assessment of costs and benefits, is detailed in 
the ``Regulatory Impact Analysis for the Proposed Industrial Boilers 
and Process Heaters MACT'' in the docket. Based on estimated compliance 
costs associated with the proposed rule and the predicted change in 
prices and production in the affected industries, the estimated social 
costs of the proposed rule are $0.5 billion (2008 dollars).
    It is estimated that 3 years after implementation of the proposed 
rule, HAP would be reduced by hundreds of

[[Page 31921]]

tons, including reductions in metallic HAP including mercury, 
hydrochloric acid, hydrogen fluoride, and several other organic HAP 
from area source boilers. Studies have determined a relationship 
between exposure to these HAP and the onset of cancer, however, the 
Agency is unable to provide a monetized estimate of the HAP benefits at 
this time. In addition, there are reductions in PM2.5 and in 
SO2 that would occur, including 2,700 tons of 
PM2.5 and 1,500 tons of SO2. These reductions 
occur within 3 years after the implementation of the proposed 
regulation and are expected to continue throughout the life of the 
affected sources. The major health effect associated with reducing 
PM2.5 and PM2.5 precursors (such as 
SO2) is a reduction in premature mortality. Other health 
effects associated with PM2.5 emission reductions include 
avoiding cases of chronic bronchitis, heart attacks, asthma attacks, 
and work-lost days (i.e., days when employees are unable to work). 
While we are unable to monetize the benefits associated with the HAP 
emissions reductions, we are able to monetize the benefits associated 
with the PM2.5 and SO2 emissions reductions. For 
SO2 and PM2.5, we estimated the benefits 
associated with health effects of PM but were unable to quantify all 
categories of benefits (particularly those associated with ecosystem 
and visibility effects). Our estimates of the monetized benefits in 
2013 associated with the implementation of the proposed alternative 
range from $1.0 billion (2008 dollars) to $2.4 billion (2008 dollars) 
when using a 3 percent discount rate (or from $0.9 billion (2008 
dollars) to $2.2 billion (2008 dollars) when using a 7 percent discount 
rate. The general approach used to value benefits is discussed in more 
detail earlier in this preamble. For more detailed information on the 
benefits estimated for the proposed rulemaking, refer to the RIA in the 
docket.
3. Future and Disproportionate Costs
    The Unfunded Mandates Reform Act requires that we estimate, where 
accurate estimation is reasonably feasible, future compliance costs 
imposed by the proposed rule and any disproportionate budgetary 
effects. Our estimates of the future compliance costs of the proposed 
rule are discussed previously in this preamble.
    We do not believe that there will be any disproportionate budgetary 
effects of the proposed rule on any particular areas of the country, 
State or local governments, types of communities (e.g., urban, rural), 
or particular industry segments. See the results of the ``Economic 
Impact Analysis of the Proposed Industrial Boilers and Process Heaters 
NESHAP,'' the results of which are discussed previously in this 
preamble.
4. Effects on the National Economy
    The Unfunded Mandates Reform Act requires that we estimate the 
effect of the proposed rule on the national economy. To the extent 
feasible, we must estimate the effect on productivity, economic growth, 
full employment, creation of productive jobs, and international 
competitiveness of the U.S. goods and services, if we determine that 
accurate estimates are reasonably feasible and that such effect is 
relevant and material.
    The nationwide economic impact of the proposed rule is presented in 
the ``Economic Impact Analysis for the Industrial Boilers and Process 
Heaters MACT'' in the docket. This analysis provides estimates of the 
effect of the proposed rule on some of the categories mentioned above. 
The results of the economic impact analysis are summarized previously 
in this preamble. The results show that there will be a small impact on 
prices and output (less than 0.01 percent). In addition, there should 
be little impact on energy markets (in this case, coal, natural gas, 
petroleum products, and electricity). Hence, the potential impacts on 
the categories mentioned above should be small.
5. Consultation With Government Officials
    The Unfunded Mandates Reform Act requires that we describe the 
extent of the Agency's prior consultation with affected State, local, 
and tribal officials, summarize the officials' comments or concerns, 
and summarize our response to those comments or concerns. In addition, 
section 203 of the UMRA requires that we develop a plan for informing 
and advising small governments that may be significantly or uniquely 
impacted by a proposal. Consistent with the intergovernmental 
consultation provisions of section 204 of the UMRA, EPA has initiated 
consultations with governmental entities affected by this proposed 
rule. EPA invited the following 10 national organizations representing 
State and local elected officials to a meeting held on March 24, 2010 
in Washington DC: (1) National Governors Association; (2) National 
Conference of State Legislatures, (3) Council of State Governments, (4) 
National League of Cities, (5) U.S. Conference of Mayors, (6) National 
Association of Counties, (7) International City/County Management 
Association, (8) National Association of Towns and Townships, (9) 
County Executives of America, and (10) Environmental Council of States. 
These 10 organizations of elected State and local officials have been 
identified by EPA as the ``Big 10'' organizations appropriate to 
contact for purpose of consultation with elected officials. The 
purposes of the consultation were to provide general background on the 
proposal, answer questions, and solicit input from State/local 
governments. During the meeting, officials expressed uncertainty with 
regard to how boilers owned/operated by State and local entities would 
be impacted, as well as with regard to the potential burden associated 
with implementing the rule on State and local entities. To that end, 
officials requested and EPA provided (1) model boiler costs, (2) 
inventory of area source boilers (coal, oil, biomass only) for the 13 
States for which we have an inventory, and (3) information on potential 
size of boilers used for various facility types and sizes. EPA has not 
received additional questions or requests from State or local 
officials.
    Consistent with section 205, EPA has identified and considered a 
reasonable number of regulatory alternatives. Because an initial 
screening analysis for impact on small entities indicated a likely 
significant impact for substantial numbers EPA convened a SBAR Panel to 
obtain advice and recommendation of representatives of the small 
entities that potentially would be subject to the requirements of the 
rule. As part of that process, EPA considered several options. Those 
options included establishing emission limits, establishing work 
practice standards, and establishing work practice standards and 
requiring an energy assessment. The regulatory alternative selected is 
a combination of the options considered and includes proposed 
provisions regarding each of the SBAR Panel's recommendations for area 
source boilers. The recommendations regard subcategorization, work 
practice standards, and compliance costs (see section VIII.C. of this 
preamble for more detail).
    EPA determined subcategorization based on boiler type to be 
appropriate because different types of units have different emission 
characteristics which may affect the feasibility and effectiveness of 
emission control. Thus, the proposal identifies three subcategories of 
area source boilers: (1) Boilers designed for coal firing, (2) boilers 
designed for biomass firing, and (3) boilers designed for oil firing.

[[Page 31922]]

    The regulatory alternative upon which the proposed standards are 
based represents the MACT floor for mercury for coal-fired boilers, the 
MACT floor for POM (CO is used as a surrogate for POM) for coal, 
biomass, and oil-fired boilers, and GACT for the other urban HAP (PM is 
used as a surrogate for urban HAP metals and CO is used as a surrogate 
for urban organic pollutants) for coal, biomass, and oil-fired boilers. 
The emission limits for existing area source boilers are only 
applicable to area source boilers that have a designed heat input 
capacity of 10 MMBtu/h or greater. A work practice standard (for 
mercury from coal-fired boilers and for POM from all boilers) or 
management practice (for all other HAP, including mercury from biomass-
fired and oil-fired boilers) requiring the implementation of a tune-up 
program is being proposed for existing area source boilers with a 
designed heat input capacity of less than 10 MMBtu/h. An additional 
``beyond-the-floor'' standard is being proposed for existing area 
source facilities having an affected boiler with a heat input capacity 
of 10 MMBtu/h or greater that requires the performance of an energy 
assessment on the boiler and the facility to identify cost-effective 
energy conservation measures.
    The proposed use of surrogate pollutants would result in reduced 
compliance costs because testing would only be required for the 
surrogate pollutants (i.e., CO and PM) versus for the HAP (i.e., POM 
and metals). The proposed work practice standard/management practice 
also would result in reduced compliance costs with respect to 
monitoring/testing for the smaller existing area source boilers. EPA's 
proposed exemption of most area source facilities from title V permit 
requirements also would reduce burden on area source boiler facilities.
    This proposed rule is not subject to the requirements of section 
203 of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. While some small 
governments may have boilers that would be affected by the proposed 
rule, EPA's analysis shows that other public facilities that are 
located at area source facilities owned by small entities would have 
cost-to-revenue ratios exceeding 10 percent. Hospitals' and schools' 
revenue tests fall below 1 percent. Because the proposed rule's 
requirements apply equally to boilers owned and/or operated by 
governments and to boilers owned and/or operated by private entities, 
there would be no requirements that uniquely apply to such governments 
or impose any disproportionate impacts on them.

E. Executive Order 13132: Federalism

    Under Executive Order 13132, EPA may not issue an action that has 
federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the Federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by State and local governments, or EPA consults with 
State and local officials early in the process of developing the 
proposed action.
    EPA has concluded that this action may have federalism 
implications, because it may impose substantial direct compliance costs 
on State or local governments, and the Federal government will not 
provide the funds necessary to pay those costs. Accordingly, EPA 
provides the following federalism summary impact statement as required 
by section 6(b) of Executive Order 13132.
    Based on the estimates in EPA's RIA for today's action, the 
proposed regulatory option, if promulgated, may have federalism 
implications because the option may impose approximately $416 million 
in annual direct compliance costs on an estimated 57,000 State or local 
governments. Boiler inventories for the health services, educational 
services, and government-owned buildings sectors from 13 States were 
used to estimate the nationwide number of potentially impacted State or 
local governments. Because the inventories for these sectors include 
privately owned and Federal government owned facilities, the estimate 
may include many facilities that are not State or local government 
owned. Table 7 of this preamble presents estimates of the number of 
potentially impacted State and local governments and their potential 
annual compliance costs for each of the three sectors. In addition to 
an estimate of the total number of potentially impacted facilities, 
estimates for facilities with small boilers and for facilities with 
large boilers are presented. Small boilers (boilers with heat input 
capacity of less than 10 MMBtu/h) would be subject to a work practice 
standard that requires a boiler tune-up every 2 years. Large coal-fired 
boilers (boilers with heat input capacity of 10 MMBtu/h or greater) 
would be subject to emission limits for mercury and CO, while large 
biomass and oil-fired boilers would be subject to emission limits for 
CO. All facilities with large boilers would be required to conduct a 
one-time energy assessment.

 Table 7--State and Local Governments Potentially Impacted by the Proposed Standards for Boilers at Area Source
                                                   Facilities
----------------------------------------------------------------------------------------------------------------
                                                Number of potentially impacted
                                                          facilities                 Annual compliance costs to
                  Sector                   ---------------------------------------         meet standards
                                               Total        Small        Large
----------------------------------------------------------------------------------------------------------------
Health Services...........................       17,206       15,293        1,913  $143 million.
Educational Services......................       34,052       33,303          749  $200 million.
Government-Owned Buildings................        5,796        5,098          698  $73 million.
                                           ---------------------------------------------------------------------
    Total.................................       57,054       53,694        3,360  $416 million.
----------------------------------------------------------------------------------------------------------------

    EPA consulted with State and local officials in the process of 
developing the proposed action to permit them to have meaningful and 
timely input into its development. EPA met with 10 national 
organizations representing State and local elected officials to provide 
general background on the proposal, answer questions, and solicit input 
from State/local governments. The UMRA discussion in this preamble 
includes a description of the consultation.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed action 
from State and local officials.

F. Executive Order 13175: Consultation and Coordination with Indian 
Tribal Governments

    Executive Order 13175 (65 FR 67249, November 9, 2000), requires EPA 
to develop an accountable process to

[[Page 31923]]

ensure ``meaningful and timely input by tribal officials in the 
development of regulatory policies that have tribal implications.'' The 
proposed rule does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in Executive Order 13175. 
The proposed rule imposes requirements on owners and operators of 
specified area sources and not tribal governments. We do not know of 
any industrial, commercial, or institutional boilers owned or operated 
by Indian tribal governments. However, if there are any, the effect of 
the proposed rule on communities of tribal governments would not be 
unique or disproportionate to the effect on other communities. Thus, 
Executive Order 13175 does not apply to the proposed rule. EPA 
specifically solicits additional comment on the proposed rule from 
tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any 
rule that: (1) Is determined to be ``economically significant'' as 
defined under Executive Order 12866, and (2) concerns an environmental 
health or safety risk that EPA has reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health or 
safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency.
    The proposed rule is not subject to Executive Order 13045 because 
the Agency does not believe the environmental health risks or safety 
risks addressed by this action present a disproportionate risk to 
children. The reason for this determination is that the proposed rule 
is based solely on technology performance.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to the 
proposed rule.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Executive Order 13211, (66 FR 28355, May 22, 2001), provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Information and Regulatory Affairs, OMB, a Statement of Energy Effects 
for certain actions identified as significant energy actions. Section 
4(b) of Executive Order 13211 defines ``significant energy actions'' as 
``any action by an agency (normally published in the Federal Register) 
that promulgates or is expected to lead to the promulgation of a final 
rule or regulation, including notices of inquiry, advance notices of 
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is 
a significant regulatory action under Executive Order 12866 or any 
successor order, and (ii) is likely to have a significant adverse 
effect on the supply, distribution, or use of energy; or (2) that is 
designated by the Administrator of the Office of Information and 
Regulatory Affairs as a significant energy action.'' The proposed rule 
is not a ``significant regulatory action'' because it is not likely to 
have a significant adverse effect on the supply, distribution, or use 
of energy. The basis for the determination is as follows.
    We estimate no significant changes for the energy sector for price, 
production, or imports. For more information on the estimated energy 
effects, please refer to the economic impact analysis for the proposed 
rule. The analysis is available in the public docket.
    Therefore, we conclude that the proposed rule when implemented is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272 
note) directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities, unless to do so would be inconsistent with 
applicable law or otherwise impractical. The VCS are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
VCS bodies. The NTTAA directs EPA to provide Congress, through OMB, 
explanations when the Agency does not use available and applicable VCS.
    The proposed rule involves technical standards. The EPA cites the 
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A, 
3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 40 CFR part 60; 101A of 40 
CFR part 61; and voluntary consensus standards: American Society for 
Testing and Materials (ASTM) D6522-00, American Society of Mechanical 
Engineers (ASME) PTC 19 (manual methods only), ASTM D6784-02, ASTM 
D2234-D2234M-03, ASTM D6323-98, ASTM D2013-04, ASTM d5198-92, ASTM 
D5865-04, ASTM E711-87, ASTM D3173-03, ASTM E871-82, and ASTM D6722-01.
    Consistent with the NTTAA, EPA conducted searches to identify 
voluntary consensus standards in addition to these EPA methods. No 
applicable voluntary consensus standards were identified for EPA 
Methods 2F, 2G, 5D, and 19. The search and review results are in the 
docket for this rule.
    The search for emissions measurement procedures identified 16 other 
voluntary consensus standards. The EPA determined that these 16 
standards identified for measuring emissions of the HAP or surrogates 
subject to emission standards in this rule were impractical 
alternatives to EPA test methods for the purposes of this rule. 
Therefore, EPA does not intend to adopt these standards for this 
purpose. The reasons for the determinations for the 16 methods can be 
found in the docket to this rule.
    Table 4 to subpart JJJJJJ of this proposed rule lists the testing 
methods included in the regulation. Under section 3.7(f) and section 
63.8(f) of Subpart A of the General Provisions, a source may apply to 
EPA for permission to use alternative test methods or alternative 
monitoring requirements in place of any required testing methods, 
performance specifications, or procedures.
    EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such 
standards should be used in this regulation.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice (EJ). Its main 
provision directs Federal agencies, to the greatest extent practicable 
and permitted by law, to

[[Page 31924]]

make EJ part of their mission by identifying and addressing, as 
appropriate, disproportionately high and adverse human health or 
environmental effects of their programs, policies, and activities on 
minority populations, low-income, and Tribal populations in the United 
States.
    This proposed action establishes national emission standards for 
industrial, commercial, and institutional boilers that are area 
sources. The industrial boiler source category includes boilers used in 
manufacturing, processing, mining, refining, or any other industry. The 
commercial boiler source category includes boilers used in commercial 
establishments such as stores/malls, laundries, apartments, 
restaurants, theaters, and hotels/motels. The institutional boiler 
source category includes boilers used in medical centers (e.g., 
hospitals, clinics, nursing homes), educational and religious 
facilities (e.g., schools, universities, places of worship), and 
municipal buildings (e.g., courthouses, arts centers, prisons). There 
are approximately 91,000 facilities affected by the proposed rule, most 
of which are small entities. By the defined nature of the category, 
many of these sources are located in close proximity to residential 
areas, commercial centers, and other locations where large numbers of 
people live and work.
    Due to the large number of these sources, their nation-wide 
dispersal, and the absence of site specific coordinates, EPA is unable 
to examine the distributions of exposures and health risks attributable 
to these sources among different socio-demographic groups for this 
rule, or to relate the locations of expected emission reductions to the 
locations of current poor air quality. However, the rule is anticipated 
to have substantial emissions reductions of toxic air pollutants (See 
Table 2.), some of which are potential carcinogens, neurotoxins, and 
respiratory irritants. The rule will also result in substantial 
reductions in criteria pollutants such as CO, PM, SO2, as 
well as ozone precursors.
    Because of the close proximity of these source categories to 
people, the substantial emission reductions of air toxics resulting 
from the implementation of this proposed rule is anticipated to have 
health benefits for all persons living or going near these types of 
sources. (Please refer to the RIA for this rulemaking, which is 
available in the docket.) For example, there will be significant 
reductions of mercury emissions which will reduce potential exposures 
due to the atmospheric deposition of mercury for populations such as 
subsistence fisherman. In addition, there will be substantial 
reductions in other air toxics that can cause adverse health effects 
such as ozone precursors which contribute to ``smog.'' This rule will 
not cause an increase in any adverse human health or environmental 
effects on any population, including any minority, low-income, or 
Tribal populations.
    EPA defines ``Environmental Justice'' to include meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and polices. To promote 
meaningful involvement, EPA has developed an EJ communication strategy 
to ensure that interested communities have access to this proposed 
rule, are aware of its content, and have an opportunity to comment. 
During the comment period, EPA will publicize the rulemaking via EJ 
newsletters, Tribal newsletters, EJ listserves, and the Internet, 
including Office of Policy, Economics, and Innovation's (OPEI) 
Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/rulegate.nsf/
content/index.html?opendocument). EPA will also provide general 
rulemaking fact sheets (e.g., why is this important for my community) 
for EJ community groups and conduct conference calls with interested 
communities. In addition, State and Federal permitting requirements 
will provide State, local governments and communities the opportunity 
to provide their comments on the permit conditions associated with 
permitting these sources.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances, Intergovernmental 
relations, Reporting and recordkeeping requirements.

    Dated: April 29, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
63 of the Code of Federal Regulations is proposed to be amended as 
follows:

PART 63--[AMENDED]

    1. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart A--[Amended]

    2. Section 63.14 is amended by revising paragraphs (b)(27), 
(b)(39), (b)(47), (b)(49), (b)(50), (b)(52), (b)(55), (b)(56), (b)(58), 
(b)(61), (b)(62), and (i)(1) to read as follows:

63.14  Incorporation by reference.

* * * * *
    (b) * * *
    (27) ASTM D 6522-00, Standard Test Method for Determination of 
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in 
Emissions from Natural Gas Fired Reciprocating Engines, Combustion 
Turbines, Boilers, and Process Heaters Using Portable Analyzers,\1\ IBR 
approved for Sec.  63.9307(c)(2), Table 4 to subpart ZZZZ, Table 5 to 
subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
    (39) ASTM Method D388-99 [egr]\1\, Standard Classification of Coals 
by Rank\1\, IBR approved for Sec.  63.7575 and Sec.  63.11237.
* * * * *
    (47) ASTM D5198-92 (Reapproved 2003), Standard Practice for Nitric 
Acid Digestion of Solid Waste,\1\ IBR approved for Table 6 to subpart 
DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory 
Subsampling of Media Related to Waste Management Activities,\1\ IBR 
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of 
this part.
    (50) ASTM E711-87 (Reapproved 1996), Standard Test Method for Gross 
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter,\1\ IBR 
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of 
this part.
* * * * *
    (52) ASTM E871-82 (Reapproved 1998), Standard Method of Moisture 
Analysis of Particulate Wood Fuels,\1\ IBR approved for Table 6 to 
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (55) ASTM D2013-04, Standard Practice for Preparing Coal Samples 
for Analysis, IBR approved for Table 6 to subpart DDDDD and Table 5 to 
subpart JJJJJJ of this part.
    (56) ASTM D2234-D2234M-03 [egr]\1\, Standard Practice for 
Collection of a Gross Sample of Coal, IBR approved for Table 6 to 
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (58) ASTM D3173-03, Standard Test Method for Moisture in the 
Analysis Sample of Coal and Coke, IBR approved

[[Page 31925]]

for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this 
part.
    (61) ASTM D6722-01, Standard Test Method for Total Mercury in Coal 
and Coal Combustion Residues by the Direct Combustion Analysis, IBR 
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of 
this part.
    (62) ASTM D5865-04, Standard Test Method for Gross Calorific Value 
of Coal and Coke, IBR approved for Table 6 to subpart DDDDD and Table 5 
to subpart JJJJJJ of this part.
* * * * *
    (i) * * *
    (1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.  
63.865(b), 63.3166(a), 63.3360(e)(1)(iii), 63.3545(a)(3), 
63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 
63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), Table 
5 to subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
    3. Add subpart JJJJJJ to read as follows:

Subpart JJJJJJ--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
Area Sources

Sec.

What This Subpart Covers

63.11193 Am I subject to this subpart?
63.11194 What is the affected source of this subpart?
63.11195 Are any boilers not subject to this subpart?
63.11196 When do I have to comply with this subpart?

Emission Limits, Work Practice Standards, Emission Reduction Measures, 
and Management Practices

63.11200 What are the subcategories of boilers?
63.11201 What standards must I meet?

Initial Compliance Requirements

63.11205 What are my general requirements for complying with this 
subpart?
63.11210 What are my initial compliance requirements and by what 
date must I conduct them?
63.11211 How do I demonstrate initial compliance with the emission 
limits?
63.11212 What stack tests and procedures must I use for the 
performance tests?
63.11213 What fuel analyses and procedures must I use for the 
performance tests?
63.11214 When must I conduct subsequent performance tests?
63.11215 How do I demonstrate initial compliance with the work 
practice standard, emission reduction measures, and management 
practice?

Continuous Compliance Requirements

63.11220 How do I monitor and collect data to demonstrate continuous 
compliance?
63.11221 How do I demonstrate continuous compliance with the 
emission limits?
63.11222 How do I demonstrate continuous compliance with the work 
practice standards?
63.11223 What are my monitoring, installation, operation, and 
maintenance requirements?
63.11225 What are my notification, reporting, and recordkeeping 
requirements?

Other Requirements and Information

63.11235 What parts of the General Provisions apply to me?
63.11236 Who implements and enforces this subpart?
63.11237 What definitions apply to this subpart?
Table 1 to Subpart JJJJJJ of Part 63. Emission Limits
Table 2 to Subpart JJJJJJ of Part 63. Work Practice Standards
Table 3 to Subpart JJJJJJ of Part 63. Operating Limits for Boilers 
With Emission Limits
Table 4 to Subpart JJJJJJ of Part 63. Performance (Stack) Testing 
Requirements
Table 5 to Subpart JJJJJJ of Part 63. Fuel Analysis Requirements
Table 6 to Subpart JJJJJJ of Part 63. Applicability of General 
Provisions to Subpart JJJJJJ

Subpart JJJJJJ--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
Area Sources

What This Subpart Covers

Sec.  63.11193 Am I subject to this subpart?
    You are subject to this subpart if you own or operate an 
industrial, commercial, or institutional boiler as defined in Sec.  
63.11237 that is located at, or is part of, an area source of hazardous 
air pollutants (HAP), as defined in Sec.  63.2.

Sec.  63.11194  What is the affected source of this subpart?

    (a) This subpart applies to each new or existing affected sources 
as defined in paragraphs (a)(1) and (2) of this section.
    (1) The affected source is the collection of all existing 
industrial, commercial, and institutional boilers within a subcategory 
located at an area source.
    (2) The affected source of this subpart is each new or 
reconstructed industrial, commercial, or institutional boiler located 
at an area source.
    (b) An affected source is an existing source if you commenced 
construction or reconstruction of the affected source on or before June 
4, 2010.
    (c) An affected source is a new source if you commenced 
construction or reconstruction of the affected source after June 4, 
2010.
    (d) A boiler is a new affected source if you commenced fuel 
switching from natural gas to coal, biomass, or oil after June 4, 2010.
    (e) Any source that was a major source and installed a control 
device on a boiler after November 15, 1990, and, as a result, became an 
area source under 40 CFR part 63 is required to obtain a permit under 
40 CFR part 70 or 40 CFR part 71. Otherwise, you are exempt from the 
obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, 
provided you are not otherwise required by law to obtain a permit under 
40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous 
sentence, you must continue to comply with the provisions of this 
subpart.

Sec.  63.11195  Are any boilers not subject to this subpart?

    The types of boilers listed in paragraphs (a) through (e) of this 
section are not subject to this subpart.
    (a) Any boiler specifically listed as an affected source in another 
standard(s) under this part.
    (b) Any boiler specifically listed as an affected source in another 
standard(s) established under section 129 of the Clean Air Act (CAA).
    (c) A boiler required to have a permit under section 3005 of the 
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g., 
hazardous waste boilers).
    (d) A boiler that is used specifically for research and 
development. This does not include boilers that only provide steam to a 
process or for heating at a research and development facility.
    (e) A gas-fired boiler as defined in this subpart.

Sec.  63.11196  What are my compliance dates?

    (a) If you own or operate an existing affected source, you must 
achieve compliance with the applicable provisions in this subpart no 
later than [DATE 3 YEARS AFTER PUBLICATION OF THE FINAL RULE IN THE 
FEDERAL REGISTER].
    (b) If you start up a new affected source on or before [DATE OF 
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
achieve compliance with the provisions of this subpart no later than 
[DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
    (c) If you start up a new affected source after [DATE OF 
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
achieve compliance with the provisions of this

[[Page 31926]]

subpart upon startup of your affected source.

Emission Limits, Work Practice Standards, Emission Reduction Measures, 
and Management Practices

Sec.  63.11200  What are the subcategories of boilers?

    The subcategories of boilers are coal, biomass, and oil. Each 
subcategory is defined in Sec.  63.11237.

Sec.  63.11201  What standards must I meet?

    (a) You must comply with each emission limit specified in Table 1 
of this subpart that applies to your boiler.
    (b) You must comply with each work practice standard, emission 
reduction measure, and management practice specified in Table 2 of this 
subpart that applies to your boiler.
    (c) These standards apply at all times.

Initial Compliance Requirements

Sec.  63.11205  What are my general requirements for complying with 
this subpart?

    (a) At all times you must operate and maintain any affected source, 
including associated air pollution control equipment and monitoring 
equipment, in a manner consistent with safety and good air pollution 
control practices for minimizing emissions. The general duty to 
minimize emissions does not require you to make any further efforts to 
reduce emissions if levels required by this standard have been 
achieved. Determination of whether such operation and maintenance 
procedures are being used will be based on information available to the 
Administrator which may include, but is not limited to, monitoring 
results, review of operation and maintenance procedures, review of 
operation and maintenance records, and inspection of the source.
    (b) You can demonstrate compliance with any applicable mercury 
emission limit using fuel analysis if the emission rate calculated 
according to Sec.  63.11211(b) is less than the applicable emission 
limit. Otherwise, you must demonstrate compliance using stack testing.

Sec.  63.11210  What are my initial compliance requirements and by what 
date must I conduct them?

    (a) You must demonstrate initial compliance with each emission 
limit specified in Table 1 of this subpart that applies to you by 
either conducting performance (stack) tests, as applicable, according 
to Sec.  63.11212 and Table 4 of this subpart or conducting fuel 
analyses, as applicable, according to Sec.  63.11213 and Table 5 to 
this subpart.
    (b) For affected sources that have an applicable carbon monoxide 
(CO) emission limit, your initial compliance requirements depend on the 
rated capacity of your boiler. If your boiler has a heat input capacity 
between 10 and 100 million British thermal units (MMBtu) per hour, your 
initial compliance demonstration is conducting a performance test for 
CO according to Table 4 to this subpart. If your boiler has a heat 
input capacity of 100 MMBtu per hour or greater, your initial 
compliance demonstration is conducting a performance evaluation of your 
continuous emission monitoring system (CEMS) for CO according to Sec.  
63.11223.
    (c) For existing affected sources that have applicable emission 
limits, you must demonstrate initial compliance no later than 180 days 
after the compliance date that is specified in Sec.  63.11196 and 
according to the applicable provisions in Sec.  63.7(a)(2).
    (d) For existing affected sources that have applicable work 
practice standards or emission reduction measures, you must demonstrate 
initial compliance no later than the compliance date that is specified 
in Sec.  63.11196 and according to the applicable provisions in Sec.  
63.7(a)(2).
    (e) For new affected sources, you must demonstrate initial 
compliance no later than 180 calendar days after [INSERT THE DATE OF 
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 180 
calendar days after startup of the source, whichever is later, 
according to Sec.  63.7(a)(2)(ix).

Sec.  63.11211  How do I demonstrate initial compliance with the 
emission limits?

    (a) For affected sources that elect to demonstrate compliance with 
any of the emission limits of this subpart through performance (stack) 
testing, your initial compliance requirements include conducting 
performance tests according to Sec.  63.11212 and Table 4 to this 
subpart and conducting CMS performance evaluations according to Sec.  
63.11223.
    (b) If you elect to demonstrate compliance with an applicable 
mercury emission limit through fuel analysis, you must conduct fuel 
analyses according to Sec.  63.11213 and follow the procedures in 
paragraphs (b)(1) through (3) of this section.
    (1) If you burn more than one fuel type, you must determine the 
fuel mixture you could burn in your boiler that would result in the 
maximum emission rates of mercury that you elect to demonstrate 
compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel 
mercury concentration of the composite samples analyzed for each fuel 
type using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.001

Where:

P90 = 90th percentile confidence level mercury 
concentration, in pounds per million Btu;
mean = Arithmetic average of the fuel mercury concentration in the 
fuel samples analyzed according to Sec.  63.11213, in units of 
pounds per million Btu;
SD = Standard deviation of the mercury concentration in the fuel 
samples analyzed according to Sec.  63.11213, in units of pounds per 
million Btu;
t = t distribution critical value for 90th percentile (0.1) 
probability for the appropriate degrees of freedom (number of 
samples minus one) as obtained from a Distribution Critical Value 
Table.

    (3) To demonstrate compliance with the applicable mercury emission 
limit, the emission rate that you calculate for your boiler using 
Equation 1 of this section must be less than the applicable mercury 
emission limit.

Sec.  63.11212  What stack tests and procedures must I use for the 
performance tests?

    (a) You must conduct all performance tests according to the 
requirements in Sec.  63.7.
    (b) You must conduct each stack test according to the requirements 
in Table 4 to this subpart.
    (c) You must conduct stack tests at the maximum normal operating 
load while burning the type of fuel or mixture of fuels that have the 
highest content of mercury, and you must demonstrate initial compliance 
based on these tests.
    (d) You must conduct a minimum of three separate test runs for each 
performance test required in this section, as specified in Sec.  
63.7(e)(3). The sampling time for each test run must last at least 1 
hour except that the sampling time for the test runs conducted for 
mercury emissions must last at least 2 hours.
    (e) To determine compliance with the emission limits, you must use 
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA 
Method 19 of appendix A to part 60 of this chapter to convert the 
measured particulate matter concentrations and the measured mercury 
concentrations that result from the initial performance test to pounds 
per million Btu heat input emission rates.

Sec.  63.11213  What fuel analyses and procedures must I use for the 
performance tests?

    (a) You must conduct fuel analyses according to the procedures in

[[Page 31927]]

paragraphs (b) and (c) of this section and Table 5 to this subpart, as 
applicable.
    (b) At a minimum, you must obtain three composite fuel samples for 
each fuel type according to the procedures in Table 5 of this subpart. 
Each composite sample will consist of a minimum of three samples 
collected at approximately equal intervals during a test run period.
    (c) Determine the concentration of mercury in the fuel in units of 
pounds per million Btu of each composite sample for each fuel type 
according to the procedures in Table 5 to this subpart.

Sec.  63.11214  When must I conduct subsequent performance tests?

    (a) You must conduct all applicable performance (stack) tests 
according to Sec.  63.11212 on an annual basis, unless you follow the 
requirements listed in paragraphs (b) through (d) of this section. 
Annual performance tests must be completed between 10 and 12 months 
after the previous performance test, unless you follow the requirements 
listed in paragraphs (b) through (d) of this section.
    (b) You can conduct performance stack tests less often for 
particulate matter or mercury if your performance stack tests for the 
pollutant for at least 3 consecutive years show that your emissions are 
at or below 75 percent of the emission limit, and if there are no 
changes in the operation of the affected source or air pollution 
control equipment that could increase emissions. In this case, you do 
not have to conduct a performance test for that pollutant for the next 
2 years. You must conduct a performance test during the third year and 
no more than 36 months after the previous performance test.
    (c) If your boiler continues to meet the emission limit for 
particulate matter or mercury, you may choose to conduct performance 
stack tests for the pollutant every third year if your emissions are at 
or below 75 percent of the emission limit, and if there are no changes 
in the operation of the affected source or air pollution control 
equipment that could increase emissions, but each such performance test 
must be conducted no more than 36 months after the previous performance 
test.
    (d) If a performance test shows emissions exceeded 75 percent of 
the emission limit, you must conduct annual performance tests for that 
pollutant until all performance tests over consecutive 3-year period 
show compliance.
    (e) If you have an applicable CO emission limit and your boiler has 
a heat input capacity between 10 and 100 MMBtu per hour, you must 
conduct annual performance tests for CO according to Sec.  63.11211. 
Each annual performance test must be conducted between 10 and 12 months 
after the previous performance test.
    (f) If you demonstrate compliance with the mercury based on fuel 
analysis, you must conduct a fuel analysis according to Sec.  63.11213 
for each type of fuel burned monthly. If you plan to burn a new type of 
fuel or fuel mixture, you must conduct a fuel analysis before burning 
the new type of fuel or mixture in your boiler. You must recalculate 
the mercury emission rate using Equation 1 of Sec.  63.11211. The 
recalculated mercury emission rate must be less than the applicable 
emission limit.

Sec.  63.11215  How do I demonstrate initial compliance with the work 
practice standard, emission reduction measures, and management 
practice?

    (a) If you own or operate an existing boiler with a heat input 
capacity of less than 10 million Btu per hour, you must submit a signed 
statement in the Notification of Compliance Status report that 
indicates that you conducted a tune-up of the boiler.
    (b) If you own or operate an existing affected boiler with a heat 
input capacity of 10 million Btu per hour or greater, you must submit 
the energy assessment report, along with a signed certification that 
the assessment is an accurate depiction of your facility.

Continuous Compliance Requirements

Sec.  63.11220  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) You must monitor and collect data according to this section and 
the site-specific monitoring plan required by Sec.  63.11223.
    (b) Except for monitor malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must monitor continuously (or collect data at all required 
intervals) at all times that the affected source is operating.
    (c) You may not use data recorded during monitoring malfunctions, 
associated repairs, or required quality assurance or control activities 
in data averages and calculations used to report emission or operating 
levels. You must use all the data collected during all other periods in 
assessing the operation of the control device and associated control 
system.

Sec.  63.11221  How do I demonstrate continuous compliance with the 
emission limits?

    (a) You must demonstrate continuous compliance with each emission 
limit and operating limit in Tables 1 and 3 to this subpart that 
applies to you according to paragraphs (a)(1) through (5) of this 
section.
    (1) Following the date on which the initial performance test is 
completed or is required to be completed under Sec. Sec.  63.7 and 
63.11196, whichever date comes first, you must not operate above any of 
the applicable maximum operating limits or below any of the applicable 
minimum operating limits listed in Table 3 to this subpart at all 
times. Operation above the established maximum or below the established 
minimum operating limits shall constitute a deviation of established 
operating limits. Operating limits are confirmed or reestablished 
during performance tests.
    (2) If you have an applicable mercury emission limit, you must keep 
records of the type and amount of all fuels burned in each boiler 
during the reporting period to demonstrate that all fuel types and 
mixtures of fuels burned would result in lower emissions of mercury 
than the applicable emission limit.
    (3) If you have you have an applicable mercury emission limit and 
you plan to burn a new type of fuel, you must determine the mercury 
concentration for any new fuel type in units of pounds per million Btu, 
based on supplier data or your own fuel analysis and meet the 
requirements in paragraphs (a)(3)(i) or (ii) of this section.
    (i) The recalculated mercury emission rate must be less than the 
applicable emission limit.
    (ii) If the results are higher than mercury fuel input during the 
previous performance test, then you must conduct a new performance test 
within 60 days of burning the new fuel type or fuel mixture according 
to the procedures in Sec.  63.11212 to demonstrate that the mercury 
emissions do not exceed the emission limit.
    (4) If your unit is controlled with a fabric filter, and you 
demonstrate continuous compliance using a bag leak detection system, 
you must initiate corrective action within 1 hour of a bag leak 
detection system alarm and operate and maintain the fabric filter 
system such that the alarm does not sound more than 5 percent of the 
operating time during a 6-month period. You must also keep records of 
the date, time, and duration of each alarm, the time corrective action 
was initiated and completed, and a brief description of the

[[Page 31928]]

cause of the alarm and the corrective action taken. You must also 
record the percent of the operating time during each 6-month period 
that the alarm sounds. In calculating this operating time percentage, 
if inspection of the fabric filter demonstrates that no corrective 
action is required, no alarm time is counted. If corrective action is 
required, each alarm shall be counted as a minimum of 1 hour. If you 
take longer than 1 hour to initiate corrective action, the alarm time 
shall be counted as the actual amount of time taken to initiate 
corrective action.
    (5) If you have an applicable CO emission limit and you are 
required to install a CEMS according to Sec.  63.11223, then you must 
continuously monitor CO according to Sec. Sec.  63.11223(a) and 
63.11220 and maintain a CO emission level below your applicable CO 
emission limit in Table 1 to this subpart at all times.
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 and 3 to this subpart 
that apply to you. These instances are deviations from the emission 
limits in this subpart. These deviations must be reported according to 
the requirements in Sec.  63.11224.

Sec.  63.11222  How do I demonstrate continuous compliance with the 
work practice and management practice standards?

    (a) For affected sources subject to the work practice standard or 
the management practices, you must keep records as required in Sec.  
63.11224(c) to demonstrate continuous compliance.
    (b) You must conduct a tune-up of the boiler biennially to 
demonstrate continuous compliance as specified in paragraphs (b)(1) 
through (6) of this section.
    (1) Inspect the burner, and clean or replace any components of the 
burner as necessary;
    (2) Inspect the flame pattern and make any adjustments to the 
burner necessary to optimize the flame pattern consistent with the 
manufacturer's specifications;
    (3) Inspect the system controlling the air-to-fuel ratio, and 
ensure that it is correctly calibrated and functioning properly;
    (4) Minimize total emissions of CO consistent with the 
manufacturer's specifications;
    (5) Measure the concentration in the effluent stream of CO in parts 
per million, by volume, dry basis (ppmvd), before and after the 
adjustments are made; and
    (6) Maintain on-site and submit, if requested by the Administrator, 
an annual report containing the information in paragraphs (b)(6)(i) 
through (iii) of this section,
    (i) The concentrations of CO in the effluent stream in ppmvd, and 
oxygen in percent dry basis, measured before and after the adjustments 
of the boiler;
    (ii) A description of any corrective actions taken as a part of the 
combustion adjustment; and
    (iii) The type and amount of fuel used over the 12 months prior to 
the annual adjustment.

Sec.  63.11223  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If you are using a control device to comply with the emission 
limits specified in Table 1 of this subpart, you must maintain each 
operating limit in Table 3 of this subpart that applies to your boiler. 
If you use a control device not covered in Table 3, or you wish to 
establish and monitor an alternative operating limit and alternative 
monitoring parameters, you must apply to the United States 
Environmental Protection Agency (EPA) Administrator for approval of 
alternative monitoring under Sec.  63.8(f).
    (b) If you demonstrate compliance with any applicable emission 
limit through stack testing, you must develop a site-specific 
monitoring plan according to the requirements in paragraphs (b)(1) 
through (4) of this section. This requirement also applies to you if 
you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
    (1) For each continuous monitoring system (CMS) required in this 
section, you must develop, and submit to the EPA Administrator for 
approval upon request, a site-specific monitoring plan that addresses 
paragraphs (b)(1)(i) through (iii) of this section. You must submit 
this site-specific monitoring plan (if requested) at least 60 days 
before your initial performance evaluation of your CMS.
    (i) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected unit such that the 
measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device);
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations).
    (2) In your site-specific monitoring plan, you must also address 
paragraphs (b)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  63.8(c)(1), (3), and (4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in 
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation 
according to the site-specific monitoring plan.
    (c) If you have an operating limit that requires the use of a CMS, 
you must install, operate, and maintain each continuous parameter 
monitoring system (CPMS) according to the procedures in paragraphs 
(c)(1) through (5) of this section.
    (1) The CPMS must complete a minimum of one cycle of operation for 
each successive 15-minute period. You must have a minimum of four 
successive cycles of operation to have a valid hour of data.
    (2) Except for monitoring malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must conduct all monitoring in continuous operation at all times 
that the unit is operating. A monitoring malfunction is any sudden, 
infrequent, not reasonably preventable failure of the monitoring to 
provide valid data. Monitoring failures that are caused in part by poor 
maintenance or careless operation are not malfunctions.
    (3) For purposes of calculating data averages, you must not use 
data recorded during monitoring malfunctions, associated repairs, out 
of control periods, or required quality assurance or control 
activities. You must use all the data collected during all other 
periods in assessing compliance. Any period for which the monitoring 
system is out-of-control and data are not available for required 
calculations constitutes a deviation from the monitoring requirements.
    (4) Determine the 3-hour block average of all recorded readings, 
except as provided in paragraph (c)(3) of this section.
    (5) Record the results of each inspection, calibration, and 
validation check.
    (d) If you have an applicable opacity operating limit, you must 
install, operate, certify and maintain each

[[Page 31929]]

continuous opacity monitoring system (COMS) according to the procedures 
in paragraphs (d)(1) through (7) of this section by the compliance date 
specified in Sec.  63.11196.
    (1) Each COMS must be installed, operated, and maintained according 
to PS 1 of 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each COMS 
according to the requirements in Sec.  63.8 and according to PS 1 of 40 
CFR part 60, appendix B.
    (3) As specified in Sec.  63.8(c)(4)(i), each COMS must complete a 
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
    (4) The COMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  63.8(d). At a minimum, the 
monitoring plan must include a daily calibration drift assessment, a 
quarterly performance audit, and an annual zero alignment audit of each 
COMS.
    (6) You must operate and maintain each COMS according to the 
requirements in the monitoring plan and the requirements of Sec.  
63.8(e). Identify periods the COMS is out of control including any 
periods that the COMS fails to pass a daily calibration drift 
assessment, a quarterly performance audit, or an annual zero alignment 
audit.
    (7) You must determine and record all the 1-hour block averages 
collected for periods during which the COMS is not out of control.
    (e) If you have an applicable CO emission limit and your boiler has 
a heat input capacity of 100 MMBtu per hour or greater, you must 
install, operate, and maintain a CEMS for CO and oxygen according to 
the procedures in paragraphs (e)(1) through (6) of this section by the 
compliance date specified in Sec.  63.11196. The CO and oxygen shall be 
monitored at the same location at the outlet of the boiler.
    (1) Each CEMS must be installed, operated, and maintained according 
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and 
according to the site-specific monitoring plan developed according to 
Sec.  63.11223.
    (2) You must conduct a performance evaluation of each CEMS 
according to the requirements in Sec.  63.8 and according to PS 4A of 
40 CFR part 60, appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period.
    (4) The CEMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must calculate and record all daily averages. A new daily 
average emission rate is calculated as the average of all of the hourly 
CO emission data for the calendar day.
    (6) For purposes of calculating data averages, you must not use 
data recorded during periods of monitoring malfunctions, associated 
repairs, out-of-control periods, required quality assurance or control 
activities, or when your boiler is operating at less than 50 percent of 
its rated capacity. You must use all the data collected during all 
other periods in assessing compliance. Any period for which the 
monitoring system is out of control and data are not available for 
required calculations constitutes a deviation from the monitoring 
requirements.
    (f) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
CEMS according to the requirements in Sec.  63.8(d).

Sec.  63.11224  What are my notification, reporting, and recordkeeping, 
requirements?

    (a) You must submit the notifications specified in paragraphs 
(a)(1) through (a)(4) of this section.
    (1) You must submit all of the notifications in Sec. Sec.  63.5(b), 
63.7(b): 63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that 
apply to you by the dates specified in those sections.
    (2) As specified in Sec.  63.9(b)(2), you must submit the Initial 
Notification no later than 120 calendar days after [INSERT THE DATE OF 
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 120 
days after the source becomes subject to the standard.
    (3) You must submit the Notification of Compliance Status in 
accordance with Sec.  63.9(h) no later than 120 days after the 
applicable compliance date specified in Sec.  63.11196 unless you must 
conduct a performance test. If you must conduct a performance test, you 
must submit the Notification of Compliance Status within 60 days of 
completing the performance test. In addition to the information 
required in Sec.  63.9(h)(2), your notification must include the 
following certification(s) of compliance, as applicable, and signed by 
a responsible official:
    (i) ``This facility complies with the requirements in Sec.  
63.11222(b) to conduct a biennial tune-up of the boiler''.
    (ii) ``This facility has had an energy assessment performed 
according to Sec.  63.11215.''
    (iii) This certification of compliance by the owner or operator 
that installs bag leak detection systems: ``This facility has prepared 
a bag leak detection system monitoring plan in accordance with Sec.  
63.11221 and will operate each bag leak detection system according to 
the plan.''
    (4) If you are using data from a previously conducted emission test 
to serve as documentation of conformance with the emission standards 
and operating limits of this subpart consistent with Sec.  
63.7(e)(2)(iv), you must submit the test data in lieu of the initial 
performance test results with the Notification of Compliance Status 
required under paragraph (a)(3) of this section.
    (b) You must prepare, by March 1 of each year, an annual compliance 
certification report for the previous calendar year containing the 
information specified in paragraphs (b)(1) through (b)(3) of this 
section. You must submit the report by March 15 if you had any instance 
described by paragraph (b)(3) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official, with the official's name, 
title, phone number, e-mail address, and signature, certifying the 
truth, accuracy and completeness of the notification and a statement of 
whether the source has complied with all the relevant standards and 
other requirements of this subpart.
    (3) If the source is not in compliance, include a description of 
deviations from the applicable requirements, the time periods during 
which the deviations occurred, and the corrective actions taken.
    (4) The total fuel use by each affected source subject to an 
emission limit, for each calendar month within the reporting period, 
including, but not limited to, a description of the fuel, including 
whether the fuel has received a non-waste determination by you or EPA, 
and the total fuel usage amount with units of measure.
    (c) You must maintain the records specified in paragraphs (c)(1) 
through (5) of this section.
    (1) As required in Sec.  63.10(b)(2)(xiv), you must keep a copy of 
each notification and report that you submitted to comply with this 
subpart and all documentation supporting any Initial Notification or 
Notification of Compliance Status that you submitted.
    (2) You must keep records to document conformance with the work 
practices, emission reduction measures, and management practices 
required by

[[Page 31930]]

Sec.  63.11215 as specified in paragraphs (c)(2)(i) through (iv) of 
this section.
    (i) Records must identify each boiler, the date of tune-up, the 
procedures followed for tune-up, and the manufacturer's specifications 
to which the boiler was tuned.
    (ii) Records documenting monthly fuel use by each boiler, including 
the type(s) of fuel, including, but not limited to, a description of 
the fuel, including whether the fuel has received a non-waste 
determination by you or EPA, and the total fuel usage amount with units 
of measure.
    (3) For sources that demonstrate compliance through fuel analysis, 
a copy of all calculations and supporting documentation that were done 
to demonstrate compliance with the mercury emission limits. Supporting 
documentation should include results of any fuel analyses. You can use 
the results from one fuel analysis for multiple boilers provided they 
are all burning the same fuel type.
    (4) You must keep the records of all inspection and monitoring data 
required by Sec. Sec.  63.11221 and 63.11222, and the information 
identified in paragraphs (c)(4)(i) through (vi) of this section for 
each required inspection or monitoring.
    (i) The date, place, and time of the monitoring event;
    (ii) Person conducting the monitoring;
    (iii) Technique or method used;
    (iv) Operating conditions during the activity;
    (v) Results, including the date, time, and duration of the period 
from the time the monitoring indicated a problem to the time that 
monitoring indicated proper operation; and
    (vi) Maintenance or corrective action taken (if applicable).
    (5) If you use a bag leak detection system, you must keep the 
records specified in paragraphs (c)(5)(i) through (iii) of this 
section.
    (i) Records of the bag leak detection system output.
    (ii) Records of bag leak detection system adjustments, including 
the date and time of the adjustment, the initial bag leak detection 
system settings, and the final bag leak detection system settings.
    (iii) The date and time of all bag leak detection system alarms, 
and for each valid alarm, the time you initiated corrective action, the 
corrective action taken, and the date on which corrective action was 
completed.
    (d) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec.  63.10(b)(1). As specified in 
Sec.  63.10(b)(1), you must keep each record for 5 years following the 
date of each recorded action. You must keep each record onsite for at 
least 2 years after the date of each recorded action according to Sec.  
63.10(b)(1). You may keep the records offsite for the remaining 3 
years.
    (e) For affected facilities having applicable emission limits, you 
must submit an electronic copy of stack test reports to EPA's WebFIRE 
data base, the owner or operator of an affected facility shall enter 
the test data into EPA's data base using the Electronic Reporting Tool 
located at http://www.epa.gov/ttn/chief/ert/ert_tool.html.

Other Requirements and Information

Sec.  63.11235  What parts of the General Provisions apply to me?

    Table 6 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  63.1 through 63.15 apply to you.

Sec.  63.11236  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by EPA or a 
delegated authority such as your State, local, or tribal agency. If the 
EPA Administrator has delegated authority to your State, local, or 
tribal agency, then that agency has the authority to implement and 
enforce this subpart. You should contact your EPA Regional Office to 
find out if implementation and enforcement of this subpart is delegated 
to your State, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a State, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities contained in paragraphs (c) of this section 
are retained by the EPA Administrator and are not transferred to the 
State, local, or tribal agency.
    (c) The authorities that cannot be delegated to State, local, or 
tribal agencies are specified in paragraphs (c)(1) through (5) of this 
section.
    (1) Approval of an alternative non-opacity emission standard and 
work practice standards in Sec.  63.11223(a).
    (2) Approval of alternative opacity emission standard under Sec.  
63.6(h)(9).
    (3) Approval of major change to test methods under Sec.  
63.7(e)(2)(ii) and (f). A ``major change to test method'' is defined in 
Sec.  63.90.
    (4) Approval of a major change to monitoring under Sec.  63.8(f). A 
``major change to monitoring'' is defined in Sec.  63.90.
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(f). A ``major change to recordkeeping/reporting'' is 
defined in Sec.  63.90.

Sec.  63.11237  What definitions apply to this subpart?

    Terms used in this subpart are defined in the CAA, in Sec.  63.2 
(the General Provisions), and in this section as follows:
    Bag leak detection system means an instrument that is capable of 
monitoring particulate matter loadings in the exhaust of a fabric 
filter (i.e., baghouse) in order to detect bag failures. A bag leak 
detection system includes, but is not limited to, an instrument that 
operates on electrodynamic, triboelectric, light scattering, light 
transmittance, or other principle to monitor relative particulate 
matter loadings.
    Biomass means but is not limited to, wood residue, and wood 
products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust, 
sanderdust, chips, scraps, slabs, millings, and shavings); animal 
manure, including litter and other bedding materials; vegetative 
agricultural and silvicultural materials, such as logging residues 
(slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut, 
rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean 
hulls and grounds. This definition of biomass fuel is not intended to 
suggest that these materials are or not solid waste.
    Biomass subcategory includes any boiler that burns any amount of 
biomass, but no coal, either alone or in combination with liquid fuels 
or gaseous fuels.
    Boiler means an enclosed combustion device in which water is heated 
to recover thermal energy in the form of steam or hot water. A device 
combusting solid waste, as defined in 40 CFR 241.3, is not a boiler. 
Waste heat boilers are excluded from this definition.
    Boiler system means the boiler and associated components, such as, 
the feedwater system, the combustion air system, the fuel system 
(including burners), blowdown system, combustion control system, and 
the energy consuming systems.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials in ASTM D388-99e1, ``Standard Specification for 
Classification of Coals by Rank\1\'' (incorporated by reference, see 
Sec.  63.14(b)) and synthetic fuels derived from coal including but not 
limited to, solvent-refined coal, coal-oil mixtures, and coal-water 
mixtures. Coal derived gases are excluded from this definition.
    Coal subcategory includes any boiler that burns any coal alone or 
at least 10

[[Page 31931]]

percent coal on an annual heat input basis in combination with biomass, 
liquid fuels, or gaseous fuels.
    Commercial boiler means a boiler used in commercial establishments 
such as hotels, restaurants, and laundries to provide electricity, 
steam, and/or hot water that does not combust solid waste, as that term 
is defined by the Administrator under RCRA.
    Deviation means any instance in which an affected source subject to 
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit; or
    (3) A deviation is not always a violation. The determination of 
whether a deviation constitutes a violation of the standard is up to 
the discretion of the entity responsible for enforcement of the 
standards.
    Dry scrubber means an add-on air pollution control system that 
injects dry alkaline sorbent (dry injection) or sprays an alkaline 
sorbent (spray dryer) to react with and neutralize acid gas in the 
exhaust stream forming a dry powder material. Sorbent injection systems 
in fluidized bed boilers are included in this definition.
    Electrostatic precipitator means an add-on air pollution control 
device used to capture particulate matter by charging the particles 
using an electrostatic field, collecting the particles using a grounded 
collecting surface, and transporting the particles into a hopper.
    Energy assessment means an in-depth assessment of a facility to 
identify immediate and long-term opportunities to save energy, focusing 
on the steam and process heating systems which involves a thorough 
examination of potential savings from energy efficiency improvements, 
waste minimization and pollution prevention, and productivity 
improvement.
    Equivalent means the following only as this term is used in Table 5 
to this subpart:
    (1) An equivalent sample collection procedure means a published 
voluntary consensus standard or practice (VCS) or EPA method that 
includes collection of a minimum of three composite fuel samples, with 
each composite consisting of a minimum of three increments collected at 
approximately equal intervals over the test period.
    (2) An equivalent sample compositing procedure means a published 
VCS or EPA method to systematically mix and obtain a representative 
subsample (part) of the composite sample.
    (3) An equivalent sample preparation procedure means a published 
VCS or EPA method that: Clearly states that the standard, practice or 
method is appropriate for the pollutant and the fuel matrix; or is 
cited as an appropriate sample preparation standard, practice or method 
for the pollutant in the chosen VCS or EPA determinative or analytical 
method.
    (4) An equivalent procedure for determining heat content means a 
published VCS or EPA method to obtain gross calorific (or higher 
heating) value.
    (5) An equivalent procedure for determining fuel moisture content 
means a published VCS or EPA method to obtain moisture content. If the 
sample analysis plan calls for determining mercury using an aliquot of 
the dried sample, then the drying temperature must be modified to 
prevent vaporizing this metal. On the other hand, if metals analysis is 
done on an ``as received'' basis, a separate aliquot can be dried to 
determine moisture content and the mercury concentration mathematically 
adjusted to a dry basis.
    (6) An equivalent mercury determinative or analytical procedure 
means a published VCS or EPA method that clearly states that the 
standard, practice, or method is appropriate for mercury and the fuel 
matrix and has a published detection limit equal or lower than the 
methods listed in Table 5 to this subpart for the same purpose.
    Fabric filter means an add-on air pollution control device used to 
capture particulate matter by filtering gas streams through filter 
media, also known as a baghouse.
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including the requirements of 40 
CFR part 60 and 40 CFR part 61, requirements within any applicable 
State implementation plan, and any permit requirements established 
under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
    Fuel type means each category of fuels that share a common name or 
classification. Examples include, but are not limited to, bituminous 
coal, subbituminous coal, lignite, anthracite, biomass, distillate oil, 
residual oil.
    Gaseous fuels includes, but is not limited to, natural gas, process 
gas, landfill gas, coal derived gas, refinery gas, and biogas.
    Gas-fired boiler includes any boiler that burns gaseous fuels not 
combined with any solid fuels, burns liquid fuel only during periods of 
gas curtailment, gas supply emergencies, or periodic testing on liquid 
fuel. Periodic testing of liquid fuel shall not exceed a combined total 
of 48 hours during any calendar year.
    Heat input means heat derived from combustion of fuel in a boiler 
and does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources such as 
gas turbines, internal combustion engines, kilns, etc.
    Industrial boiler means a boiler used in manufacturing, processing, 
mining, and refining or any other industry to provide steam, hot water, 
and/or electricity that does not combust solid waste, as that term is 
defined by the Administrator under RCRA.
    Institutional boiler means a boiler used in institutional 
establishments such as medical centers, research centers, and 
institutions of higher education to provide electricity, steam, and/or 
hot water that does not combust solid waste, as that term is defined by 
the Administrator under RCRA.
    Liquid fuel means petroleum, distillate oil, residual oil, any form 
of liquid fuel derived from petroleum, on-spec used oil, and biodiesel.
    Minimum sorbent flow rate means 90 percent of the test average 
sorbent (or activated carbon) flow rate measured according to Table 6 
to this subpart during the most recent performance test demonstrating 
compliance with the applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath the earth's surface, of 
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society for 
Testing and Materials in ASTM D1835-03a, ``Standard Specification for 
Liquid Petroleum Gases'' (incorporated by reference, see Sec.  
63.14(b)).

[[Page 31932]]

    Oil subcategory includes any boiler that does not burn any solid 
fuel and burns any liquid fuel either alone or in combination with 
gaseous fuels. Gas boilers that burn liquid fuel during periods of gas 
curtailment, gas supply emergencies, or for periodic testing of liquid 
fuel are not included in this definition.
    Opacity means the degree to which emissions reduce the transmission 
of light and obscure the view of an object in the background.
    Particulate matter means any finely divided solid or liquid 
material, other than uncombined water, as measured by the test methods 
specified under this subpart, or an alternative method.
    Performance testing means the collection of data resulting from the 
execution of a test method used (either by stack testing or fuel 
analysis) to demonstrate compliance with a relevant emission standard.
    Period of natural gas curtailment or supply interruption means a 
period of time during which the supply of natural gas to an affected 
facility is halted for reasons beyond the control of the facility. An 
increase in the cost or unit price of natural gas does not constitute a 
period of natural gas curtailment or supply interruption.
    Qualified personnel mean specialists in evaluating energy systems, 
such as, those who have successfully completed the DOE Qualified 
Specialist program for all systems, Certified Energy Managers certified 
by the Association of Energy Engineers, or the equivalent.
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    Tune-up means adjustments made to a boiler in accordance with 
procedures supplied by the manufacturer (or an approved specialist) to 
optimize the combustion efficiency.
    Waste heat boiler means a device that recovers normally unused 
energy and converts it to usable heat. Waste heat boilers incorporating 
duct or supplemental burners that are designed to supply 50 percent or 
more of the total rated heat input capacity of the waste heat boiler 
are not considered waste heat boilers, but are considered boilers. 
Waste heat boilers are also referred to as heat recovery steam 
generators.
    Work practice standard means any design, equipment, work practice, 
or operational standard, or combination thereof, that is promulgated 
pursuant to section 112(h) of the CAA.
    As stated in Sec.  63.11201, you must comply with the following 
applicable emission limits:

          Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
------------------------------------------------------------------------
                                For the following    You must meet the
   If your boiler is in this     pollutants . . .    following emission
       subcategory . . .                                limits . . .
------------------------------------------------------------------------
1. New coal...................  a. Particulate     0.03 lb per MMBtu of
                                 Matter.            heat input.
                                b. Mercury.......  0.000003 lb per MMBtu
                                                    of heat input.
                                c. Carbon          310 ppm by volume on
                                 Monoxide.          a dry basis
                                                    corrected to 7
                                                    percent oxygen
                                                    (daily average).
2. New biomass................  a. Particulate     0.03 lb per MMBtu of
                                 Matter.            heat input.
                                b. Carbon          100 ppm by volume on
                                 Monoxide.          a dry basis
                                                    corrected to 7
                                                    percent oxygen
                                                    (daily average).
3. New oil....................  a. Particulate     0.03 lb per MMBtu of
                                 Matter.            heat input.
                                b. Carbon          1 ppm by volume on a
                                 Monoxide.          dry basis corrected
                                                    to 3 percent oxygen
                                                    (daily average).
4. Existing coal (units with    a. Mercury.......  0.000003 lb per MMBtu
 heat input capacity of 10      b. Carbon           of heat input.
 million Btu per hour or         Monoxide.         310 ppm by volume on
 greater).                                          a dry basis
                                                    corrected to 7
                                                    percent oxygen
                                                    (daily average).
5. Existing biomass (units      Carbon Monoxide..  160 ppm by volume on
 with heat input capacity of                        a dry basis
 10 million Btu per hour or                         corrected to 7
 greater).                                          percent oxygen
                                                    (daily average).
6. Existing oil (units with     Carbon Monoxide..  2 ppm by volume on a
 heat input capacity of 10                          dry basis corrected
 million Btu per hour or                            to 3 percent oxygen
 greater).                                          (daily average).
------------------------------------------------------------------------

    As stated in Sec. Sec.  63.11202 and 63.11203, you must comply with 
the following applicable work practice standards:

 Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
              Reduction Measures, and Management Practices
------------------------------------------------------------------------
     If your boiler is in this
         subcategory . . .            You must meet the following . . .
------------------------------------------------------------------------
1. Existing coal, biomass, or oil   a. Conduct a tune-up of the boiler
 (units with heat input capacity     biennially as specified in Sec.
 of less than 10 million Btu per     63.11222.
 hour).
2. Existing coal, biomass, or oil   Must have an energy assessment
 (units with heat input capacity     performed by qualified personnel
 of 10 million Btu per hour and      which includes:
 greater).
                                       (1) a visual inspection of the
                                        boiler system.
                                       (2) establish operating
                                        characteristics of the facility,
                                        energy system specifications,
                                        operating and maintenance
                                        procedures, and unusual
                                        operating constraints,
                                       (3) identify major energy
                                        consuming systems,
                                       (4) a review of available
                                        architectural and engineering
                                        plans, facility operation and
                                        maintenance procedures and logs,
                                        and fuel usage,
                                       (5) a list of major energy
                                        conservation measures,
                                       (6) the energy savings potential
                                        of the energy conservation
                                        measures identified,

[[Page 31933]]

                                       (7) a comprehensive report
                                        detailing the ways to improve
                                        efficiency, the cost of specific
                                        improvements, benefits, and the
                                        time frame for recouping those
                                        investments.
------------------------------------------------------------------------

    As stated in Sec.  63.11201, you must comply with the applicable 
operating limits:

 Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers with
                         Mercury Emission Limits
------------------------------------------------------------------------
If you demonstrate compliance with
applicable mercury emission limits  You must meet these operating limits
            using . . .                             . . .
------------------------------------------------------------------------
1. Fabric filter control..........  a. Maintain opacity to less than or
                                     equal to 10 percent opacity (daily
                                     block average); OR
                                    b. Install and operate a bag leak
                                     detection system according to Sec.
                                      63.11221 and operate the fabric
                                     filter such that the bag leak
                                     detection system alarm does not
                                     sound more than 5 percent of the
                                     operating time during each 6-month
                                     period.
2. Electrostatic precipitator       Maintain opacity to less than or
 control.                            equal to 10 percent opacity (daily
                                     block average).
3. Dry scrubber or carbon           Maintain the minimum sorbent or
 injection control.                  carbon injection rate at or above
                                     the operating levels established
                                     during the performance test that
                                     demonstrated compliance with the
                                     applicable emission limit for
                                     mercury.
4. Fuel analysis..................  Maintain the fuel type or fuel
                                     mixture (annual average) such that
                                     the mercury emission rates
                                     calculated according to Sec.
                                     63.11211(c) is less than the
                                     applicable emission limits for
                                     mercury.
------------------------------------------------------------------------

    As stated in Sec.  63.11212, you must comply with the following 
requirements for performance (stack) test for new affected sources:

    Table 4 to Subpart JJJJJJ of Part 63--Performance (Stack) Testing
                              Requirements
------------------------------------------------------------------------
  To conduct a performance
   test for the following        You must . . .          Using . . .
       pollutant . . .
------------------------------------------------------------------------
1. Particulate Matter.......  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASTM D6522-00
                                                     (IBR, see Sec.
                                                     63.14(b)), or ASME
                                                     PTC 19, Part
                                                     10(1981) (IBR, see
                                                     Sec.   63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 5 or 17
                               particulate matter    (positive pressure
                               emission              fabric filters must
                               concentration.        use Method 5D) in
                                                     appendix A to part
                                                     60 of this chapter.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb/  methodology in
                               MMBtu emission        appendix A to part
                               rates.                60 of this chapter.
2. Mercury..................  a. Select sampling    Method 1 in appendix
                               ports location and    A to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASTM D6522-00
                                                     (IBR, see Sec.
                                                     63.14(b)), or ASME
                                                     PTC 19, Part
                                                     10(1981)(IBR, see
                                                     Sec.   63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 29 in
                               mercury emission      appendix A to part
                               concentration.        60 of this chapter
                                                     or Method 101A in
                                                     appendix B to part
                                                     61 of this chapter
                                                     or ASTM Method
                                                     D6784-02 (IBR, see
                                                     Sec.   63.14(b)).
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb/  methodology in
                               MMBtu emission        appendix A to part
                               rates.                60 of this chapter.
3. Carbon Monoxide..........  a. Select the         Method 1 in appendix
                               sampling ports        A to part 60 of
                               location and the      this chapter.
                               number of traverse
                               points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.

[[Page 31934]]

                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A to part
                               concentrations of     60 of this chapter,
                               the stack gas.        or ASTM D6522-00
                                                     (IBR, see Sec.
                                                     63.14(b)), or ASME
                                                     PTC 19, Part
                                                     10(1981)(IBR, see
                                                     Sec.   63.14(i)).
                              d. Measure the        Method 4 in appendix
                               moisture content of   A to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 10, 10A, or
                               carbon monoxide       10 B in appendix A
                               emission              to part 60 of this
                               concentration.        chapter or ASTM
                                                     D6522-00 (IBR, see
                                                     Sec.   63.14(b).
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb/  methodology in
                               MMBtu emission        appendix A to part
                               rates.                60 of this chapter.
------------------------------------------------------------------------

    As stated in Sec.  63.11213, you must comply with the following 
requirements for fuel analysis testing for new affected sources:

    Table 5 to Subpart JJJJJJ of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
 To conduct a fuel analysis
 for the following pollutant     You must . . .          Using . . .
            . . .
------------------------------------------------------------------------
1. Mercury..................  a. Collect fuel       Procedure in Sec.
                               samples.              63.11213(c) or ASTM
                                                     D2234-D2234M-03[egr
                                                     ]\1\ (for coal)
                                                     (IBR, see Sec.
                                                     63.14(b)) or ASTM
                                                     D6323-98 (2003)
                                                     (for biomass) (IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              b. Compose fuel       Procedure in Sec.
                               samples.              63.11213(c) or
                                                     equivalent.
                              c. Prepare            SW-846-3050B (for
                               composited fuel       solid samples) or
                               samples.              SW-846-3020A (for
                                                     liquid samples) or
                                                     ASTM D2013-04 (for
                                                     coal) (IBR, see
                                                     Sec.   63.14(b)) or
                                                     ASTM D5198-92
                                                     (2003) (for
                                                     biomass) (IBR, see
                                                     Sec.   63.14(b)) or
                                                     equivalent.
                              d. Determine heat     ASTM D5865-04 (for
                               content of the fuel   coal) (IBR, see
                               type.                 Sec.   63.14(b)) or
                                                     ASTM E711-87 (1996)
                                                     (for biomass) (IBR,
                                                     see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              e. Determine          ASTM D3173-03 (IBR,
                               moisture content of   see Sec.
                               the fuel type.        63.14(b)) or ASTM
                                                     E871-82 (1998)
                                                     (IBR, see Sec.
                                                     63.14(b)) or
                                                     equivalent.
                              f. Measure mercury    ASTM D6722-01 (for
                               concentration in      coal) (IBR, see
                               fuel sample.          Sec.   63.14(b)) or
                                                     SW-846-7471A (for
                                                     solid samples) or
                                                     SW-846 7470A (for
                                                     liquid samples) or
                                                     equivalent.
                              g. Convert
                               concentrations into
                               units of lb/MMBtu
                               of heat content.
------------------------------------------------------------------------

    As stated in Sec.  63.11235, you must comply with the applicable 
General Provisions according to the following:

     Table 6 to Subpart JJJJJJ of Part 63--Applicability of General
                      Provisions to Subpart JJJJJJ
------------------------------------------------------------------------
                                                      Applies to subpart
            Citation                    Subject             JJJJJJ
------------------------------------------------------------------------
Sec.   63.1.....................  Applicability.....  Yes.
Sec.   63.2.....................  Definitions.......  Yes.
Sec.   63.3.....................  Units and           Yes.
                                   Abbreviations.
Sec.   63.4.....................  Prohibited          Yes.
                                   Activities and
                                   Circumvention.
Sec.   63.5.....................  Preconstruction     No.
                                   Review and
                                   Notification
                                   Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),    Compliance with     Yes.
 (b)(7), (c), (f)(2)-(3), (g),     Standards and
 (i), (j).                         Maintenance
                                   Requirements.
Sec.   63.6(e)(1), (e)(3),        Startup, shutdown,  No. Standards
 (f)(1), and (h).                  and malfunction     apply at all
                                   requirements and    times, including
                                   Opacity/Visible     during startup,
                                   Emission Limits.    shutdown, and
                                                       malfunction
                                                       events.
Sec.   63.7(a), (b), (c), (d),    Performance         Yes.
 (e)(2)-(e)(9), (f), (g), and      Testing
 (h).                              Requirements.
Sec.   63.7(e)(1)...............  Conditions for      No. Subpart DDDDD
                                   conducting          specifies
                                   performance tests.  conditions for
                                                       conducting
                                                       performance tests
                                                       at Sec.
                                                       63.11210.
Sec.   63.8.....................  Monitoring          Yes.
                                   Requirements.

[[Page 31935]]

Sec.   63.9.....................  Notification        Yes. Subpart
                                   Requirements.       JJJJJJ requires
                                                       submission of
                                                       Notification of
                                                       Compliance Status
                                                       within 120 days
                                                       of compliance
                                                       date unless a
                                                       performance test
                                                       is required.
Sec.   63.10(a), (b)(1),          Recordkeeping and   Yes.
 (b)(2)(i)-(iii), (b)(2)(vi)-      Reporting
 (xiv), (c)(1)-(c)(14), (d)(1)-    Requirements.
 (2), and (f).
Sec.   63.10(b)(2)(iv)-(v),       ..................  No, Subpart JJJJJJ
 (b)(3), (d)(3)-(5), and (e).                          requires
                                                       submission on an
                                                       annual basis.
Sec.   63.10(c)(15).............  Allows use of SSM   No.
                                   plan.
Sec.   63.11....................  Control Device      No.
                                   Requirements.
Sec.   63.12....................  State Authority     Yes.
                                   and Delegation.
Sec.   63.13-63.16..............  Addresses,          Yes.
                                   Incorporation by
                                   Reference,
                                   Availability of
                                   Information,
                                   Performance Track
                                   Provisions.
Sec.   63.1(a)(5), (a)(7)-        Reserved..........  No.
 (a)(9), (b)(2), (c)(3)-(4),
 (d), 63.6(b)(6), (c)(3),
 (c)(4), (d), (e)(2),
 (e)(3)(ii), (h)(3), (h)(5)(iv),
 63.8(a)(3), 63.9(b)(3), (h)(4),
 63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------

[FR Doc. 2010-10832 Filed 6-3-10; 8:45 am]
BILLING CODE 6560-50-P