[Federal Register Volume 75, Number 107 (Friday, June 4, 2010)]
[Proposed Rules]
[Pages 32006-32073]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-10827]



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Part V





Environmental Protection Agency





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40 CFR Part 63



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

  Federal Register / Vol. 75 , No. 107 / Friday, June 4, 2010 / 
Proposed Rules  

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-9148-5]
RIN 2060-AG69


National Emission Standards for Hazardous Air Pollutants for 
Major Sources: Industrial, Commercial, and Institutional Boilers and 
Process Heaters

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: On September 13, 2004, under authority of section 112 of the 
Clean Air Act, EPA promulgated national emission standards for 
hazardous air pollutants for new and existing industrial/commercial/
institutional boilers and process heaters. On June 19, 2007, the United 
States Court of Appeals for the District of Columbia Circuit vacated 
and remanded the national emission standards for hazardous air 
pollutants for industrial/commercial/institutional boilers and process 
heaters.
    In response to the court's vacatur and remand, this action would 
require all major sources to meet hazardous air pollutants emissions 
standards reflecting the application of the maximum achievable control 
technology. The proposed rule would protect air quality and promote 
public health by reducing emissions of the hazardous air pollutants 
listed in section 112(b)(1) of the Clean Air Act.
    We are also proposing that existing major source facilities with an 
affected boiler undergo an energy assessment on the boiler system to 
identify cost-effective energy conservation measures.

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

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by one of the following methods:
     http://www.regulations.gov. Follow the instructions for 
submitting comments.
     http://www.epa.gov/oar/docket.html. Follow the 
instructions for submitting comments on the EPA Air and Radiation 
Docket Web site.
     E-mail: Comments may be sent by electronic mail (e-mail) 
to [email protected], Attention Docket ID No. EPA-HQ-OAR-2002-
0058.
     Fax: Fax your comments to: (202) 566-9744, Docket ID No. 
EPA-HQ-OAR-2002-0058.
     Mail: Send your comments to: EPA Docket Center (EPA/DC), 
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058. 
Please include a total of two copies. In addition, please mail a copy 
of your comments on the information collection provisions to the Office 
of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 
725 17th St., NW., Washington, DC 20503.
     Hand Delivery or Courier: Deliver your comments to: EPA 
Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW., 
Washington, DC 20460. Such deliveries are only accepted during the 
Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holiday), and special arrangements 
should be made for deliveries of boxed information.
    Instructions: All submissions must include agency name and docket 
number or Regulatory Information Number (RIN) for this rulemaking. All 
comments will be posted without change and may be made available online 
at http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
confidential business information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through http://www.regulations.gov, your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses.
    Public Hearing: We will hold a public hearing concerning this 
proposed rule on June 21, 2010. Persons interested in presenting oral 
testimony at the hearing should contact Ms. Pamela Garrett, Energy 
Strategies Group, at (919) 541-7966 by June 14, 2010. The public 
hearing will be held in the Washington DC area at a location and time 
that will be posted at the following Web site: http://www.epa.gov/airquality/combustion. Please refer to this Web site to confirm the 
date of the public hearing as well. If no one requests to speak at the 
public hearing by June 14, 2010 then the public hearing will be 
cancelled and a notification of cancellation posted on the following 
Web site: http://www.epa.gov/airquality/combustion.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy 
form. Publicly available docket materials are available either 
electronically in http://www.regulations.gov or in hard copy at the EPA 
Docket Center, Room 3334, 1301 Constitution Ave., NW., Washington, DC. 
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Brian Shrager, Energy Strategies 
Group, Sector Policies and Programs Division, (D243-01), Office of Air 
Quality Planning and Standards, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711; Telephone number: (919) 
541-7689; Fax number (919) 541-5450; E-mail address: 
[email protected].

SUPPLEMENTARY INFORMATION:  The information presented in this preamble 
is organized as follows:

I. General Information
    A. Does this action apply to me?

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    B. What should I consider as I prepare my comments to EPA?
    C. Where can I get a copy of this document?
    D. When would a public hearing occur?
II. Background Information
    A. What is the statutory authority for the proposed rule?
    B. Summary of the Natural Resources Defense Council v. EPA 
Decision
    C. Summary of Other Related Court Decisions
    D. EPA's Response to the Vacatur
    E. What is the relationship between the proposed rule and other 
combustion rules?
    F. What are the health effects of pollutants emitted from 
industrial/commercial/institutional boilers and process heaters?
III. Summary of the Proposed Rule
    A. What source categories are affected by the proposed rule?
    B. What is the affected source?
    C. Does the proposed rule apply to me?
    D. What emission limitations and work practice standards must I 
meet?
    E. What are the startup, shutdown, and malfunction (SSM) 
requirements?
    F. What are the testing and initial compliance requirements?
    G. What are the continuous compliance requirements?
    H. What are the notification, recordkeeping and reporting 
requirements?
I. Submission of Emissions Test Results to EPA
IV. Rationale for the Proposed Rule
    A. How did EPA determine which sources would be regulated under 
the proposed rule?
    B. How did EPA select the format for the proposed rule?
    C. How did EPA determine the proposed emission limitations for 
existing units?
    D. How did EPA determine the MACT floor for existing units?
    E. How did EPA consider beyond-the-floor for existing units?
    F. Should EPA consider different subcategories for solid fuel 
boilers and process heaters?
    G. How did EPA determine the proposed emission limitations for 
new units?
    H. How did EPA determine the MACT floor for new units?
    I. How did EPA consider beyond-the-floor for new units?
    J. What other compliance alternatives were considered?
    K. How did we select the compliance requirements?
    L. What alternative compliance provisions are being proposed?
    M. How did EPA determine compliance times for the proposed rule?
    N. How did EPA determine the required records and reports for 
this proposed rule?
    O. How does the proposed rule affect permits?
    P. Alternative Standard for Consideration
V. Impacts of the Proposed Rule
    A. What are the air impacts?
    B. What are the water and solid waste impacts?
    C. What are the energy impacts?
    D. What are the control costs?
    E. What are the economic impacts?
    F. What are the social costs and benefits of the proposed rule?
VI. Public Participation and Request for Comment
VII. Relationship of the Proposed Action to Section 112(c)(6) of the 
CAA
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866, Regulatory Planning and Review
    B. Executive Order 13132, Federalism
    C. Executive Order 13175, Consultation and Coordination With 
Indian Tribal Governments
    D. Executive Order 13045, Protection of Children From 
Environmental Health Risks and Safety Risks
    E. Unfunded Mandates Reform Act of 1995
    F. Regulatory Flexibility Act as Amended by the Small Business 
Regulatory Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C. 
601 et seq.
    G. Paperwork Reduction Act
    H. National Technology Transfer and Advancement Act
    I. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. General Information

A. Does this action apply to me?

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

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           Category              NAICS code \1\             Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or               211  Extractors of crude petroleum and natural gas.
 process heater as defined in
 the proposed rule.
                                             321  Manufacturers of lumber and wood products.
                                             322  Pulp and paper mills.
                                             325  Chemical manufacturers.
                                             324  Petroleum refineries, and manufacturers of coal products.
                                   316, 326, 339  Manufacturers of rubber and miscellaneous plastic products.
                                             331  Steel works, blast furnaces.
                                             332  Electroplating, plating, polishing, anodizing, and coloring.
                                             336  Manufacturers of motor vehicle parts and accessories.
                                             221  Electric, gas, and sanitary services.
                                             622  Health services.
                                             611  Educational services.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
action. To determine whether your facility, company, business, 
organization, etc., would be regulated by this action, you should 
examine the applicability criteria in 40 CFR 63.7485 of subpart DDDDD 
(National Emission Standards for Hazardous Air Pollutants (NESHAP) for 
Industrial, Commercial, and Institution Boilers and Process Heaters). 
If you have any questions regarding the applicability of this action to 
a particular entity, consult either the air permitting authority for 
the entity or your EPA regional representative as listed in 40 CFR 
63.13 of subpart A (General Provisions).

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

    Do not submit information containing CBI to EPA through http://www.regulations.gov or e-mail. Send or deliver information identified 
as CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S.

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Environmental Protection Agency, Research Triangle Park, North Carolina 
27711, Attention: Docket ID EPA-HQ-OAR-2002-0058. Clearly mark the part 
or all of the information that you claim to be CBI. For CBI information 
in a disk or CD-ROM that you mail to EPA, mark the outside of the disk 
or CD-ROM as CBI and then identify electronically within the disk or 
CD-ROM the specific information that is claimed as CBI. In addition to 
one complete version of the comment that includes information claimed 
as CBI, a copy of the comment that does not contain the information 
claimed as CBI must be submitted for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2.

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

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

D. When would a public hearing occur?

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

II. Background Information

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

    Section 112(d) of the Clean Air Act (CAA) requires EPA to set 
emissions standards for hazardous air pollutants (HAP) emitted by major 
stationary sources based on the performance of the maximum achievable 
control technology (MACT). The MACT standards for existing sources must 
be at least as stringent as the average emissions limitation achieved 
by the best performing 12 percent of existing sources (for which the 
Administrator has emissions information) or the best performing 5 
sources for source categories with less than 30 sources (CAA section 
112(d)(3)(A) and (B)). This level of minimum stringency is called the 
MACT floor. For new sources, MACT standards must be at least as 
stringent as the control level achieved in practice by the best 
controlled similar source (CAA section 112(d)(3)). EPA also must 
consider more stringent ``beyond-the-floor'' control options. When 
considering beyond-the-floor options, EPA must consider not only the 
maximum degree of reduction in emissions of HAP, but must take into 
account costs, energy, and nonair environmental impacts when doing so.
    CAA section 112(c)(6) requires EPA to list categories and 
subcategories of sources assuring that sources accounting for not less 
than 90 percent of the aggregate emissions of each such pollutant 
(alkylated lead compounds; polycyclic organic matter; 
hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8-
tetrachlorodibenzofurans; and 2,3,7,8-tetrachloroidibenzo-p-dioxin) are 
subject to standards under subsection 112(d)(2) or (d)(4). Standards 
established under CAA section 112(d)(2) must reflect the performance of 
MACT. ``Industrial Coal Combustion,'' ``Industrial Oil Combustion,'' 
``Industrial Wood/Wood Residue Combustion,'' ``Commercial Coal 
Combustion,'' ``Commercial Oil Combustion,'' and ``Commercial Wood/Wood 
Residue Combustion'' are listed as source categories for regulation 
pursuant to CAA section 112(c)(6) due to emissions of polycyclic 
organic matter (POM) and mercury (63 FR 17838, 17848, April 10, 1998). 
In the documentation for the 112(c)(6) listing, the commercial fuel 
combustion categories included institutional fuel combustion (``1990 
Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,'' 
April 1998).
    CAA section 129(a)(1)(A) requires EPA to establish specific 
performance standards, including emission limitations, for ``solid 
waste incineration units'' generally, and, in particular, for ``solid 
waste incineration units combusting commercial or industrial waste'' 
(section 129(a)(1)(D)). Section 129 defines ``solid waste incineration 
unit'' as ``a distinct operating unit of any facility which combusts 
any solid waste material from commercial or industrial establishments 
or the general public.'' Section 129(g)(1). Section 129 also provides 
that ``solid waste'' shall have the meaning established by EPA pursuant 
to its authority under the Resource Conservation and Recovery Act. 
Section 129(g)(6).
    In Natural Resources Defense Council v. EPA, 489 F. 3d 1250, 1257-
61 (DC Cir. 2007), the court vacated the Commercial and Industrial 
Solid Waste Incineration (CISWI) Definitions Rule, 70 FR 55568 
(September 22, 2005), which EPA issued pursuant to CAA section 
129(a)(1)(D). In that rule, EPA defined the term ``commercial or 
industrial solid waste incineration unit'' to mean a combustion unit 
that combusts ``commercial or industrial waste.'' The rule defined 
``commercial or industrial waste'' to mean waste combusted at a unit 
that does not recover thermal energy from the combustion for a useful 
purpose. Under these definitions, only those units that combusted 
commercial or industrial waste and were not designed to, or did not 
operate to, recover thermal energy from the combustion would be subject 
to section 129 standards. The District of Columbia Circuit (DC Circuit) 
rejected the definitions contained in the CISWI Definitions Rule and 
interpreted the term ``solid waste incineration unit'' in CAA section 
129(g)(1) ``to unambiguously include among the incineration units 
subject to its standards any facility that combusts any commercial or 
industrial solid waste material at all--subject to the four statutory 
exceptions identified in [CAA section 129(g)(1).]'' NRDC v. EPA, 489 
F.3d 1250, 1257-58.
    CAA section 129 covers any facility that combusts any solid waste; 
CAA section 112(g)(6) directs the Agency to the Resource Conservation 
and Recovery Act (RCRA) in terms of the definition of solid waste. The 
Agency is in the process of defining solid waste for purposes of 
Subtitle D of RCRA. EPA initiated a rulemaking to define which 
secondary materials are ``solid waste'' for purposes of subtitle D 
(nonhazardous waste) of RCRA when burned in a combustion unit. (See 
Advance Notice of Proposed Rulemaking (74 FR 41, January 2, 2009) 
soliciting comment on whether certain secondary materials used as 
alternative fuels or ingredients are solid wastes within the meaning of 
Subtitle D of RCRA.) If a unit combusts solid waste, it is subject to 
CAA section 129 of the Act, unless it falls within one of the four 
specified exceptions in CAA section 129(g).
    The solid waste definitional rulemaking under RCRA is being 
proposed in a parallel action and is

[[Page 32009]]

relevant to this proceeding because some industrial, commercial, or 
institutional boilers and process heaters combust secondary materials 
as alternative fuels. If industrial, commercial, or institutional 
boilers or process heaters combusts secondary materials that are solid 
waste under the proposed definitional rule, those units would be 
subject to section 129. The units subject to this rule include those 
industrial, commercial, or institutional boilers and process heaters 
that do not combust solid waste. EPA recognizes that it has imperfect 
information on the exact nature of the secondary materials which 
boilers and process heaters combust, including, for example, how much 
processing of such materials occurs, if any. We nevertheless used the 
information currently available to the Agency to determine which 
materials are solid waste and, therefore, subject to CAA section 129, 
and which are not solid waste and, therefore, subject to CAA section 
112.

B. Summary of the Natural Resources Defense Council v. EPA Decision

    On September 13, 2004, EPA issued the NESHAP for Industrial, 
Commercial, and Institutional Boilers and Process Heaters (40 CFR 
55218) (the Boiler MACT). We identified 18 subcategories of boilers and 
process heaters emitting four different types of HAPs. See 69 FR 
55,223-24. EPA set out to establish the MACT floor for each subcategory 
emitting each HAP according to the effectiveness of various add-on 
technologies. (See 68 FR 1660, 1674, Jan. 13, 2003 (proposed rule).) 
Applying this methodology, EPA set 25 numerical emission standards. The 
2004 final rule established emission limitations for particulate matter 
(PM), as a surrogate for non-mercury HAP metals, mercury, and hydrogen 
chloride (HCl), as a surrogate for acid gas HAP, for existing large 
solid fuel-fired sources only. For the remaining 47 boiler subcategory/
HAP emissions, EPA determined that the appropriate MACT floor was ``no 
emissions reduction'' because ``the best-performing sources were not 
achieving emissions reductions through the use of an emission control 
system and there were no other appropriate methods by which boilers and 
process heaters could reduce HAP emissions.'' (69 FR 55,233.) 
Accordingly, we established no standards. In addition, we set risk-
based standards, also known as health-based compliance alternatives, as 
alternatives to the MACT-based standards for hydrogen chloride and 
manganese.
    EPA issued emissions standards for CISWI units on December 1, 2000, 
and as part of that rulemaking, defined the term ``commercial and 
industrial waste'' to mean solid waste combusted in an enclosed device 
using controlled flame combustion without energy recovery that is a 
distinct operating unit of any commercial or industrial facility. In 
response to a petition for reconsideration, EPA filed a motion for 
voluntary remand, which the court granted on September 6, 2001. On 
remand, EPA solicited comments on the CISWI Rule's definitions of 
``solid waste,'' ``commercial and industrial waste'' and ``CISWI 
unit.'' On September 22, 2005, EPA issued the CISWI Definitions Rule, 
which contained definitions that were substantively the same as those 
issued before reconsideration. In particular, the 2005 CISWI 
Definitions Rule defined ``commercial or industrial waste'' to include 
only waste that is combusted at a facility that cannot or does not use 
a process that recovers thermal energy from the combustion for a useful 
purpose.
    EPA received separate petitions from environmental groups, 
industry, and municipalities seeking judicial review of the NESHAP for 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
(Boiler MACT) as well as amendments to definitional terms in the 
Standards of Performance for New Stationary Sources and Emission 
Guidelines for Existing Sources: Commercial and Industrial Solid Waste 
Incineration Units (CISWI Definitions Rule), promulgated pursuant to 
CAA section 129. The environmental organizations challenged the CISWI 
Definitions Rule on the ground that its definition of ``commercial or 
industrial waste'' was inconsistent with the plain language of CAA 
section 129 and therefore impermissibly constricted the class of 
``solid waste incineration unit[s]'' that were subject to the emission 
standards of the CISWI Rule. The environmental groups also challenged 
specific emission standards that EPA promulgated in the Boiler MACT and 
EPA's methodology for setting them. The municipalities--the American 
Municipal Power-Ohio, Inc. and six of its members, the cities of Dover, 
Hamilton, Orrville, Painesville, Shelby and St. Mary's--challenged the 
Boiler MACT on the grounds that EPA failed to comply with the 
requirements of the Regulatory Flexibility Act (RFA) and that the 
standards as applied to small municipal utilities are unlawful.
    As explained further below, the Court concluded that EPA's 
definition of ``commercial or industrial waste,'' as incorporated in 
the definition of ``commercial and industrial solid waste incineration 
unit'' (CISWI unit), was inconsistent with the plain language of CAA 
section 129 and that the CISWI Definitions Rule must, therefore, be 
vacated. The Court also vacated and remanded the Boiler MACT, finding 
that the Boiler MACT must be substantially revised as a consequence of 
the vacatur and remand of the CISWI Definitions Rule.
    In its decision, the Court agreed with the environmental 
petitioners that EPA's definition of ``commercial or industrial 
waste,'' as incorporated in the definition of CISWI units, conflicted 
with the plain language of CAA section 129(g)(1). That provision 
defines ``solid waste incineration unit'' to mean ``any facility which 
combusts any solid waste material'' from certain types of 
establishments, with four specific exclusions. The Court stated that, 
based on the use of the term ``any'' and the specific exclusions for 
only certain types of facilities from the definition of ``solid waste 
incineration unit,'' CAA section 129 unambiguously includes among the 
incineration units subject to its standards any facility that combusts 
any commercial or industrial solid waste material at all--subject only 
to the four statutory exclusions. The Court held that the definitions 
EPA promulgated in the CISWI Definitions Rule constricted the plain 
language of CAA section 129(g)(1), because the CISWI Definitions Rule 
excluded from its universe operating units that combusted solid waste 
and were designed for or operating with energy recovery.
    Having determined that EPA's definition of ``commercial and 
industrial solid waste incineration unit'' conflicts with the plain 
meaning of CAA section 129 and must, therefore, be vacated, the Court 
also vacated the Boiler MACT because it concluded that the Boiler MACT 
would need to be revised because the universe of boilers subject to its 
standards will be different once EPA revises the CISWI definitions rule 
consistent with the Court's opinion. The Court did not address 
petitioners' specific challenges to the Boiler MACT.

C. Summary of Other Related Court Decisions

    In March 2007, the DC Circuit Court issued an opinion (Sierra Club 
v. EPA, 479 F. 3d 875 (DC Cir. 2007) (Brick MACT)) vacating and 
remanding CAA section 112(d) MACT standards for the Brick and 
Structural Clay Ceramics source categories. Some key holdings in that 
case were:
     Floors for existing sources must reflect the average 
emission limitation achieved by the best-performing 12 percent of 
existing sources, not levels

[[Page 32010]]

EPA considers to be achievable by all sources (479 F. 3d at 880-81);
     EPA cannot set floors of ``no control.'' The Court 
reiterated its prior holdings, including National Lime Association, 
confirming that EPA must set floor standards for all HAP emitted by the 
major source, including those HAP that are not controlled by at-the-
stack control devices (479 F. 3d at 883);
     EPA cannot ignore non-technology factors that reduce HAP 
emissions. Specifically, the Court held that ``EPA's decision to base 
floors exclusively on technology even though non-technology factors 
affect emissions violates the Act.'' (479 F. 3d at 883)
    Based on the Brick MACT decision, we believe a source's performance 
resulting from the presence or absence of HAP in fuel materials must be 
accounted for in establishing floors; i.e., a low emitter due to low 
HAP fuel materials can still be a best performer. In addition, the fact 
that a specific level of performance is unintended is not a legal basis 
for excluding the source's performance from consideration. (National 
Lime Ass'n, 233 F. 3d at 640.)
    The Brick MACT decision also stated that EPA may account for 
variability in setting floors. However, the court found that EPA erred 
in assessing variability because it relied on data from the worst 
performers to estimate best performers' variability, and held that 
``EPA may not use emission levels of the worst performers to estimate 
variability of the best performers without a demonstrated relationship 
between the two.'' (479 F. 3d at 882.)
    The majority opinion in the Brick MACT case does not address the 
possibility of subcategorization to address differences in the HAP 
content of raw materials. However, in his concurring opinion Judge 
Williams stated that EPA's ability to create subcategories for sources 
of different classes, size, or type (CAA section 112(d)(1)) may provide 
a means out of the situation where the floor standards are achieved for 
some sources, but the same floors cannot be achieved for other sources 
due to differences in local raw materials whose use is essential. (Id. 
At 884-85.9)
    A second court opinion is also relevant to this proposal. In Sierra 
Club v. EPA, 551 F. 3d 1019 (DC Cir. 2008), the court vacated the 
portion of the regulations contained in the General Provisions which 
exempt major sources from MACT standards during periods of startup, 
shutdown and malfunction (SSM). The regulations (in 40 CFR 63.6(f)(1) 
and 63.6(h)(1)) provided that sources need not comply with the relevant 
CAA section 112(d) standard during SSM events and instead must 
``minimize emissions * * * to the greatest extent which is consistent 
with safety and good air pollution control practices.'' The vacated 
Boiler MACT did not contain specific provisions covering operation 
during SSM operating modes; rather it referenced the now-vacated 
exemption in the General Provisions. As a result of the court decision, 
we are addressing SSM in this proposed rulemaking. Discussion of this 
issue may be found later in this preamble.

D. EPA's Response to the Vacatur

    In response to the NRDC v. EPA mandate, we initiated an information 
collection effort entitled ``Information Collection Effort for 
Facilities with Combustion Units.'' This information collection was 
conducted by EPA's Office of Air and Radiation pursuant to CAA section 
114 to assist the Administrator in developing emissions standards for 
boilers/process heaters and CISWI units (collectively, ``combustion 
units'') pursuant to CAA sections 112(d) and 129. CAA section 114(a) 
states, in pertinent part:

    For the purpose of * * * (iii) carrying out any provision of 
this Chapter * * * (1) the Administrator may require any person who 
owns or operates any emission source * * * to- * * * (D) sample such 
emissions (in accordance with such procedures or methods, at such 
locations, at such intervals, during such periods and in such manner 
as the Administrator shall prescribe); (E) keep records on control 
equipment parameters, production variables or other indirect data 
when direct monitoring of emissions is impractical * * * (G) provide 
such other information as the Administrator may reasonably require * 
* *

    There were two components to the information collection. To obtain 
the information necessary to identify and categorize all combustion 
units potentially affected by the revised standards for boilers/process 
heaters and for CISWI units, the first component of the information 
collection effort solicited information from all potentially affected 
combustion units in the format of an electronic survey. The survey was 
submitted to the following facilities: (1) All facilities that 
submitted an initial notification for the 2004 boiler MACT standard, 
(2) all facilities identified by States as being subject to the 2004 
boiler MACT standard, and (3) facilities that are classified as a major 
source in their Title V permit that have a boiler or process heater 
listed in their permit. The survey was also sent to units covered by 
the 2000 CISWI emissions standards (40 CFR part 60 subpart CCCC) and to 
facilities that have incineration units (e.g., energy recovery units) 
that were listed as exempt under the 2000 CISWI standard. Each facility 
was required to complete the survey for all combustion units located at 
the facility. The information requested for each combustion unit 
included the unit design, operation, air pollution control data, the 
fuels/materials burned, and available emissions test data, continuous 
emission monitoring (CEM) data, fuel/material analysis data, and 
permitted and regulatory emission limits.
    The second component of the information collection request effort 
consisted of requiring the owners/operators of 169 boilers/process 
heaters to conduct emission testing for HAP and HAP surrogates. We 
first analyzed the results of the survey to determine if sufficient 
emissions data existed to develop emission standards under CAA sections 
112(d) for all types of boilers/process heaters, all types of materials 
combusted, and all HAP to be regulated. If data were not sufficient, 
then we selected pools of candidates to conduct emission testing. We 
submitted a list of candidates to stakeholders, including state, 
industry, and environmental stakeholders, who had an opportunity to 
comment on the technical feasibility, the least-cost impact of the 
testing program, and the appropriateness of the testing being 
requested. We then made a selection of test sites after taking into 
account stakeholder comments. The sites selected were required to 
conduct an outlet stack test, consisting of three runs, in accordance 
with EPA-approved protocols, for all of the following pollutants: PM 
(filterable, condensable, and PM2.5), dioxins/furans (D/F), 
hydrogen chloride/hydrogen fluoride, mercury, metals (including 
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, 
manganese, nickel, phosphorus, and selenium), carbon monoxide (CO), 
total hydrocarbons (THC), formaldehyde, oxides of nitrogen 
(NOX), and sulfur dioxide (SO2). Six facilities 
(two coal-fired, two biomass-fired, and two gas-fired boilers) were 
required to collect CEM data over 30 operating days using mobile CEM 
devices for CO, THC, and NOX. The owner/operator of each 
selected combustion unit was also required to collect and analyze, in 
accordance with acceptable procedures, the material(s) fed to the 
combustion unit during each stack test. The results of the stack tests 
and the analyses of materials combusted were required to be submitted 
to the Agency and are available in the docket and can be

[[Page 32011]]

downloaded at http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
    When we compared information on boilers and process heaters from 
facilities submitting initial notifications to comply with the vacated 
2004 Boiler MACT to the information gathering effort conducted for the 
2004 Boiler MACT, a large disparity was identified in the number of 
potentially affected units at major sources of HAP. Since the last 
combustion unit data gathering effort in 1996, many sources have shut 
down, others have selected to operate with a permit limit on their HAP 
emissions in order to avoid being subject to the Boiler MACT (i.e., 
synthetic area source), and some units have switched out older solid 
fuel units for newer equipment due to increased insurance and 
maintenance costs.
    Based on the definition of solid waste as set forth in a parallel 
proposed action, we revised the population of combustion units subject 
to CAA section 129 (because they combust solid waste) and the 
population of boilers and process heaters subject to CAA section 112 
(because they do not combust solid waste). We then used the new data to 
develop a revised NESHAP for boilers and process heaters under CAA 
section 112 and revised standards for incineration units covered by CAA 
section 129. Specifically, the data provide the Agency with updated 
information on the number of potentially affected units, available 
emission test data, and fuel/material analysis data to address 
variability. We are using all of the information before the 
Administrator to calculate the MACT floors, set emission limits, and 
evaluate the emission impacts of various regulatory options for these 
revised rulemakings.

E. What is the relationship between this proposed rule and other 
combustion rules?

    The proposed rule regulates source categories covering industrial 
boilers, institutional boilers, commercial boilers, and process 
heaters. These source categories potentially include combustion units 
that are already regulated by other MACT standards. Therefore, we are 
excluding from this proposed rule any boiler or process heater that is 
subject to regulation under other MACT standards.
    In 1986, EPA had codified new source performance standards (NSPS) 
for industrial boilers (40 CFR part 60, subparts Db and Dc) and revised 
portions of those standards in 1999 and 2006. The NSPS regulates 
emissions of PM, SO2, and NOX from boilers 
constructed after June 19, 1984. Sources subject to the NSPS will be 
subject to the final CAA section 112(d) standards for boilers and 
process heaters because it regulates sources of HAP while the NSPS do 
not. However, in developing the proposed rule, we considered the 
monitoring requirements, testing requirements, and recordkeeping 
requirements of the NSPS to avoid duplicating requirements.
    This proposed rule addresses the combustion of non-solid waste 
materials in boilers and process heaters. If an owner or operator of an 
affected source subject to these proposed standards were to start 
combusting a solid waste (as defined by the Administrator under RCRA), 
the affected source would cease to be subject to this action and would 
instead be subject to regulation under CAA section 129. A rulemaking 
under CAA section 129 is being proposed in a parallel action and is 
relevant to this action because it would apply to boilers and process 
heaters located at a major source that combust any solid waste. EPA is 
taking comment on whether a boiler or process heater could then opt 
back into regulation under this proposed rule by taking a federally 
enforceable restriction precluding the future combustion of any solid 
waste material.

F. What are the health effects of pollutants emitted from industrial/
commercial/institutional boilers and process heaters?

    This proposed rule protects air quality and promotes the public 
health by reducing emissions of some of the HAP listed in CAA section 
112(b)(1). As noted above, emissions data collected during development 
of the proposed rule show that hydrogen chloride emissions represent 
the predominant HAP emitted by industrial, commercial, and 
institutional (ICI) boilers, accounting for 61 percent of the total HAP 
emissions.\1\ ICI boilers and process heaters also emit lesser amounts 
of hydrogen fluoride, accounting for about 17 percent of total HAP 
emissions, and metals (arsenic, cadmium, chromium, mercury, manganese, 
nickel, and lead) accounting for about 6 percent of total HAP 
emissions. Organic HAP (formaldehyde, POM, acetaldehyde, benzene) 
account for about 15 percent of total HAP emissions. Exposure to these 
HAP, depending on exposure duration and levels of exposures, can be 
associated with a variety of adverse health effects. These adverse 
health effects may include, for example, irritation of the lung, skin, 
and mucus membranes, effects on the central nervous system, damage to 
the kidneys, and alimentary effects such as nausea and vomiting. We 
have classified two of the HAP as human carcinogens (arsenic and 
chromium VI) and four as probable human carcinogens (cadmium, lead, 
dioxins/furans, and nickel). We do not know the extent to which the 
adverse health effects described above occur in the populations 
surrounding these facilities. However, to the extent the adverse 
effects do occur, this proposed rule would reduce emissions and 
subsequent exposures.
---------------------------------------------------------------------------

    \1\ See Memorandum ``Methodology for Estimating Impacts from 
Industrial, Commercial, Institutional Boilers and Process Heaters at 
Major Sources of Hazardous Air Pollutant Emissions'' located in the 
docket.
---------------------------------------------------------------------------

III. Summary of This Proposed Rule

    This section summarizes the requirements proposed in today's 
action. Section IV below provides our rationale for the proposed 
requirements.

A. What source categories are affected by this proposed rule?

    This proposed rule affects industrial boilers, institutional 
boilers, commercial boilers, and process heaters. In this proposed 
rule, process heaters are defined as units in which the combustion 
gases do not directly come into contact with process material or gases 
in the combustion chamber (e.g., indirect fired). Boiler means an 
enclosed device using controlled flame combustion and having the 
primary purpose of recovering thermal energy in the form of steam or 
hot water.

B. What is the affected source?

    The affected source is: (1) The collection of all existing 
industrial, commercial, or institutional boilers or process heaters 
within a subcategory located at a major source facility that do not 
combust solid waste or (2) each new or reconstructed industrial, 
commercial, or institutional boiler or process heater located at a 
major source facility that do not combust solid waste, as that term is 
defined by the Administrator under RCRA.
    The affected source does not include boilers and process heaters 
that are subject to another standard under 40 CFR part 63 or a standard 
established under CAA section 129.

C. Does this proposed rule apply to me?

    This proposed rule applies to you if you own or operate a boiler or 
process heater at a major source meeting the requirements discussed 
previously in this preamble. A major source of HAP emissions is any 
stationary source or group of stationary sources located within a 
contiguous area and under common control that emits or has the

[[Page 32012]]

potential to emit considering controls 10 tons per year or more of any 
HAP or 25 tons per year or more of any combination of HAP.

D. What emission limitations and work practice standards must I meet?

    We are proposing the emission limits presented in Table 1 of this 
preamble. Emission limits were developed for new and existing sources 
for eleven subcategories, which we developed based on unit design.
    We are proposing that if your new or existing boiler or process 
heater burns at least 10 percent coal on an annual average heat input 
\2\ basis, the unit is in one of the coal subcategories. If your new or 
existing boiler or process heater burns at least 10 percent biomass, on 
an annual average heat input basis, and less than 10 percent coal, on 
an annual average heat input basis, we are proposing that the unit is 
in one of the biomass subcategories. If your new or existing boiler or 
process heater burns at least 10 percent liquid fuel (such as 
distillate oil, residual oil), and less than 10 percent solid fuel, on 
an annual heat input basis, we are proposing that the unit is in the 
liquid subcategory. If your new or existing boiler or process heater 
burns gaseous fuel and less than 10 percent, on an annual average heat 
input basis, of liquid or solid fuel, we are proposing that the unit is 
in one of the gas subcategories.
---------------------------------------------------------------------------

    \2\ Heat input means heat derived from combustion of fuel in a 
boiler or process heater and does not include the heat derived from 
preheated combustion air, recirculated flue gases or exhaust gases 
from other sources (such as stationary gas turbines, internal 
combustion engines, and kilns).

                            Table 1--Emission Limits for Boilers and Process Heaters
                                   [Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
                                                                                      Carbon         Dioxins/
                                   Particulate      Hydrogen                      monoxide (CO)   furans  (total
          Subcategory             matter  (PM)   chloride (HCl)   Mercury  (Hg)      (ppm @3%       TEQ)  (ng/
                                                                                     oxygen)           dscm)
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker..........           0.02         0.02           0.000003                50         0.003
Existing--Coal Fluidized Bed...           0.02         0.02           0.000003                30         0.002
Existing--Pulverized Coal......           0.02         0.02           0.000003                90         0.004
Existing--Biomass Stoker.......           0.02         0.006          0.0000009              560         0.004
Existing--Biomass Fluidized Bed           0.02         0.006          0.0000009              250         0.02
Existing--Biomass Suspension              0.02         0.006          0.0000009             1010         0.03
 Burner/Dutch Oven.............
Existing--Biomass Fuel Cells...           0.02         0.006          0.0000009              270         0.02
Existing--Liquid...............           0.004        0.0009         0.000004                 1         0.002
Existing--Gas (Other Process              0.05         0.000003       0.0000002                1         0.009
 Gases)........................
New--Coal Stoker...............           0.001        0.00006        0.000002                 7         0.003
New--Coal Fluidized Bed........           0.001        0.00006        0.000002                30         0.00003
New--Pulverized Coal...........           0.001        0.00006        0.000002                90         0.002
New--Biomass Stoker............           0.008        0.004          0.0000002              560         0.00005
New--Biomass Fluidized Bed.....           0.008        0.004          0.0000002               40         0.007
New--Biomass Suspension Burner/           0.008        0.004          0.0000002             1010         0.03
 Dutch Oven....................
New--Biomass Fuel Cells........           0.008        0.004          0.0000002              270         0.0005
New--Liquid....................           0.002        0.0004         0.0000003                1         0.002
New--Gas (Other Process Gases).           0.003        0.000003       0.0000002                1         0.009
----------------------------------------------------------------------------------------------------------------

    The proposed emission limits in the above table apply only to 
existing boilers and process heaters that have a designed heat input 
capacity of 10 million British thermal units (Btu) per hour or greater. 
Pursuant to CAA section 112(h), we are proposing a work practice 
standard for three particular classes of boilers and process heaters: 
Existing units that have a designed heat input capacity of less than 10 
million Btu per hour and new and existing units in the Gas 1 (natural 
gas/refinery gas) subcategory and in the metal process furnaces 
subcategory. The work practice standard being proposed for these 
boilers and process heaters would require the implementation of a tune-
up program as described in section III.F of this preamble.
    We are also proposing a beyond-the-floor standard for all existing 
major source facilities having affected boilers or process heaters that 
would require the performance of a one-time energy assessment, as 
described in section III.F of this preamble, by qualified personnel, on 
the affected boilers and facility to identify any cost-effective energy 
conservation measures.

E. What are the startup, shutdown, and malfunction (SSM) requirements?

    The United States Court of Appeals for the District of Columbia 
Circuit vacated portions of two provisions in EPA's CAA Section 112 
regulations governing the emissions of HAP during periods of startup, 
shutdown, and malfunction (SSM). Sierra Club v. EPA, 551 F.3d 1019 (DC 
Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010). Specifically, 
the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 
40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to 
as the ``General Provisions Rule,'' that EPA promulgated under section 
112 of the CAA. When incorporated into CAA Section 112(d) regulations 
for specific source categories, these two provisions exempt sources 
from the requirement to comply with the otherwise applicable CAA 
section 112(d) emission standard during periods of SSM.
    Consistent with Sierra Club v. EPA, EPA has established standards 
in this rule that apply at all times. EPA has attempted to ensure that 
we have not incorporated into proposed regulatory language any 
provisions that are inappropriate, unnecessary, or redundant in the 
absence of an SSM exemption. We are specifically seeking comment on 
whether there are any such provisions that we have inadvertently 
incorporated or overlooked. We also request comment on whether there 
are additional provisions that should be added to regulatory text in 
light of the absence of an SSM exemption and provisions related to the 
SSM exemption (such as the SSM plan requirement and SSM recordkeeping 
and reporting provisions).
    In establishing the standards in this rule, EPA has taken into 
account startup and shutdown periods and, for the

[[Page 32013]]

reasons explained below, has not established different standards for 
those periods. The standards that we are proposing are daily or monthly 
averages. Continuous emission monitoring data obtained from best 
performing units, and used in establishing the standards, include 
periods of startup and shutdown. Boilers, especially solid fuel-fired 
boilers, do not normally startup and shutdown more the once per day. 
Thus, we are not establishing a separate emission standard for these 
periods because startup and shutdown are part of their routine 
operations and, therefore, are already addressed by the standards. 
Periods of startup, normal operations, and shutdown are all predictable 
and routine aspects of a source's operation. We have evaluated whether 
it is appropriate to have the same standards apply during startup and 
shutdown as applied to normal operations.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is defined as a ``sudden, infrequent, and not 
reasonably preventable failure of air pollution control and monitoring 
equipment, process equipment or a process to operate in a normal or 
usual manner * * *'' (40 CFR 63.2). EPA has determined that 
malfunctions should not be viewed as a distinct operating mode and, 
therefore, any emissions that occur at such times do not need to be 
factored into development of CAA section 112(d) standards, which, once 
promulgated, apply at all times. It is reasonable to interpret section 
112(d) as not requiring EPA to account for malfunctions in setting 
emissions standards. For example, we note that Section 112 uses the 
concept of ``best performing'' sources in defining MACT, the level of 
stringency that major source standards must meet. Applying the concept 
of ``best performing'' to a source that is malfunctioning presents 
significant difficulties. The goal of best performing sources is to 
operate in such a way as to avoid malfunctions of their units.
    Moreover, even if malfunctions were considered a distinct operating 
mode, we believe it would be impracticable to take malfunctions into 
account in setting CAA section 112(d) standards for major source 
boilers and process heaters. As noted above, by definition, 
malfunctions are sudden and unexpected events and it would be difficult 
to set a standard that takes into account the myriad different types of 
malfunctions that can occur across all sources in the category. 
Moreover, malfunctions can vary in frequency, degree, and duration, 
further complicating standard setting.
    In the event that a source fails to comply with the applicable CAA 
section 112(d) standards as a result of a malfunction event, EPA would 
determine an appropriate response based on, among other things, the 
good faith efforts of the source to minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses to ascertain and rectify excess emissions. 
EPA would also consider whether the source's failure to comply with the 
CAA section 112(d) standard was, in fact, ``sudden, infrequent, not 
reasonably preventable'' and was not instead ``caused in part by poor 
maintenance or careless operation.'' 40 CFR 63.2 (definition of 
malfunction).

F. What are the testing and initial compliance requirements?

    We are proposing that the owner or operator of a new or existing 
boiler or process heater must conduct performance tests to demonstrate 
compliance with all applicable emission limits. Affected units would be 
required to conduct the following compliance tests where applicable:
    (1) Conduct initial and annual stack tests to determine compliance 
with the PM emission limits using EPA Method 5 or 17.
    (2) Conduct initial and annual stack tests to determine compliance 
with the mercury emission limits using EPA method 29 or ASTM-D6784-02 
(Ontario Hydro Method).
    (3) Conduct initial and annual stack tests to determine compliance 
with the HCl emission limits using EPA Method 26A or EPA Method 26 (if 
no entrained water droplets in the sample).
    (4) Use EPA Method 19 to convert measured concentration values to 
pound per million Btu values.
    (5) Conduct initial and annual test to determine compliance with 
the CO emission limits using either EPA Method 10 or a CO CEMS.
    (6) Conduct initial and annual test to determine compliance with 
the D/F emission limits using EPA Method 23.
    As part of the initial compliance demonstration, we are proposing 
that you monitor specified operating parameters during the initial 
performance tests that you would conduct to demonstrate compliance with 
the PM, mercury, D/F, and HCl emission limits. You would calculate the 
average parameter values measured during each test run over the three 
run performance test. The average of the three average values 
(depending on the parameter measured) for each applicable parameter 
would establish the site-specific operating limit. The applicable 
operating parameters for which operating limits would be required to be 
established are based on the emissions limits applicable to your unit 
as well as the types of add-on controls on the unit. The following is a 
summary of the operating limits that we are proposing to be established 
for the various types of the following units:
    (1) For boilers and process heaters without wet or dry scrubbers 
that must comply with an HCl emission limit, you must measure the 
average chlorine content level in the input fuel(s) during the HCl 
performance test. This is your maximum chlorine input operating limit.
    (2) For boilers and process heaters with wet scrubbers, you must 
measure pressure drop and liquid flow rate of the scrubber during the 
performance test, and calculate the average value for each test run. 
The average of the three test run averages establishes your minimum 
site-specific pressure drop and liquid flow rate operating levels. If 
different average parameter levels are measured during the mercury, PM 
and HCl tests, the highest of the average values becomes your site-
specific operating limit. If you are complying with an HCl emission 
limit, you must measure pH of the scrubber effluent during the 
performance test for HCl and determine the average for each test run 
and the average value for the performance test. This establishes your 
minimum pH operating limit.
    (3) For boilers and process heaters with sorbent injection, you 
would be required to measure the sorbent injection rate for each 
sorbent used during the performance tests for HCl, mercury, and D/F and 
calculate the average for each sorbent for each test run. The average 
of the three test run averages established during the performance tests 
would be your site-specific minimum sorbent injection rate operating 
limit. If different sorbents and/or injection rates are used during the 
mercury, HCl, and D/F tests, the average value for each sorbent becomes 
your site-specific operating limit.
    (4) For boilers and process heaters with fabric filters in 
combination with wet scrubbers, you must measure the pH, pressure drop, 
and liquid flowrate of the wet scrubber during the performance test and 
calculate the average value for each test run. The minimum test run 
average establishes your site-specific pH, pressure drop, and liquid 
flowrate operating limits for the wet scrubber. Furthermore, the fabric 
filter must be operated such that

[[Page 32014]]

the bag leak detection system alarm does not sound more than 5 percent 
of the operating time during any 6-month period unless a CEMS is 
installed to measure PM.
    (5) For boilers and process heaters with electrostatic 
precipitators (ESP) in combination with wet scrubbers, you must measure 
the pH, pressure drop, and liquid flow rate of the wet scrubber during 
the HCl performance test and you must measure the voltage and current 
of the ESP collection fields during the mercury and PM performance 
test. You would then be required to calculate the average value of 
these parameters for each test run. The average of the three test run 
averages would establish your site-specific minimum pH, pressure drop, 
and liquid flowrate operating limit for the wet scrubber and the 
minimum voltage and current operating limits for the ESP.
    (6) For boilers and process heaters that choose to demonstrate 
compliance with the mercury emission limit on the basis of fuel 
analysis, you would be required to measure the mercury content of the 
inlet fuel that was burned during the mercury performance test. This 
value is your maximum fuel inlet mercury operating limit.
    (7) For boilers and process heaters that choose to demonstrate 
compliance with the HCl emission limit on the basis of fuel analysis, 
you would be required to measure the chlorine content of the inlet fuel 
that was burned during the HCl performance test. This value is your 
maximum fuel inlet chlorine operating limit.
    These proposed operating limits would not apply to owners or 
operators of boilers or process heaters having a heat input capacity of 
less than 10 million Btu per hour (MMBtu/h) or boilers or process 
heaters of any size which combust natural gas or refinery gas, as 
discussed in section IV.D.3 of this preamble. Instead, we are proposing 
that owners or operators of such boilers and process heaters submit to 
the delegated authority or EPA, as appropriate, if requested, 
documentation that a tune-up meeting the requirements of the proposed 
rule was conducted. We are proposing that, to comply with the work 
practice standard, a tune-up procedure include the following:
    (1) Inspect the burner, and clean or replace any components of the 
burner as necessary,
    (2) Inspect the flame pattern and make any adjustments to the 
burner necessary to optimize the flame pattern consistent with the 
manufacturer's specifications,
    (3) Inspect the system controlling the air-to-fuel ratio, and 
ensure that it is correctly calibrated and functioning properly,
    (4) Minimize total emissions of CO consistent with the 
manufacturer's specifications,
    (5) Measure the concentration in the effluent stream of CO in 
ppmvd, before and after the adjustments are made,
    (6) Submit an annual report containing the concentrations of CO in 
the effluent stream in ppmvd, and oxygen in percent dry basis, measured 
before and after the adjustments of the boiler, a description of any 
corrective actions taken as a part of the combustion adjustment, and 
the type and amount of fuel used over the 12 months prior to the annual 
adjustment.
    Further, all owners or operators of major source facilities having 
boilers and process heaters subject to this rule would be required to 
submit to the delegated authority or EPA, as appropriate, documentation 
that an energy assessment was performed, by qualified personnel, and 
the cost-effective energy conservation measures indentified. The 
procedures for an energy assessment are:
    (1) Conduct a visual inspection of the boiler system.
    (2) Establish operating characteristics of the facility, energy 
system specifications, operating and maintenance procedures, and 
unusual operating constraints,
    (3) Identify major energy consuming systems,
    (4) Review available architectural and engineering plans, facility 
operation and maintenance procedures and logs, and fuel usage,
    (5) Identify a list of major energy conservation measures,
    (6) Determine the energy savings potential of the energy 
conservation measures identified, and
    (7) Prepare a comprehensive report detailing the ways to improve 
efficiency, the cost of specific improvements, benefits, and the time 
frame for recouping those investments.

G. What are the continuous compliance requirements?

    To demonstrate continuous compliance with the emission limitations, 
we are proposing following requirements:
    (1) For units combusting coal, biomass, or residual fuel oil (i.e., 
No 4, 5 or 6 fuel oil) with heat input capacities of less than 250 
million Btu per hour that do not use a wet scrubber, we are proposing 
that opacity levels be maintained to less than 10 percent (daily 
average) for existing and new units with applicable emission limits. 
Or, if the unit is controlled with a fabric filter, instead of 
continuous monitoring of opacity, the fabric filter must be 
continuously operated such that the bag leak detection system alarm 
does not sound more than 5 percent of the operating time during any 6-
month period (unless a PM CEMS is used).
    (2) For units combusting coal, biomass, or residual oil with heat 
input capacities of 250 million Btu per hour or greater, we are 
proposing that PM CEMS be installed and operated and that PM levels 
(monthly average) be maintained below the applicable PM limit.
    (3) For boilers and process heaters with wet scrubbers, we are 
proposing that you monitor pressure drop and liquid flow rate of the 
scrubber and maintain the 12-hour block averages at or above the 
operating limits established during the performance test. You must 
monitor the pH of the scrubber and maintain the 12-hour block average 
at or above the operating limit established during the performance test 
to demonstrate continuous compliance with the HCl emission limits.
    (4) For boilers and process heaters with dry scrubbers, we are 
proposing that you continuously monitor the sorbent injection rate and 
maintain it at or above the operating limits established during the 
performance tests.
    (5) For boilers and process heaters having heat input capacities of 
less than 250 million Btu per hour with an ESP in combination with a 
wet scrubber, we are proposing that you monitor the pH, pressure drop, 
and liquid flow rate of the wet scrubber and maintain the 12-hour block 
averages at or above the operating limits established during the HCl 
performance test and that you monitor the voltage and current of the 
ESP collection plates and maintain the 12-hour block averages at or 
above the operating limits established during the mercury or PM 
performance test.
    (6) For units that choose to comply with either the mercury 
emission limit or the HCl emission limit based on fuel analysis rather 
than on performance stack testing, we are proposing that you maintain 
daily fuel records that demonstrate that you burned no new fuels or 
fuels from a new supplier such that the mercury content or the chlorine 
content of the inlet fuel was maintained at or below your maximum fuel 
mercury content operating limit or your chlorine content operating 
limit set during the performance stack tests. If you plan to burn a new 
fuel, a fuel from a new mixture, or a new supplier's fuel that differs 
from what was burned during the initial performance tests, then you 
must

[[Page 32015]]

recalculate the maximum mercury input and/or the maximum chlorine input 
anticipated from the new fuels based on supplier data or own fuel 
analysis, using the methodology specified in Table 6 of this proposed 
rule. If the results of recalculating the inputs exceed the average 
content levels established during the initial test then, you must 
conduct a new performance test(s) to demonstrate continuous compliance 
with the applicable emission limit.
    (7) For all boilers and process heaters, we are proposing that you 
maintain daily records of fuel use that demonstrate that you have 
burned no materials that are considered solid waste.
    (8) For boilers and process heaters in any of the subcategories 
with heat input capacities greater than 100 MMBtu/h, we are proposing 
that you continuously monitor CO and maintain the average CO emissions 
at or below the applicable limit listed in Tables 1 or 2 of this 
proposed rule.
    If an owner or operator would like to use a control device other 
than the ones specified in this section to comply with this proposed 
rule, the owner/operator should follow the requirements in 40 CFR 
63.8(f), which presents the procedure for submitting a request to the 
Administrator to use alternative monitoring.

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

    All new and existing sources would be required to comply with 
certain requirements of the General Provisions (40 CFR part 63, subpart 
A), which are identified in Table 10 of this proposed rule. The General 
Provisions include specific requirements for notifications, 
recordkeeping, and reporting.
    Each owner or operator would be required to submit a notification 
of compliance status report, as required by Sec.  63.9(h) of the 
General Provisions. This proposed rule would require the owner or 
operator to include in the notification of compliance status report 
certifications of compliance with rule requirements.
    Semiannual compliance reports, as required by Sec.  63.10(e)(3) of 
subpart A, would be required only for semiannual reporting periods when 
a deviation from any of the requirements in the rule occurred, or any 
process changes occurred and compliance certifications were 
reevaluated.
    This proposed rule would require records to demonstrate compliance 
with each emission limit and work practice standard. These 
recordkeeping requirements are specified directly in the General 
Provisions to 40 CFR part 63, and are identified in Table 10. Owners or 
operators of sources with units with heat input capacity of less than 
10 MMBtu/h or units combusting natural gas or refinery gas must keep 
records of the dates and the results of each required boiler tune-up.
    Records of either continuously monitored parameter data for a 
control device if a device is used to control the emissions or CEMS 
data would be required.
    We are proposing that you must keep the following records:
    (1) All reports and notifications submitted to comply with this 
proposed rule.
    (2) Continuous monitoring data as required in this proposed rule.
    (3) Each instance in which you did not meet each emission limit and 
each operating limit (i.e., deviations from this proposed rule).
    (4) Daily hours of operation by each source.
    (5) Total fuel use by each affected source electing to comply with 
an emission limit based on fuel analysis for each 30-day period along 
with a description of the fuel, the total fuel usage amounts and units 
of measure, and information on the supplier and original source of the 
fuel.
    (6) Calculations and supporting information of chlorine fuel input, 
as required in this proposed rule, for each affected source with an 
applicable HCl emission limit.
    (7) Calculations and supporting information of mercury fuel input, 
as required in this proposed rule, for each affected source with an 
applicable mercury emission limit.
    (8) A signed statement, as required in this proposed rule, 
indicating that you burned no new fuel type and no new fuel mixture or 
that the recalculation of chlorine input demonstrated that the new fuel 
or new mixture still meets chlorine fuel input levels, for each 
affected source with an applicable HCl emission limit.
    (9) A signed statement, as required in this proposed rule, 
indicating that you burned no new fuels and no new fuel mixture or that 
the recalculation of mercury fuel input demonstrated that the new fuel 
or new fuel mixture still meets the mercury fuel input levels, for each 
affected source with an applicable mercury emission limit.
    (10) A copy of the results of all performance tests, fuel analysis, 
opacity observations, performance evaluations, or other compliance 
demonstrations conducted to demonstrate initial or continuous 
compliance with this proposed rule.
    (11) A copy of your site-specific monitoring plan developed for 
this proposed rule as specified in 63 CFR 63.8(e), if applicable.
    We are also proposing to require that you submit the following 
reports and notifications:
    (1) Notifications required by the General Provisions.
    (2) Initial Notification no later than 120 calendar days after you 
become subject to this subpart.
    (3) Notification of Intent to conduct performance tests and/or 
compliance demonstration at least 60 calendar days before the 
performance test and/or compliance demonstration is scheduled.
    (4) Notification of Compliance Status 60 calendar days following 
completion of the performance test and/or compliance demonstration.
    (5) Compliance reports semi-annually.

I. Submission of Emissions Test Results to EPA

    The EPA must have performance test data to conduct effective 
reviews of CAA Section 112 and 129 standards, as well as for many other 
purposes including compliance determinations, emissions factor 
development, and annual emissions rate determinations. In conducting 
these required reviews, we have found it ineffective and time consuming 
not only for us but also for regulatory agencies and source owners and 
operators to locate, collect, and submit emissions test data because of 
varied locations for data storage and varied data storage methods. One 
improvement that has occurred in recent years is the availability of 
stack test reports in electronic format as a replacement for cumbersome 
paper copies.
    In this action, we are taking a step to improve data accessibility. 
Owners and operators of boilers and process heaters will be required to 
submit to an EPA electronic database an electronic copy of reports of 
certain performance tests required under this rule. Data entry will be 
through an electronic emissions test report structure called the 
Electronic Reporting Tool (ERT) that will be used by the EPA staff as 
part of the emissions testing project. The ERT was developed with input 
from stack testing companies who generally collect and compile 
performance test data electronically and offices within State and local 
agencies which perform field test assessments. The ERT is currently 
available, and access to direct data submittal to EPA's electronic 
emissions database (WebFIRE) will become available by December 31, 
2011.
    The requirement to submit source test data electronically to EPA 
will not

[[Page 32016]]

require any additional performance testing and will apply to those 
performance tests conducted using test methods that are supported by 
ERT. The ERT contains a specific electronic data entry form for most of 
the commonly used EPA reference methods. The Web site listed at the end 
of this section contains a listing of the pollutants and test methods 
supported by ERT. In addition, when a facility submits performance test 
data to WebFIRE, there will be no additional requirements for emissions 
test data compilation. Moreover, we believe industry will benefit from 
development of improved emissions factors, fewer follow-up information 
requests, and better regulation development as discussed below. The 
information to be reported is already required for the existing test 
methods and is necessary to evaluate the conformance to the test 
method.
    One major advantage of submitting source test data through the ERT 
is that it provides a standardized method to compile and store much of 
the documentation required to be reported by this rule while clearly 
stating what testing information we require. Another important benefit 
of submitting these data to EPA at the time the source test is 
conducted is that it will substantially reduce the effort involved in 
data collection activities in the future. Specifically, because EPA 
would already have adequate source category data to conduct residual 
risk assessments or technology reviews, there would be fewer or less 
substantial data collection requests (e.g., CAA Section 114 letters). 
This results in a reduced burden on both affected facilities (in terms 
of reduced manpower to respond to data collection requests) and EPA (in 
terms of preparing and distributing data collection requests).
    State/local/Tribal agencies may also benefit in that their review 
may be more streamlined and accurate as the States will not have to re-
enter the data to assess the calculations and verify the data entry. 
Finally, another benefit of submitting these data to WebFIRE 
electronically is that these data will improve greatly the overall 
quality of the existing and new emissions factors by supplementing the 
pool of emissions test data upon which the emissions factor is based 
and by ensuring that data are more representative of current industry 
operational procedures. A common complaint we hear from industry and 
regulators is that emissions factors are outdated or not representative 
of a particular source category. Receiving and incorporating data for 
most performance tests will ensure that emissions factors, when 
updated, represent accurately the most current operational practices. 
In summary, receiving test data already collected for other purposes 
and using them in the emissions factors development program will save 
industry, State/local/Tribal agencies, and EPA time and money and work 
to improve the quality of emissions inventories and related regulatory 
decisions.
    As mentioned earlier, the electronic data base that will be used is 
EPA's WebFIRE, which is a Web site accessible through EPA's Technology 
Transfer Network (TTN). The WebFIRE Web site was constructed to store 
emissions test data for use in developing emissions factors. A 
description of the WebFIRE data base can be found at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
    The ERT will be able to transmit the electronic report through 
EPA's Central Data Exchange (CDX) network for storage in the WebFIRE 
data base. Although ERT is not the only electronic interface that can 
be used to submit source test data to the CDX for entry into WebFIRE, 
it makes submittal of data very straightforward and easy. A description 
of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert_tool.html.

IV. Rationale for This Proposed Rule

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

    This proposed rule regulates source categories covering industrial 
boilers, institutional and commercial boilers, and process heaters. 
These source categories potentially include combustion units that are 
already regulated by other MACT standards under CAA sections 112 or 
129. Therefore, we are excluding from this proposed rule any units that 
are subject to regulation in another MACT standard established under 
CAA section 112 or a standard established under CAA section 129.
    The CAA specifically requires that fossil fuel-fired steam 
generating units of more than 25 megawatts that produce electricity for 
sale (i.e., utility boilers) be reviewed separately by EPA. 
Consequently, this proposed rule would not regulate fossil fuel-fired 
utility boilers greater than 25 megawatts, but would regulate fossil 
fuel-fired units less than 25 megawatts and all utility boilers firing 
a non-fossil fuel that is not a solid waste.
    The scope of the process heater source category is limited to only 
indirect-fired units.\3\ Direct-fired units are covered in other MACT 
standards or rulemakings pertaining to industrial process operations. 
For example, lime kilns are covered by the Pulp and Paper NESHAP (40 
CFR part 63, subpart S). Indirect-fired process heaters are similar to 
boilers in fuel use, emissions, and applicable controls, and, 
therefore, it is appropriate for EPA to combine this listed source 
category of units with the listed source categories of industrial 
boilers and commercial/institutional boilers for purposes of developing 
emission standards.
---------------------------------------------------------------------------

    \3\ Indirect-fired process heaters are combustion devices in 
which the combustion gases do not directly come into contact with 
process materials.
---------------------------------------------------------------------------

    The proposed rule would not regulate hot water heaters, as defined 
in this proposed rule, because such units are not part of the listed 
source categories. Many industrial facilities have office buildings 
located onsite which use hot water heaters. Such hot water heaters, by 
their design and operation, could be considered boilers since hot water 
heaters meet the definition of a boiler as specified in the proposed 
rule, because they are enclosed devices that combust fuel for the 
purpose of recovery energy to heat water. However, hot water heaters 
are more appropriately described as residential-type boilers, not 
industrial, commercial, or institutional boilers because their output 
(i.e., hot water) is intended for personal use rather than for use in 
an industrial, commercial, or institutional process. Moreover, since 
hot water heaters generally are small and use natural gas as fuel, 
their emissions are negligible compared to the emissions from the 
industrial operations that make such facilities major sources, and 
compared to boilers that are used for industrial, commercial, or 
institutional purposes. However, the primary reason that we are 
excluding hot water heaters is that hot water heaters are not part of 
the listed source category. Consequently, we are including a definition 
of hot water heaters that includes fuel, size, pressure and temperature 
limitations that we believe are appropriate to distinguish between 
residential-type units and industrial, commercial, or institutional 
units.
    The CAA allows EPA to divide source categories into subcategories 
based on differences in class, type, or size. For example, differences 
between given types of units can lead to corresponding differences in 
the nature of emissions and the technical feasibility of applying 
emission control techniques. The design, operating, and emissions 
information that EPA has reviewed

[[Page 32017]]

indicates differences in unit design that distinguish different types 
of boilers. Data indicate that there are significant design and 
operational differences between units that burn coal, biomass, liquid, 
and gaseous fuels.
    Boiler systems are designed for specific fuel types and will 
encounter problems if a fuel with characteristics other than those 
originally specified is fired. While many boilers in the population 
data base are indicated to co-fire liquids or gases with solid fuels, 
in actuality most of these commonly use fuel oil or natural gas as a 
startup fuel only, and operate on solid fuel during the remainder of 
their operation. In contrast, some co-fired units are specifically 
designed to fire combinations of solids, liquids, and gases. Changes to 
the fuel type would generally require extensive changes to the fuel 
handling and feeding system (e.g., a stoker using wood as fuel would 
need to be redesigned to handle fuel oil or gaseous fuel). 
Additionally, the burners and combustion chamber would need to be 
redesigned and modified to handle different fuel types and account for 
increases or decreases in the fuel volume. In some cases, the changes 
may reduce the capacity and efficiency of the boiler or process heater. 
An additional effect of these changes would be extensive retrofitting 
needed to operate using a different fuel.
    The design of the boiler or process heater, which is dependent in 
part on the type of fuel being burned, impacts the degree of 
combustion. Boilers and process heaters emit a number of different 
types of HAP emissions. Organic HAP are formed from incomplete 
combustion and are influenced by the design and operation of the unit. 
The degree of combustion may be greatly influenced by three general 
factors: Time, turbulence, and temperature. On the other hand, the 
formation of fuel-dependent HAP (metals, mercury, and acid gases) is 
dependent upon the composition of the fuel. These fuel-dependent HAP 
emissions generally can be controlled by either changing the fuel 
property before combustion or by removing the HAP from the flue gas 
after combustion.
    We first examined the HAP emissions results to determine if 
subcategorization by unit design type was warranted. We concluded that 
the data were sufficient for determining that a distinguishable 
difference in performance exists based on unit design type. Therefore, 
because different types of units have different emission 
characteristics which may influence the feasibility of effectiveness of 
emission control, they should be regulated separately (i.e., 
subcategorized). Accordingly, we propose to subcategorize boilers and 
process heaters based on unit design in order to account for these 
differences in emissions and applicable controls.
    For the fuel-dependent HAP (metals, mercury, acid gases), we 
identified five basic unit types as subcategories. These are the 
following: (1) Units designed to burn coal, (2) units designed to burn 
biomass, (3) units designed to burn liquid fuel, (4) units designed to 
burn natural gas/refinery gas, and (5) units designed to burn other 
process gases. Within the basic unit types there are different designs 
and combustion systems that, while having a minor effect on fuel-
related HAP emissions, have a much larger effect on organic HAP 
emissions. Therefore, we decided to further subcategorize based on 
these different unit designs but only in proposing standards for 
organic HAP emissions. We have identified the following 11 
subcategories for organic HAP:

Pulverized coal units,
Stokers designed to burn coal,
Fluidized bed units designed to burn coal,
Stokers designed to burn biomass,
Fluidized bed units designed to burn biomass,
Suspension burners/Dutch Ovens designed to burn biomass,
Fuel Cells designed to burn biomass,
Units designed to burn liquid fuel,
Units designed to burn natural gas/refinery gas,
Units designed to burn other gases, and
Metal process furnaces.

    These subcategories are based on the primary fuel that the boiler 
or process heater is designed to burn. We are aware that some boilers 
burn a combination of fuel types or burn a different fuel type as a 
backup fuel if the primary fuel supply is curtailed. However, boilers 
are designed based on the primary fuel type (and perhaps to burn a 
backup fuel) and can encounter operational problems if another fuel 
type that was not considered in its design is fired at more than 10 
percent of the heat input to the boiler. Also, in some cases, a small 
amount of coal may be added to a biomass designed boiler to stabilize 
the combustion when the biomass has a higher moisture content than 
normal. In this case, it would not be appropriate to classify the 
boiler as being in one of the ``coal'' subcategories because the boiler 
design is such that it is constructed and operated to combust biomass, 
and could not combust primarily coal (without significant retrofitting 
or design changes). Therefore, we are proposing to define boilers and 
process heaters that burn at least 10 percent coal (on an annual heat 
input basis) as being in one of the coal subcategories. We are also 
proposing to define boilers and process heaters that burn at least 10 
percent biomass, and less than 10 percent coal (on an annual heat input 
basis) as being in one of the biomass subcategories. We are proposing 
to define boilers and process heaters that burn at least 10 percent 
liquid fuel, and less than 10 percent solid fuel (on an annual heat 
input basis) as being in the liquid subcategory. We are proposing to 
define boilers and process heaters that burn at least 90 percent 
natural gas and/or refinery gas (on an annual heat input basis) as 
being in the Gas 1 subcategory. This would ensure that each boiler and 
process heater is subject to emissions standards calculated on the 
basis of the best performing units with similar design and operation. 
The remaining boilers and process heaters, except for those described 
below would be in the Gas 2 subcategory.
    In addition, there is a certain class of natural gas-fired process 
heaters that are designed and operated differently compared to typical 
process heaters. A review of information gathered on process heaters 
used in the metal processing industries shows that these process 
heaters typically are designed with multiple burners that fire into 
individual combustion chambers. These individual burners are operated 
to cycle on and off to maintain the proper temperatures throughout the 
various zones of the process heater. Thus, due to their design, these 
process heaters rarely operate in a steady-state condition due to 
burners constantly starting up and shutting down. This results in 
emissions characteristics different from the process heaters used in 
other industries. The process heaters used in metal processing are 
natural gas-fired and include annealing furnaces, preheat furnaces, 
reheat furnaces, aging furnaces, and heat treat furnaces. Therefore, we 
propose to identify these metal processing process heaters (furnaces) 
as a separate eleventh subcategory.
    In summary, we have identified 11 subcategories of boilers and 
process heaters located at major sources.\4\
---------------------------------------------------------------------------

    \4\ See Memorandum ``Development of Baseline Emission Factors 
for Boilers and Process Heaters at Commercial, Industrial, and 
Institutional Facilities'' located in the docket.
---------------------------------------------------------------------------

B. How did EPA select the format for this proposed rule?

    This proposed rule includes numerical emission limits for PM, 
mercury, HCl, CO, and D/F. The selection of numerical emission limits 
as the format for this proposed rule

[[Page 32018]]

provides flexibility for the regulated community by allowing a 
regulated source to choose any control technology or technique to meet 
the emission limits, rather than requiring each unit to use a 
prescribed control method that may not be appropriate in each case.
    We are proposing numerical emission rate limits as a mass of 
pollutant emitted per heat energy input to the boiler or process heater 
for the fuel-related HAP. The most typical units for the limits are 
pounds of pollutant emitted per million Btu of heat input. The mass per 
heat input units are consistent with other Federal and many State 
boiler regulations \5\ and allows easy comparison between such 
requirements. Additionally, this proposed rule contains an option to 
monitor inlet chlorine and mercury content in the fuel to meet outlet 
emission rate limits. This option can only be done on a mass basis.
---------------------------------------------------------------------------

    \5\ For example, the new source performance standards for 
industrial, commercial, and institutional steam generating units (40 
CFR subpart Db) have emission limits for sulfur dioxide, nitrogen 
oxide, and PM in terms of pounds per million Btu.
---------------------------------------------------------------------------

    We are proposing outlet concentration as the format for the organic 
HAP. An outlet concentration limit for organic HAP would also be 
consistent with the format of other regulations.
    Boilers and process heaters can emit a wide variety of compounds, 
depending on the fuel burned. Because of the large number of HAP 
potentially present and the disparity in the quantity and quality of 
the emissions information available, EPA grouped the HAP into five 
categories: Mercury, non-mercury metallic HAP, inorganic HAP, non-
dioxin organic HAP, and D/F. The pollutants within each group have 
similar characteristics and can be controlled with the same techniques. 
For example, non-mercury metallic HAP can be controlled with PM 
controls. We chose to look at mercury separately from other metallic 
HAP due to its different chemical characteristics and its different 
control technology feasibility.
    Next, EPA identified compounds that could be used as surrogates for 
all the compounds in each pollutant category. For the non-mercury 
metallic HAP, we chose to use PM as a surrogate. Most, if not all, non-
mercury metallic HAP emitted from combustion sources will appear on the 
flue gas fly-ash. Therefore, the same control techniques that would be 
used to control the fly-ash PM will control non-mercury metallic HAP. 
PM was also chosen instead of specific metallic HAP because all fuels 
do not emit the same type and amount of metallic HAP but most generally 
emit PM that includes some amount and combination of metallic HAP. The 
use of PM as a surrogate will also eliminate the cost of performance 
testing to comply with numerous standards for individual non-mercury 
metals. Since non-mercury metallic HAP tend to be on small size 
particles (i.e., fine particle enrichment), we considered using 
PM2.5 as the surrogate, but we determined that PM 
(filterable) was the more appropriate surrogate for two reasons. First, 
the test method (OTM 27) for measuring PM2.5 is only 
applicable for use in exhaust stacks without entrained water droplets. 
Therefore, the test method (OTM 27) for measuring PM2.5 is 
not applicable for units equipped with wet scrubbers which will likely 
be necessary to achieve the proposed HCl emission limits. Second, based 
on the emission data obtained during EPA's information collection 
effort from units not equipped with wet scrubbers, the majority of the 
filterable PM emitted from units that are well controlled for PM is 
fine particulate (PM2.5). Thus, we are proposing to use PM 
(filterable), instead of PM2.5, as the surrogate for non-
mercury metals.
    For non-metallic inorganic HAP, EPA is proposing using HCl as a 
surrogate. The emissions test information available to EPA indicate 
that the primary non-metallic inorganic HAP emitted from boilers and 
process heaters are acid gases, with HCl present in the largest 
amounts. Other inorganic compounds emitted are found in much smaller 
quantities. Control technologies that reduce HCl also control other 
inorganic compounds such as chlorine and other acid gases. Thus, the 
best controls for HCl would also be the best controls for other 
inorganic HAP that are acid gases. Therefore, HCl is a good surrogate 
for inorganic HAP because controlling HCl will result in control of 
other inorganic HAP emissions.
    For organic HAP, we considered both THC and CO as a surrogate for 
non-dioxin organic HAP emitted from boilers and process heaters. CO has 
generally been used as a surrogate for organic HAP because CO is a good 
indicator of incomplete combustion and organic HAP are products of 
incomplete combustion. However, based on concerns that CO may not be an 
appropriate surrogate for D/F because, unlike other organic HAP, D/F 
can be formed outside the combustion unit, we are proposing to use CO 
as a surrogate for non-dioxin organic HAP. We are also proposing 
separate emission limits for D/F. For non-dioxin organic HAP, using CO 
as a surrogate is a reasonable approach because minimizing CO emissions 
will result in minimizing non-dioxin organic HAP. Methods used for the 
control of non-dioxin organic HAP emissions would be the same methods 
used to control CO emissions. These emission control methods include 
achieving good combustion or using an oxidation catalyst. Standards 
limiting emissions of CO will also result in decreases in non-dioxin 
organic HAP emissions (with the additional benefit of decreasing 
volatile organic compounds (VOC) emissions). Establishing emission 
limits for specific organic HAP (with the exception of D/F) would be 
impractical and costly. CO, which is less expensive to test for and 
monitor, is appropriate for use as a surrogate for non-dioxin organic 
HAP.
    The Agency recognizes that the level and distribution of organic 
HAP associated with CO emissions will vary from unit to unit. For 
example, the principal organic HAP emitted from coal-fired units is 
benzene, which accounts for about 20 percent of the organic HAP while 
the principal organic HAP emitted from biomass-fired units is 
formaldehyde, which accounts for 34 percent of the organic HAP.\6\ 
Limiting CO as a surrogate for only non-dioxin organic HAP will 
eliminate costs associated with speciating numerous compounds. The 
proposed standards establish separate emission limits for D/F because 
of the high toxicity associated with even low masses of these 
compounds.
---------------------------------------------------------------------------

    \6\ Based on emission factors reported on EPA webpage ``AP 42, 
Fifth Edition, Volume 1--Chapter 1: External Combustion Sources'' 
located at http://www.epa.gov/ttn/chief/ap42/ch01/index.html.
---------------------------------------------------------------------------

    THC could also be an appropriate surrogate for non-dioxin organic 
HAP because low THC also ensures good combustion efficiency and, thus, 
low organic HAP. However, we believe CO is preferable because many 
sources currently have CO CEMS. In addition, there are more CO emission 
data available for the various subcategories than THC emission data.

C. How did EPA determine the proposed emission limitations for existing 
units?

    All standards established pursuant to CAA section 112(d)(2) must 
reflect MACT, the maximum degree of reduction in emissions of air 
pollutants that the Administrator, taking into consideration the cost 
of achieving such emissions reductions, and any nonair quality health 
and environmental impacts and energy requirements, determined is 
achievable for each category. For existing sources, MACT cannot be less 
stringent than the average emission limitation achieved by the best 
performing 12 percent of existing

[[Page 32019]]

sources for categories and subcategories with 30 or more sources or the 
best performing 5 sources for subcategories with less than 30 sources. 
This requirement constitutes the MACT floor for existing boilers and 
process heaters. However, EPA may not consider costs or other impacts 
in determining the MACT floor. EPA must consider cost, nonair quality 
health and environmental impacts, and energy requirements in connection 
with any standards that are more stringent than the MACT floor (beyond-
the-floor controls).

D. How did EPA determine the MACT floors for existing units?

    EPA must consider available emissions information to determine the 
MACT floors. For each pollutant, we calculated the MACT floor for a 
subcategory of sources by ranking all the available emissions data from 
units within the subcategory from lowest emissions to highest 
emissions, and then taking the numerical average of the test results 
from the best performing (lowest emitting) 12 percent of sources.
    We first considered whether fuel switching would be an appropriate 
control option for sources in each subcategory. We considered the 
feasibility of fuel switching to other fuels used in the subcategory 
and to fuels from other subcategories. This consideration included 
determining whether switching fuels would achieve lower HAP emissions. 
A second consideration was whether fuel switching could be technically 
achieved by boilers and process heaters in the subcategory considering 
the existing design of boilers and process heaters. We also considered 
the availability of various types of fuel.
    After considering these factors, we determined that fuel switching 
was not an appropriate control technology for purposes of determining 
the MACT floor level of control for any subcategory. This decision was 
based on the overall effect of fuel switching on HAP emissions, 
technical and design considerations discussed previously in this 
preamble, and concerns about fuel availability.
    Based on the emission factors reported in EPA's Technology Transfer 
Network, we determined that while fuel switching from solid fuels to 
gaseous or liquid fuels would decrease PM and some metals emissions, 
emissions of some organic HAP (e,g., formaldehyde) would increase.\7\ 
This determination is discussed in the memorandum ``Development of Fuel 
Switching Costs and Emission Reductions for Industrial, Commercial, and 
Institutional Boilers and Process Heaters National Emission Standards 
for Hazardous Air Pollutants'' located in the docket.
---------------------------------------------------------------------------

    \7\ See EPA webpage ``AP 42, Fifth Edition, Volume 1--Chapter 1: 
External Combustion Sources'' located at http://www.epa.gov/ttn/chief/ap42/ch01/index.html.
---------------------------------------------------------------------------

    A similar determination was made when considering fuel switching to 
cleaner fuels within a subcategory. For example, the term ``clean 
coal'' refers to coal that is lower in sulfur content and not 
necessarily lower in HAP content. Data gathered by EPA also indicates 
that within specific coal types HAP content can vary significantly. 
Switching to a low sulfur coal may actually increase emissions of some 
HAP. Therefore, it is not appropriate for EPA to include fuel switching 
to a low sulfur coal as part of the MACT standards for boilers and 
process heaters. Fuel switching from coal to biomass would result in 
similar impacts on HAP emissions. While this would reduce metallic HAP 
emissions, it would likely increase emissions of organics based on 
information in the emissions database.
    Another factor considered was the availability of alternative fuel 
types. Natural gas pipelines are not available in all regions of the 
U.S., and natural gas is simply not available as a fuel for many 
industrial, commercial, and institutional boilers and process heaters. 
Moreover, even where pipelines provide access to natural gas, supplies 
of natural gas may not be adequate. For example, it is common practice 
in cities during winter months (or periods of peak demand) to 
prioritize natural gas usage for residential areas before industrial 
usage. Requiring boilers and process heaters to switch to natural gas 
would place an even greater strain on natural gas resources. 
Consequently, even where pipelines exist, some units would not be able 
to run at normal or full capacity during these times if shortages were 
to occur. Therefore, under any circumstances, there would be some units 
that could not comply with a requirement to switch to natural gas.
    Similar problems for fuel switching to biomass could arise. 
Existing sources burning biomass generally are combusting a recovered 
material from the manufacturing or agriculture process. Industrial, 
commercial, and institutional facilities that are not associated with 
the wood products industry or agriculture may not have access to a 
sufficient supply of biomass materials to replace their fossil fuel.
    As discussed previously in this preamble, there is a significant 
concern that switching fuels would be infeasible for sources designed 
and operated to burn specific fuel types. Changes in the type of fuel 
burned by a boiler or process heater (solid, liquid, or gas) may 
require extensive changes to the fuel handling and feeding system 
(e.g., a stoker using wood as fuel would need to be redesigned to 
handle fuel oil or gaseous fuel). Additionally, burners and combustion 
chamber designs are generally not capable of handling different fuel 
types, and generally cannot accommodate increases or decreases in the 
fuel volume. Design changes to allow different fuel use, in some cases, 
may reduce the capacity and efficiency of the boiler or process heater. 
Reduced efficiency may result in less complete combustion and, thus, an 
increase in organic HAP emissions. For the reasons discussed above, we 
decided that fuel switching to cleaner solid fuels or to liquid or 
gaseous fuels is not an appropriate criteria for identifying the MACT 
floor emission levels for units in the boilers and process heaters 
category.
    Therefore, the MACT floor limits for each of the HAP and HAP 
surrogates (PM, mercury, CO, HCl, and D/F) are calculated based on the 
performance of the lowest emitting (best performing) sources in each of 
the subcategories. We ranked all of the sources for which we had data 
based on their emissions and identified the lowest emitting 12 percent 
of the sources for each HAP.
    We used the emissions data for those best performing affected 
sources to determine the emission limits to be proposed, with an 
accounting for variability. EPA must exercise its judgment, based on an 
evaluation of the relevant factors and available data, to determine the 
level of emissions control that has been achieved by the best 
performing sources under variable conditions. The DC Circuit Court of 
Appeals has recognized that EPA may consider variability in estimating 
the degree of emission reduction achieved by best-performing sources 
and in setting MACT floors. See Mossville Envt'l Action Now v. EPA, 370 
F.3d 1232, 1241-42 (DC Cir 2004) (holding EPA may consider emission 
variability in estimating performance achieved by best-performing 
sources and may set the floor at level that best-performing source can 
expect to meet ``every day and under all operating conditions'').
    In determining the MACT floor limits, we first determine the floor, 
which is the level achieved in practice by the average of the top 12 
percent. We then assess variability of the best performers by using a 
statistical formula designed to estimate a MACT floor level that is 
achievable by the average of the best performing sources if the best 
performing sources were able to replicate the compliance tests in our

[[Page 32020]]

data base. Specifically, the MACT floor limit is an upper prediction 
limit (UPL) calculated with the Student's t-test using the TINV 
function in Microsoft Excel. The Student's t-test has also been used in 
other EPA rulemakings (e.g., NSPS for Hospital/Medical/Infectious Waste 
Incinerators) in accounting for variability. A prediction interval for 
a future observation is an interval that will, with a specified degree 
of confidence, contain the next (or some other pre-specified) randomly 
selected observation from a population. In other words, the prediction 
interval estimates what future values will be, based upon present or 
past background samples taken. Given this definition, the UPL 
represents the value which we can expect the mean of 3 future 
observations (3-run average) to fall below, based upon the results of 
an independent sample from the same population. In other words, if we 
were to randomly select a future test condition from any of these 
sources (i.e., average of 3 runs), we can be 99% confident that the 
reported level will fall at or below the UPL value. To calculate the 
UPL, we used the average (or sample mean) and sample standard 
deviation, which are two statistical measures calculated from the 
sample data. The average is the central value of a data set, and the 
standard deviation is the common measure of the dispersion of the data 
set around the average.
    We first determined the distribution of the emissions data for the 
best-performing 12 percent of units within each subcategory prior to 
calculating UPL values. To evaluate the distribution of the best 
performing dataset, we first computed the skewness and kurtosis 
statistics and then conducted the appropriate small-sample hypothesis 
tests.
    The skewness statistic (S) characterizes the degree of asymmetry of 
a given data distribution. Normally distributed data have a skewness of 
0. A skewness statistic that is greater (less) than 0 indicates that 
the data are asymmetrically distributed with a right (left) tail 
extending towards positive (negative) values. Further, the standard 
error of the skewness statistic (SES) is given by SES = SQRT(6/N) where 
N is the sample size. According to the small sample skewness hypothesis 
test, if the skewness statistic (S) is greater than two times the SES, 
the data distribution can be considered non-normal.
    The kurtosis statistic (K) characterizes the degree of peakedness 
or flatness of a given data distribution in comparison to a normal 
distribution. Normally distributed data have a kurtosis of 0. A 
kurtosis statistic that is greater (less) than 0 indicates a relatively 
peaked (flat) distribution. Further, the standard error of the kurtosis 
statistic (SEK) is given by SEK = SQRT(24/N) where N is the sample 
size. According to the small sample kurtosis hypothesis test, if the 
kurtosis statistic (K) is greater than two times the SEK, the data 
distribution is typically considered to be non-normal.
    We applied the skewness and kurtosis hypothesis tests to both the 
reported test values and the lognormal values of the reported test 
values. If the skewness (S) and kurtosis (K) statistics of the reported 
data set were both less than twice the SES and SEK, respectively, the 
dataset was classified as normally distributed. If neither of the 
skewness (S) and kurtosis (K) statistics, or only one of these 
statistics were less than twice the SES or SEK, respectively, then the 
skewness and kurtosis hypothesis tests were conducted for the natural 
log-transformed data. Then the distribution most similar to a normal 
distribution was selected as the basis for calculating the UPL. If both 
the reported values and the natural-log transformed reported values had 
skewness (S) and kurtosis (K) statistics that were greater than twice 
the SES or SEK, respectively, the normally distributed dataset was 
selected as the basis of the floor to be conservative. If the results 
of the skewness and kurtosis hypothesis tests were mixed for the 
reported values and the natural log-transformed reported values, we 
also chose the normal distribution to be conservative. We believe this 
approach is more accurate and obtained more representative results than 
a more simplistic normal distribution assumption.
    Since the compliance with the MACT floor emission limit is based on 
the average of a three run test, the UPL is calculated by:
[GRAPHIC] [TIFF OMITTED] TP04JN10.002

Where:

n = the number of test runs
m = the number of test runs in the compliance average

    This calculation was performed using the following two Excel 
functions:

Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + 
[STDEV(Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees of 
freedom)*SQRT((1/n)+(\1/3\))], for a one-tailed t-value (with 2 x 
probability), probability of 0.01, and sample size of n

Lognormal distribution: 99% UPL = EXP{AVERAGE(Natural Log Values of 
Test Runs in Top 12%) + [STDEV(Natural Log Values of Test Runs in Top 
12%) x TINV(2 x probability, n-1 degrees of freedom)* SQRT((1/n)+(\1/
3\))]{time} , for a one-tailed t-value (with 2 x probability), 
probability of 0.01, and sample size of n

    Test method measurement imprecision can also be a component of data 
variability. At very low emissions levels as encountered in the data 
used to support this rule, the inherent imprecision in the pollutant 
measurement method has a large influence on the reliability of the data 
underlying the regulatory floor or beyond-the-floor emissions limit. Of 
particular concern are those data that are reported near or below a 
test method's pollutant detection capability. In our guidance for 
reporting pollutant emissions used to support this rule, we specified 
the criteria for determining test-specific method detection levels. 
Those criteria insure that there is about a 1 percent probability of an 
error in deciding that the pollutant measured at the method detection 
level is present when in fact it was absent. Such a probability is also 
called a false positive or the alpha, Type I, error. Another view of 
this probability is that one is 99 percent certain of the presence of 
the pollutant measured at the method detection level. Because of matrix 
effects, laboratory techniques, sample size, and other factors, method 
detection levels normally vary from test to test. We requested sources 
to identify (i.e., flag) data which were measured below the method 
detection level and to report those values as equal to the test-
specific method detection level.
    Variability of data due to measurement imprecision is inherently 
and reasonably addressed in calculating the floor emissions limit when 
the data base represents multiple tests for which all of the data are 
measured significantly above the method detection level. That is less 
true when the data base includes emissions occurring below method 
detection capabilities and are reported as the method detection level 
values. The data base is then truncated at the lower end of the 
measurement range (i.e., no values reported below the method detection 
level) and we believe that a floor emissions limit based on a truncated 
data base or otherwise including values at or near the method detection 
level may not adequately account for data measurement variability. We 
did not adjust the calculated floor for the data used for this 
proposal; although, we believe that accounting for measurement 
imprecision should be an important

[[Page 32021]]

consideration in calculating the floor emissions limit. We request 
comment on approaches suitable to account for measurement variability 
in establishing the floor emissions limit when based on measurements at 
or near the method detection level.
    As noted above, the confidence level that a value measured at the 
detection level is greater than zero is about 99 percent. The expected 
measurement imprecision for an emissions value occurring at or near the 
method detection level is about 40 to 50 percent. Pollutant measurement 
imprecision decreases to a consistent relative 10 to 15 percent for 
values measured at a level about three times the method detection 
level.\8\ One approach that we believe could be applied to account for 
measurement variability would require defining a method detection level 
that is representative of the data used in establishing the floor 
emissions limits and also minimizes the influence of an outlier test-
specific method detection level value. The first step in this approach 
would be to identify the highest test-specific method detection level 
reported in a data set that is also equal to or less than the floor 
emissions limit calculated for the data set. This approach has the 
advantage of relying on the data collected to develop the floor 
emissions limit while to some degree minimizing the effect of a test(s) 
with an inordinately high method detection level (e.g., the sample 
volume was too small, the laboratory technique was insufficiently 
sensitive, or the procedure for determining the detection level was 
other than that specified).
---------------------------------------------------------------------------

    \8\ American Society of Mechanical Engineers, Reference Method 
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack 
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    The second step would be to determine the value equal to three 
times the representative method detection level and compare it to the 
calculated floor emissions limit. If three times the representative 
method detection level were less than the calculated floor emissions 
limit, we would conclude that measurement variability is adequately 
addressed and we would not adjust the calculated floor emissions limit. 
If, on the other hand, the value equal to three times the 
representative method detection level were greater than the calculated 
floor emissions limit, we would conclude that the calculated floor 
emissions limit does not account entirely for measurement variability. 
We then would use the value equal to three times the method detection 
level in place of the calculated floor emissions limit to ensure that 
the floor emissions limit accounts for measurement variability. We 
request comment on this approach.
    We are requesting comment on whether there is a more appropriate 
statistical approach to account for variability in the MACT floor 
analyses when there are emission data from a limited number of units in 
the subcategory.
    However, after review of the available HAP data, including both 
emission test data and fuel analyses, we determined that it was 
inappropriate to use only this MACT floor approach to determine 
variability and to establish emission limits for boilers and process 
heaters, because this approach considers only the emissions test data. 
The main problem with using only the HAP emissions test data is that 
the data, which may reflect the variability of fuel-related HAP of the 
best performing units, may not reflect the variability of fuel-related 
HAP from the best performing units over the long term. Based on fuel-
related HAP concentrations (nine individual samples collected over a 
30-day period) obtained, pursuant to letters mandating data gathering 
issued under the authority of CAA section 114, fuel-related HAP levels 
in the various fuels can vary significantly over time.
    The first step in establishing a MACT standard is to determine the 
MACT floor. A necessary step in doing so is determining the amount of 
HAP emitted. In the case of fuel-related HAP emitted, this is not 
necessarily a straightforward undertaking. Single stack measurements 
represent a snapshot in time of a source's emissions, always raising 
questions of how representative such emissions are of the source's 
emissions over time. The variations in fuel-related HAP inputs directly 
translate to a variability of fuel-related HAP stack emissions.
    We believe that single short term stack test data (typically a few 
hours) are probably not indicative of long term emissions performance, 
and so are not the best indicators of performance over time. With these 
facts in mind, we carefully considered alternatives other than use of 
only single short-term stack test results to quantify performance for 
fuel-related HAP. We decided that the most accurate method available to 
us to determine long term fuel-related HAP emissions performance was to 
use data on the fuel-related HAP inputs in the fuels used by the best 
performing units, obtained as part of our information collection effort 
under the authority of CAA section 114, on long-term fuel-related HAP 
concentrations (nine individual samples collected over a 30-day period) 
in each fuel, along with the fuel-related HAP concentrations during the 
stack tests.
    As previously discussed above, we account for variability in 
setting floors, not only because variability is an element of 
performance, but because it is reasonable to assess best performance 
over time. Here, for example, we know that the HAP emission data from 
the best performing units are short-term averages, and that the actual 
HAP emissions from those sources will vary over time. If we do not 
account for this variability, we would expect that even the units that 
perform better than the floor on average would potentially exceed the 
floor emission levels a significant part of the time which would mean 
that variability was not properly taken into account. This variability 
includes the day-to-day variability in the total fuel-related HAP input 
to each unit and variability of the sampling and analysis methods, and 
it includes the variability resulting from site-to-site differences for 
the best performing units. We calculated the MACT floor based on the 
UPL (upper 99th percentile) as described earlier from the average 
performance of the best performing units, Students t-factor, and the 
variability of the best performing units.
    This approach reasonably ensures that the emission limit selected 
as the MACT floor adequately represents the level of emissions actually 
achieved by the average of the units in the top 12 percent, considering 
ordinary operational variability of those units. Both the analysis of 
the measured emissions from units representative of the top 12 percent, 
and the variability analysis, are reasonably designed to provide a 
meaningful estimate of the average performance, or central tendency, of 
the best controlled 12 percent of units in a given subcategory.
    A detailed discussion of the MACT floor methodology is presented in 
the memorandum ``MACT Floor Analysis (2010) for the Industrial, 
Commercial, and Institutional Boilers and Process Heaters National 
Emission Standards for Hazardous Air Pollutants--Major Source'' in the 
docket.
1. Determination of MACT for the Fuel-Related HAP
    In developing the proposed MACT floor for the fuel-related HAP 
(non-mercury metals, acid gases, and mercury), as described earlier, we 
are using PM as a surrogate for non-mercury metallic HAP and HCl as a 
surrogate for the acid gases. Table 2 of this preamble presents the 
number of units in each of the five subcategories, along with the

[[Page 32022]]

number of units from which we have collected emission data. Table 2 
also presents for each subcategory and fuel-related HAP the number of 
units comprising the best performing units (top 12 percent), the 
average emission level of the top 12 percent, and the MACT floor (99 
percent UPL of top 12 percent) which includes the variability across 
the best performing units and the long term variability across those 
units.

           Table 2--Summary of MACT Floor Results for the Fuel-Related HAP for Existing Subcategories
----------------------------------------------------------------------------------------------------------------
                Subcategory                           Parameter                 PM        Mercury        HCl
----------------------------------------------------------------------------------------------------------------
Units designed for Coal firing............  No. of sources in subcategory          578          578          578
                                            No. of sources with data.....          366          285          318
                                            No. in MACT floor............           44           35           39
                                            Avg of top 12%, lb/MMBtu.....     7.24E-03     5.95E-07     4.23E-03
                                            99% UPL of top 12% (test            0.0179     1.64E-06     7.38E-03
                                             runs), lb/MMBtu.
                                            99% UPL with fuel variability  ...........     2.88E-06     1.11E-02
                                             of top 12%, lb/MMBtu.
Units designed for Biomass firing.........  No. of sources in subcategory          420          420          420
                                            No. of sources with data.....          192           91           92
                                            No. in MACT floor............           24           11           12
                                            Avg of top 12%, lb/MMBtu.....     6.06E-03     3.46E-07     4.34E-03
                                            99% UPL of top 12% (test            0.0162     7.52E-07     6.00E-03
                                             runs), lb/MMBtu.
                                            99% UPL with fuel variability  ...........     8.88E-07  ...........
                                             of top 12%, lb/MMBtu.
Units designed for Liquid Fuel firing.....  No. of sources in subcategory          826          826          826
                                            No. of sources with data.....           91          177          190
                                            No. in MACT floor............           11           22           23
                                            Avg of top 12%, lb/MMBtu.....     1.40E-03     1.91E-06     2.59E-04
                                            99% UPL of top 12% (test           0.00323     2.78E-06     3.26E-04
                                             runs), lb/MMBtu.
                                            99% UPL with fuel variability  ...........     3.97E-06     8.04E-04
                                             of top 12%, lb/MMBtu.
Units designed for other gas firing.......  No. of sources in subcategory          199          199          199
                                            No. of sources with data.....           13            8            8
                                            No. in MACT floor............            2            1            1
                                            Avg of top 12%, lb/MMBtu.....        0.011     8.25E-08     1.70E-06
                                            99% UPL of top 12% (test             0.045     1.86E-07     2.50E-06
                                             runs), lb/MMBtu.
----------------------------------------------------------------------------------------------------------------

    For three cases, the proposed new and existing source MACT floors 
are almost identical because the best performing 12 percent of existing 
units (for which we have emissions information) is only one or two 
sources. The reason we look to the best performing 12 percent of 
sources, even though we have data on fewer than 5 sources, is that 
these subcategories consist of 30 or more units. CAA section 
112(d)(3)(A) provides that standards for existing sources shall not be 
less stringent than ``the average emission limitation achieved by the 
best performing 12 percent of the existing sources (for which the 
Administrator has emissions information), * * * in the category or 
subcategory for categories and subcategories with 30 or more sources.'' 
A plain reading of the above statutory provisions is to apply the 12 
percent rule in deriving the MACT floor for those categories or 
subcategories with 30 or more sources. The parenthetical ``(for which 
the Administrator has emissions information)'' in CAA section 
112(d)(3)(A) modifies the best performing 12 percent of existing 
sources, which is the clause it immediately follows.
    However, in cases where there are 30 or more sources but little 
emission data, this results in only a few units setting the existing 
source floor with the result that the new and existing source MACT 
floors are almost identical. In contrast, if these subcategories had 
less than 30 sources, we would be required to use the top five best 
performing sources, rather than the one or two that comprise the top 12 
percent. Section 112(d)(3)(B).
    We are seeking comment on whether, with the facts of this 
rulemaking, we should consider reading the intent of Congress to allow 
us to consider five sources rather than just one or two. First, it 
seems evident that Congress was concerned that floor determinations 
should reflect a minimum quantum of data: At least data from 5 sources 
for source categories of less than 30 sources (assuming that data from 
5 sources exist). Second, it does not appear that this concern would be 
any less for subcategories with 30 or more sources. We are specifically 
requesting comment on this interpretation relating to the proposed MACT 
floors.\9\
---------------------------------------------------------------------------

    \9\ The impact of using a minimum of five sources in the MACT 
floor analyses for these subcategories and HAP are presented in the 
Memorandum ``MACT Floor Analysis (2010) for the Industrial, 
Commercial, and Institutional Boilers and Process Heaters National 
Emission Standards for Hazardous Air Pollutants--Major Sources'' 
located in the Docket.
---------------------------------------------------------------------------

2. Determination of MACT for Organic HAP
    In developing the MACT floor for organic HAP, as described earlier, 
we are using CO as a surrogate for non-dioxin organic HAP. Table 3 of 
this preamble presents the number of units in each of the 11 
subcategories, along with the number of units from which we have 
collected emission data. Table 3 also presents for each subcategory 
(for CO and D/F) the number of units comprising the best performing 
units (top 12 percent), the average emission level of the top 12 
percent, and the MACT floor (99 percent UPL of top 12 percent) which 
includes the variability across the best performing units and the long 
term variability.
    We calculated the MACT floors based on the upper 99th percentile 
UPL from the average performance of the best performing units and their 
variances as described earlier for the fuel-related HAP.

[[Page 32023]]



                    Table 3--Summary of MACT Floor Results for the Organic HAP Subcategories
----------------------------------------------------------------------------------------------------------------
            Subcategory                       Parameter                     CO              Dioxin/Furan (TEQ)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal.......................  No. of sources in            361...................  361.
                                      subcategory.
                                     No. of sources with data...  61....................  14.
                                     No. in MACT floor..........  8.....................  2.
                                     Avg of top 12%.............  21.4 ppm @ 3% O2......  0.00182 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top % (test       48.8 ppm @ 3% O2......  0.00274 ng/dscm @ 7%
                                      runs).                                               O2.
Fluidized Bed--Coal................  No. of sources in            31....................  31.
                                      subcategory.
                                     No. of sources with data...  17....................  12.
                                     No. in MACT floor..........  3.....................  2.
                                     Avg of top 12%.............  12.5 ppm @ 3% O2......  0.000471 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top % (test       21.4 ppm @ 3% O2......  0.00168 ng/dscm @ 7%
                                      runs).                                               O2.
PC--Coal...........................  No. of sources in            186...................  186.
                                      subcategory.
                                     No. of sources with data...  41....................  10.
                                     No. in MACT floor..........  5.....................  2.
                                     Avg of top 12%.............  19.2 ppm @ 3% O2......  0.00158 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top % (test       82.8 ppm @ 3% O2......  0.00307 ng/dscm @ 7%
                                      runs).                                               O2.
Stoker--Biomass....................  No. of sources in            320...................  320.
                                      subcategory.
                                     No. of sources with data...  119...................  16.
                                     No. in MACT floor..........  15....................  2.
                                     Avg of top 12%.............  203 ppm @ 3% O2.......  0.000819 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top % (test       551 ppm @ 3% O2.......  0.00339 ng/dscm @ 7%
                                      runs).                                               O2.
Fluidized Bed--Biomass.............  No. of sources in            12....................  12.
                                      subcategory.
                                     No. of sources with data...  7.....................  6.
                                     No. in MACT floor..........  5.....................  5.
                                     Avg of top 12%.............  97.1 ppm @ 3% O2......  0.00507 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top 12% (test     245 ppm @ 3% O2.......  0.0127 ng/dscm @ 7%
                                      runs).                                               O2.
Suspension Burner/Dutch Oven.......  No. of sources in            62....................  62.
                                      subcategory.
                                     No. of sources with data...  17....................  3.
                                     No. in MACT floor..........  3.....................  1.
                                     Avg of top 12%.............  362 ppm @ 3% O2.......  0.00952 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top 12% (test     1010 ppm @ 3% O2......  0.0279 ng/dscm @ 7%
                                      runs).                                               O2.
Fuel Cell--Biomass.................  No. of sources in            26....................  26.
                                      subcategory.
                                     No. of sources with data...  16....................  7.
                                     No. in MACT floor..........  5.....................  5.
                                     Avg of top 12%.............  130 ppm @ 3% O2.......  0.00552 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top 12% (test     262 ppm @ 3% O2.......  0.0148 ng/dscm @ 7%
                                      runs).                                               O2.
Units designed for Liquid fuel       No. of sources in            826...................  826.
 firing.                              subcategory.
                                     No. of sources with data...  116...................  17.
                                     No. in MACT floor..........  14....................  3.
                                     Avg of top 12%.............  0.443 ppm @ 3% O2.....  0.000733 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top 12% (test     0.911 ppm @ 3% O2.....  0.00182 ng/dscm @ 7%
                                      runs).                                               O2.
Units designed for other gases       No. of sources in            199...................  199.
 firing.                              subcategory.
                                     No. of sources with data...  75....................  5.
                                     No. in MACT floor..........  9.....................  1.
                                     Avg of top 12%.............  0.0737 ppm @ 3% O2....  0.00267 ng/dscm @ 7%
                                                                                           O2.
                                     99% UPL of top 12% (test     0.134 ppm @ 3% O2.....  0.00828 ng/dscm @ 7%
                                      runs).                                               O2.
----------------------------------------------------------------------------------------------------------------

    For organic HAP, as previously discussed above for fuel-related 
HAP, we account for variability in setting floors, not only because 
variability is an element of performance, but because it is reasonable 
to assess best performance over time. Here, however, we know that the 
organic HAP emissions will also vary over the operating range of the 
unit, unlike fuel-related HAP emissions. Organic HAP are combustion-
related pollutants. That is, their levels of emissions are a function 
of the combustion process. Combustion units operate most efficiently 
when operated

[[Page 32024]]

at or near their design capacity. The combustion efficiency tends to 
decrease as the unit's load (steam production) decreases. Most 
industrial or commercial/institutional units do not continuously 
operate at or near their design capacity but operate according to the 
facility's demand for steam. Thus, operation at lower capacity rates 
must be accounted for in determining operational variability.
    As part of EPA's information collection effort, we obtained data on 
organic HAP (THC and CO) from six units (two coal-fired, two biomass-
fired, and two gas-fired) that were collected using CEM over a 30-day 
period. All of these units were selected to test using CEM to provide 
variability information because their stack test results indicated that 
they were among the best performing units.
    The CEMS data shows that CO (as a surrogate for non-dioxin organic 
HAP) from best performing units did not vary much when such unit is 
operated at below design capacity. Therefore, even though ICI units, 
due to steam demand, may operate at these low load conditions, no 
additional variability due to operating load needs to be accounted for 
since the average CO emission levels that include these low load 
conditions are within the variability range determined by the 
statistical analyses of CO emissions from the best performing units. 
Thus, we are proposing to add no additional variability factor to 
account for load variability to the MACT floor 99 percent UPL values 
determined from the stack test data for CO emissions.
    This approach reasonably ensures that the emission limit selected 
as the MACT floor adequately represents the average level of control 
actually achieved by units in the top 12 percent in each subcategory, 
considering ordinary operational variability of those units. Both the 
analysis of the measured emissions from units representative of the top 
12 percent, and the variability analysis of those units, are reasonably 
designed to provide a meaningful estimate of the average performance, 
or central tendency, of the best controlled 12 percent of units in a 
given subcategory.
    As was the case for the three fuel-dependent MACT floors, the 
proposed new and existing source MACT floors for eight combustion-
dependent subcategories are almost identical because the best 
performing 12 percent of units (for which we have emissions 
information) is only one or two sources. Again, the reason we look to 
the best performing 12 percent of sources is that these subcategories 
consist of 30 or more units. In contrast, if these subcategories had 
less than 30 sources, we would be required to use the top five best 
performing sources, rather than the one or two that comprise the top 12 
percent. As stated previously, we are seeking comment on whether, with 
the facts of this rulemaking, we should consider reading the intent of 
Congress to allow us to consider five sources rather than just one, 
two, or three. We are specifically requesting comment on this 
interpretation relating to the proposed MACT floors.
3. Determination of the Work Practice Standard
    CAA section 112(h)(1) states that the Administrator may prescribe a 
work practice standard or other requirements, consistent with the 
provisions of CAA sections 112(d) or (f), in those cases where, in the 
judgment of the Administrator, it is not feasible to enforce an 
emission standard. CAA section 112(h)(2)(B) further defines the term 
``not feasible'' in this context to apply when ``the application of 
measurement technology to a particular class of sources is not 
practicable due to technological and economic limitations.''
    The standard reference methods for measuring emissions of mercury, 
CO (as a surrogate for organic HAP), D/F, HCl (as a surrogate for acid 
gases) and PM (as a surrogate for non-mercury metals) are EPA Methods 
29, 10, 23, 26A and 5. These methods are reliable but relatively 
expensive as a group. However, the methods are generally not able to 
accurately sample small diameter (less than 12 inches) stacks. For 
example, in these small diameter stacks, the conventional EPA Method 5 
stack assembly blocks a significant portion of the cross-section of the 
duct and, if unaccounted for, could cause inaccurate measurements. Many 
existing small boilers and process heaters have stacks with diameters 
less than 12 inches. The stack diameter is generally related to the 
size of the unit. Units that have capacity below 10 million Btu per 
hour generally have stacks with diameters less than 12 inches. Also, 
many existing small units do not currently have sampling ports or a 
platform for accessing the exhaust stack which would require an 
expensive modification to install sampling ports and a platform.
    We conducted a cost analysis \10\ to evaluate the economic impact 
of the testing and monitoring costs that facilities with small units 
would incur to demonstrate compliance with the proposed emission 
limits. The compliance costs imposed on each facility would not only 
include the costs of the stack tests and monitoring equipment but would 
also include the capital costs of any installed control equipment. We 
estimate that the total capital costs of installing control equipment 
on the over 7,400 small boilers and process heaters to achieve the 
proposed emission limits would be $6.3 billion. In addition to these 
costs, additional costs would be incurred because many of these small 
units do not have test ports or testing platforms installed in order to 
conduct performance testing. Prior to conducting a stack test each unit 
would need to construct or rent scaffolding and install test ports. EPA 
estimates that these small sources would incur an additional $185 
million to install test ports and rent temporary scaffolding. Many 
establishments in each industry, commercial, or institutional sector 
are associated with multiple (as many as a 700) small units.
---------------------------------------------------------------------------

    \10\ Memorandum: Methodology for Estimating Impacts from 
Industrial, Commercial, and Institutional Boilers and Process 
Heaters at Major Sources of Hazardous Air Pollutant Emissions, March 
23, 2010.
---------------------------------------------------------------------------

    The results of the analysis indicate that the annual costs for 
testing and monitoring costs alone would have a significant adverse 
economic impact on these facilities. The severity of the economic 
impact would depend on the size of the facility.
    Based on this analysis, the Administrator has determined under CAA 
section 112(h) that it is not feasible to enforce emission standards 
for a particular class of existing boilers and process heaters because 
of the technological and economic limitations described above. Thus, a 
work practice, as discussed below, is being proposed to limit the 
emission of HAP for existing boilers and process heaters having a heat 
input capacity of less than 10 million Btu per hour. We are 
specifically requesting comment on whether a threshold higher than 10 
million Btu per hour meets the technical and economic limitations as 
specified in CAA section 112(h).
    For existing units, the only work practice being used that 
potentially controls HAP emissions is a tune-up. Fuel dependent HAP are 
typically controlled by removing them from the flue gas after 
combustion. The only work practices expected to minimize fuel dependent 
HAP emissions are reducing the fuel usage or fuel switching to a fuel 
type with a lower HAP content. Fuel usage can be reduced by improving 
the combustion efficiency of the unit, such as, by a tune-up. As 
combustion efficiency decreases, fuel usage must increase to maintain

[[Page 32025]]

constant energy output. This increased fuel use results in increased 
emissions.
    On the other hand, organic HAP are formed from incomplete 
combustion of the fuel. The objective of good combustion is to release 
all the energy in the fuel while minimizing losses from combustion 
imperfections and excess air. The combination of the fuel with the 
oxygen requires temperature (high enough to ignite the fuel 
constituents), mixing or turbulence (to provide intimate oxygen-fuel 
contact), and sufficient time (to complete the process), sometimes 
referred to the three Ts of combustion. Good combustion practice (GCP), 
in terms of combustion units, could be defined as the system design and 
work practices expected to minimize organic HAP emissions.
    We have obtained information on units that reported using GCP, as 
part of the information collection effort for the NESHAP. The data that 
we have suggests that units typically conduct tune-ups. We also 
reviewed State regulations and permits. The work practices listed in 
State regulations includes tune-ups (10 States), operator training (1 
State), periodic inspections (2 States), and operation in accordance 
with manufacturer specifications (1 State). Of the units with a 
capacity of less than 10 MMBtu/h that responded to EPA's information 
collection effort for the NESHAP, 80 percent reported conducting a 
tune-up program. Ultimately, we determine that at least 6 percent of 
the units in each of the subcategories are subject to a tune-up 
requirement. Therefore, the proposed work practice of a tune-up \11\ 
program does establish the MACT floor for HAP emissions from existing 
units with a heat input capacity of less than 10 MMBtu/h.
---------------------------------------------------------------------------

    \11\ Tune-up procedure is specified in section 63.7540 of this 
proposed rule and includes making adjustments to the burner to 
optimize the flame to minimize CO emissions consistent with the 
manufacturer's specifications.
---------------------------------------------------------------------------

    We are also proposing a work practice standard under section 112(h) 
that would require an annual tune-up for existing boilers and process 
heaters combusting natural gas or refinery gas. These boilers and 
process heaters are units included in the Gas 1 and metal processing 
furnace subcategories. We are specifically seeking comment on whether 
the application of measurement methodology to sources in this 
subcategory is impracticable due to technological or economic 
limitations, as specified in section 112(h)(2)(B).
    This work practice standard is being proposed for several reasons. 
First, the capital costs estimated for installing controls on these 
boilers and process heaters to comply with MACT limits for the five HAP 
groups is over $14 billion. This cost includes installation of a 
combination system of a fabric filter (for PM, mercury, and D/F 
control) and a wet scrubber (for HCl control). This capital cost is 
higher than the estimated combined capital cost for boilers and process 
heaters in all of the other subcategories. The projected control system 
needed for boilers and process heaters in the other subcategories is 
also a combined fabric filter/wet scrubber system.
    Second, we believe that proposing emission standards for gas-fired 
boilers and process heaters that result in the need to employ the same 
emission control system as needed for the other fuel types would have 
the negative benefit of providing a disincentive for switching to gas 
as a control technique (and a pollution prevention technique) for 
boilers and process heaters in the other fuel subcategories. In 
addition, emission limits on gas-fired boilers and process heaters may 
have the negative benefit of providing an incentive for a facility to 
switch from gas (considered a ``clean'' fuel) to a ``dirtier'' but 
cheaper fuel (i.e., coal). It would be inconsistent with the emissions 
reductions goals of the CAA, and of section 112 in particular, to adopt 
requirements that would result in an overall increase in HAP emissions. 
We are soliciting comment on the extent to which natural gas facilities 
would be expected to switch to a ``dirtier'' fuel if emissions limits 
for such facilities are adopted.
    Thus, a work practice, as discussed above for small boilers and 
process heaters, is being proposed to limit the emission of HAP for 
existing natural gas-fired and refinery gas-fired boilers and process 
heaters.
    We request comments on whether the emission limits listed in Table 
4 of this preamble for the Gas 1 and Metal Process Furnace 
subcategories should be promulgated. Comments should include detailed 
information regarding why emission limits for these gas-fired boilers 
and process heaters are appropriate.

                              Table 4--Summary of MACT Floor Results for the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                         Dioxin/furan
           Subcategory                 Parameter              PM                Mercury               HCl                 CO              (total TEQ)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing.  No. of sources in   10,783............  10,783............  10,783............  10,783............  10,783.
                                   subcategory.
                                  No. of sources      144...............  14................  11................  754...............  8.
                                   with data.
                                  No. in MACT floor.  18................  2.................  2.................  91................  1.
                                  Avg of top 12%....  0.00388 lb/MMBtu..  1.1E-07 lb/MMBtu..  1.01E-04 lb/MMBtu.  1.45 ppm @ 3%       0.0026 ng/dscm @
                                                                                                                   oxygen.             7% oxygen.
                                  99% UPL of top 12%  0.03 lb/MMBtu.....  2.0E-07 lb/MMBtu..  0.0002 lb/MMBtu...  20 ppm @ 3% oxygen  0.01 ng/dscm @ 7%
                                   (test runs).                                                                                        oxygen.
Metal Process Furnaces..........  No. of sources in   749...............  749...............  749...............  749...............  749.
                                   subcategory.
                                  No. of sources      9.................  7.................  9.................  15................  7.
                                   with data.
                                  No. in MACT floor.  2.................  1.................  2.................  2.................  1.
                                  Avg of top 12%....  0.0047 lb/MMBtu...  3.3E-08 lb/MMBtu..  1.92E-04 lb/MMBtu.  0.38 ppm @ 3%       0.0026 ng/dscm @
                                                                                                                   oxygen.             7% oxygen.
                                  99% UPL of top 12%  0.02 lb/MMBtu.....  2.0E-07 lb/MMBtu..  0.0004 lb/MMBtu...  2 ppm @ 3% oxygen.  0.004 ng/dscm @ 7%
                                   (test runs).                                                                                        oxygen.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 32026]]

E. How did EPA consider beyond-the-floor options for existing units?

    Once the MACT floor determinations were done for each subcategory, 
we considered various regulatory options more stringent than the MACT 
floor level of control (i.e., technologies or other work practices that 
could result in lower emissions) for the different subcategories. A 
detailed description of the beyond-the-floor consideration is in the 
memorandum ``Methodology for Estimating Cost and Emissions Impacts for 
Industrial, Commercial, Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants'' in the 
docket.
    We could not identify better HAP emissions reduction approaches 
that could achieve greater emissions reductions of HAP than the control 
technology combination (fabric filter, carbon injection, scrubber, and 
GCP) that we expect will be used to meet the MACT floor level of 
control.
    For each subcategory, fuel switching to natural gas is an option 
that would reduce HAP emissions. We determined that fuel switching was 
not an appropriate beyond-the-floor option. First, natural gas supplies 
are not available in some areas, and supplies to industrial customers 
can be limited during periods when natural gas demand exceeds supply. 
Additionally, the estimated emissions reductions that would be achieved 
if solid and liquid fuel units switched to natural gas were compared 
with the estimated cost of converting existing solid fuel and liquid 
fuel units to fire natural gas. The annualized cost of fuel switching 
was estimated to be $13.5 billion compared with $3.5 billion under the 
floor approach. The emission reduction associated with fuel switching 
was estimated to be 4,296 tons per year for metallic HAP, 8 tons per 
year for mercury, and 50,332 tons per year for inorganic HAP (HCl and 
HF). The cost for fuel switching is over double the cost of the floor 
approach while the emission reductions associated with fuel switching 
are approximately the same. Additional detail on the calculation 
procedures is provided in the memorandum ``Development (2010) of Fuel 
Switching Costs and Emissions Reductions for Industrial, Commercial, 
and Institutional Boilers and Process Heaters National Emission 
Standards for Hazardous Air Pollutants'' in the docket.
    We also considered the pollution prevention and energy conservation 
measure of an energy assessment/audit as a beyond-the-floor option for 
HAP emissions. An energy assessment provides valuable information on 
improving energy efficiency. An energy assessment, or audit, is an in-
depth energy study identifying all energy conservation measures 
appropriate for a facility given its operating parameters. An energy 
assessment refers to a process which involves a thorough examination of 
potential savings from energy efficiency improvements, pollution 
prevention, and productivity improvement. It leads to the reduction of 
emissions of pollutants through process changes and other efficiency 
modifications. Besides reducing operating and maintenance costs, 
improving energy efficiency reduces negative impacts on the environment 
and results in reduced emissions and improved public health. 
Improvement in energy efficiency results in decreased fuel use which 
results in a corresponding decrease in emissions (both HAP and non-HAP) 
from the combustion unit, but not necessarily a decrease in emissions 
of all HAP emitted. The Department of Energy has conducted energy 
assessments at selected manufacturing facilities and reports that 
facilities can reduce fuel/energy use by 10 to 15 percent by using best 
practices to increase their energy efficiency. Many best practices are 
considered pollution prevention because they reduce the amount of fuel 
combusted which results in a corresponding reduction in emissions from 
the fuel combustion. The most common best practice is simply tuning the 
boiler to the manufacturer's specification.
    The one-time cost of an energy assessment ranges from $2500 to 
$55,000 depending on the size of the facility. The total annualized 
cost if each major source facility conducted an energy assessment is 
estimated at $26 million. If a facility implemented the cost-effective 
energy conservation measures identified in the energy assessment, it 
would potentially result in greater HAP reduction than achieved by a 
boiler tune-up alone and potentially reducing HAP emissions (HCl, 
mercury, non-mercury metals, and VOC) by an additional 820 to 1,640 
tons per year. In addition, the costs of any energy conservation 
improvement will be offset by the cost savings in lower fuel costs. 
Therefore, we decided to go beyond the MACT floor for this proposed 
rule for the existing units. These proposed standards for existing 
units include the requirement of a performance of an energy assessment 
to identify cost-effective energy conservation measures. Since there 
was insufficient information to determine if requiring implementation 
of cost-effective measures were economically feasible, we are seeking 
comment on this point.
    In this proposed rule, we are defining a cost-effective energy 
conservation measure to be any measure that has a payback (return of 
investment) period of 2 years or less. This payback period was selected 
based on section 325(o)(2)(B)(iii) of the Energy Policy and 
Conservation Act which states that there is a presumption that an 
energy conservation standard is economically justified if the increased 
installed cost for a measure is less than three times the value of the 
first-year energy savings resulting from the measure.
    We believe that an energy assessment is an appropriate beyond-the-
floor control technology because it is one of the measures identified 
in CAA section 112(d)(2). CAA section 112(d)(2) states that ``Emission 
standards promulgated * * * and applicable to new or existing sources * 
* * is achievable * * * through application of measures, processes, 
methods, systems or techniques including, but not limited to measures 
which * * * reduce the volume of, or eliminate emissions of, such 
pollutants through process changes, substitution of materials or other 
modifications * * *''
    The purpose of an energy assessment is to identify energy 
conservation measures (such as, process changes or other modifications 
to the facility) that can be implemented to reduce the facility energy 
demand which would result in reduced fuel use. Reduced fuel use will 
result in a corresponding reduction in HAP, and non-HAP, emissions. 
Thus, an energy assessment, in combination with the MACT emission 
limits will result in the maximum degree of reduction in emissions as 
required by 112(d)(2). Therefore, we are proposing to require all 
existing sources to conduct a one-time energy assessment to identify 
cost-effective energy conservation measures.
    We are proposing that the energy assessment be conducted by energy 
professionals and/or engineers that have expertise that cover all 
energy using systems, processes, and equipment. We are aware of, at 
least, two organizations that provide certification of specialists in 
evaluating energy systems. We are proposing that a qualified 
specialized is someone who has successfully completed the Department of 
Energy's Qualified Specialist Program for all systems or a professional 
engineer certified as a Certified Energy Manager by the Association of 
Energy Engineers.
    As part of the energy assessment, we are proposing that the 
facility assess its energy management program and

[[Page 32027]]

practices using EPA's ENERGY STAR Facility Energy Management Assessment 
Matrix. ENERGY STAR has a simple facility energy management assessment 
tool that can be used as part of the assessment process. This tool 
identifies gaps in current practices. Facilities, as part of the 
requirement, would identify steps to close the management gaps. We are 
also proposing that the facility develop an energy management program 
according to the ENERGY STAR Guidelines for Energy Management (see 
www.energystar.gov/guidelines).\12\
---------------------------------------------------------------------------

    \12\ The location of the guidance is: http://www.energystar.gov/index.cfm?c=guidelines.assess_facility_energy.
---------------------------------------------------------------------------

    We are specifically requesting comment on: (1) Whether our 
estimates of the assessment costs are correct; (2) is there adequate 
access to certified assessors; (3) are there other organizations for 
certifying energy engineers; (4) are online tools adequate to inform 
the facility's decision to make efficiency upgrades; (5) is the 
definition of ``cost-effective'' appropriate in this context since it 
refers to payback of energy saving investments without regard to the 
impact on HAP reduction; (6) what rate of return should be used; and 
(7) are there other guidelines for energy management beside ENERGY 
STAR's that would be appropriate.
    We considered proposing a beyond-the-floor requirement for certain 
sources in the natural gas and refinery gas subcategory (i.e., the Gas 
1 subcategory). Specifically, we considered proposing that facilities 
with boilers or process heaters combusting refinery gas install and 
maintain a carbon adsorber bed system \13\ to remove mercury from the 
refinery gas before combustion in a boiler or process heater. Based on 
data from the information collection effort, refinery gas contains 
mercury and additional mercury reductions can be achieved from units 
combusting refinery gas. Consequently, we analyzed the mercury 
emissions reductions and additional cost of adopting this work 
practice. The annualized cost of the carbon adsorber bed system to 
treat the refinery gas prior to combustion is estimated to be about 1.6 
billion dollars with a mercury emission reduction of 0.8 tons. The 
results indicated that while additional mercury emissions reductions 
would be realized, the costs would be too high to consider it a 
feasible beyond-the-floor option. Nonair quality health, environmental 
impacts, and energy effects were not significant factors, because there 
would be little difference in the nonair quality health and 
environmental impacts of requiring the installation of carbon bed 
adsorbers. Therefore, we are not proposing installation of a carbon 
adsorber bed system as a beyond-the-floor requirement.
---------------------------------------------------------------------------

    \13\ Carbon adsorption of mercury can be accomplished by (a) 
injecting dry carbon with or without other dry sorbents into the 
offgas upstream of a PM control device (typically a baghouse), or 
(b) using a fixed or moving bed of granular carbon through which the 
offgas flows. In a typical fixed bed carbon adsorption system, the 
flue gas flows through a vessel packed with a specified depth of the 
carbon granules. The bed and packing are designed to limit the 
linear velocity of the offgas in the bed to increase the contact 
time with the carbon. Due to the increased contact times and 
typically lower operating temperatures, better removal efficiencies 
can be achieved than for carbon injection. At a residence time of 10 
seconds in the carbon bed, virtually all of the mercury can be 
removed. (Ref. NUCON INTERNATIONAL, Inc., ``Design & Performance 
Characteristics of MERSORBB Mercury Adsorbents in Liquids and 
Gases,'' NUCON 11B28, August 1995.)
---------------------------------------------------------------------------

F. Should EPA consider different subcategories for solid fuel boilers 
and process heaters?

    The boilers and process heaters source category is tremendously 
heterogeneous. EPA has attempted to identify subcategories that provide 
the most reasonable basis for grouping and estimating the performance 
of generally similar units using the available data. We believe that 
the subcategories we selected are appropriate.
    EPA requests comments on whether additional or different 
subcategories should be considered. Comments should include detailed 
information regarding why a new or different subcategory is appropriate 
(based on the available data or adequate data submitted with the 
comment), how EPA should define any additional/different subcategories, 
how EPA should account for varied or changing fuel mixtures, and how 
EPA should use the available data to determine the MACT floor for any 
new or different categories.

G. How did EPA determine the proposed emission limitations for new 
units?

    All standards established pursuant to section 112 of the CAA must 
reflect MACT, the maximum degree of reduction in emissions of air 
pollutants that the Administrator, taking into consideration the cost 
of achieving such emissions reductions, and any nonair quality health 
and environmental impacts and energy requirements, determines is 
achievable for each category. The CAA specifies that MACT for new 
boilers and process heaters shall not be less stringent than the 
emission control that is achieved in practice by the best-controlled 
similar source. This minimum level of stringency is the MACT floor for 
new units. However, EPA may not consider costs or other impacts in 
determining the MACT floor. EPA must consider cost, nonair quality 
health and environmental impacts, and energy requirements in connection 
with any standards that are more stringent than the MACT floor (beyond-
the-floor controls).

H. How did EPA determine the MACT floor for new units?

    Similar to the MACT floor process used for existing units, the 
approach for determining the MACT floor must be based on available 
emissions test data. Using such an approach, we calculated the MACT 
floor for a subcategory of sources by ranking the emission test results 
from units within the subcategory from lowest to highest to identify 
the best controlled similar source. The MACT floor limits for each of 
the HAP and HAP surrogates (PM, mercury, CO, HCl, and D/F) are 
calculated based on the performance (numerical average) of the lowest 
emitting (best controlled) source for each pollutant in each of the 
subcategories.
    The MACT floor limits for new sources were calculated using the 
same formula as was used for existing sources. However, as was the case 
for the existing MACT floor analysis, we determined that it was 
inappropriate to use only this MACT floor approach to determine 
variability and to establish emission limits for new boilers and 
process heaters. The main problem with using only the HAP emissions 
test data is that the data may not reflect the variability of fuel-
related HAP from the best controlled similar source over the long term. 
Based on our current information, fuel-related HAP levels in the 
various fuels can vary significantly over time. The variations in fuel-
related HAP inputs directly translate to a variability of fuel-related 
HAP stack emissions.
    As previously discussed above, we account for variability of the 
best-controlled source in setting floors, not only because variability 
is an element of performance, but because it is reasonable to assess 
best performance over time. If we do not account for this variability, 
we would expect that even the best controlled similar source would 
potentially exceed the floor emission levels a significant part of the 
time which would mean that their variability was not properly accounted 
for when setting the floor. We calculated the MACT floor based on the 
UPL (upper 99th percentile) as described earlier from the average 
performance of the best controlled similar source, Students t-factor, 
and the total variability of the best-controlled source.

[[Page 32028]]

    This approach reasonably ensures that the emission limit selected 
as the MACT floor adequately represents the average level of control 
actually achieved by the best controlled similar source, considering 
ordinary operational variability.
    A detailed discussion of the MACT floor methodology is presented in 
the memorandum ``MACT Floor Analysis for the Industrial, Commercial, 
and Institutional Boilers and Process Heaters National Emission 
Standards for Hazardous Air Pollutants'' in the docket.
    The approach that we use to calculate the MACT floors for new 
sources is somewhat different from the approach that we use to 
calculate the MACT floors for existing sources. While the MACT floors 
for existing units are intended to reflect the performance achieved by 
the average of the best performing 12 percent of sources, the MACT 
floors for new units are meant to reflect the emission control that is 
achieved in practice by the best controlled source. Thus, for existing 
units, we are concerned about estimating the central tendency of a set 
of multiple units, while for new units, we are concerned about 
estimating the level of control that is representative of that achieved 
by a single best controlled source. As with the analysis for existing 
sources, the new unit analysis must account for variability. To 
accomplish this for new sources, for the fuel dependent HAP emissions, 
we determined what the best controlled source has achieved in light of 
the inherent and unavoidable variations in the HAP content of the fuel 
that such unit might potentially use. For non-fuel dependent HAP 
emissions, on the other hand, we look at the inherent variability of 
the control technology used by the best-controlled source in the 
subcategory. These approaches, respectively, represent the most 
reasonable way to estimate performance for purposes of establishing 
MACT floors for new units, given the data available.
    For fuel dependent HAP emissions (mercury and HCl), we calculated 
the variability factor by looking at data on HAP variability in fuel 
obtained through our information collection request. We derived the 
fuel dependent variability factor by dividing the highest observed HAP 
concentration by the lowest observed HAP concentration from the fuel 
analyses from the best-controlled source. Once we calculated the fuel 
dependent variability factors, we applied these factors to the average 
measured emissions performance of the best controlled similar source to 
derive the MACT floor level of control. This approach reasonably 
estimates the best source's level of emissions, adjusted for 
unavoidable variation in fuel characteristics which have a direct 
impact on emissions.
1. Determination of MACT for the Fuel-Related HAP
    In developing the MACT floor for the fuel-related HAP (PM, HCl, and 
mercury), as described earlier, we are using PM as a surrogate for non-
mercury metallic HAP and HCl as a surrogate for the acid gases. Table 5 
presents for each subcategory and fuel-related HAP the average emission 
level of the best controlled similar source and the MACT floor (99 
percent UPL) which includes the variability across the best controlled 
similar source and the long term variability of that source.

                 Table 5--Summary of MACT Floor Results for the Fuel-Related HAP for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                                        Mercury Lb/    HCl Lb/
                Subcategory                           Parameter            PM Lb/MMBtu     MMBtu        MMBtu
----------------------------------------------------------------------------------------------------------------
Units designed for Coal firing............  Avg of top performer.........     0.000396     1.18E-07     3.85E-05
                                            99% UPL of top performer          0.000928     3.89E-07     5.21E-05
                                             (test runs).
Units designed for Biomass firing.........  Avg of top performer.........      0.00216     9.73E-08     7.85E-04
                                            99% UPL of top performer           0.00711     1.86E-07     3.07E-03
                                             (test runs).
Units designed for Liquid Fuel firing.....  Avg of top performer.........     0.000511     5.87E-08     3.99E-04
                                            99% UPL of top performer           0.00154     2.47E-07     9.80E-04
                                             (test runs).
Units designed for other gas firing.......  Avg of top performer.........      0.00042     8.25E-08     1.70E-06
                                            99% UPL of top performer            0.0024     1.86E-07     2.50E-06
                                             (test runs).
----------------------------------------------------------------------------------------------------------------

2. Determination of MACT for Organic HAP
    In developing the MACT floor for organic HAP, as described earlier, 
we are using CO as a surrogate for non-dioxin organic HAP. Table 6 
presents for each subcategory and CO and D/F the average emission level 
of the best controlled similar source and the MACT floor (99 percent 
UPL) which includes the variability across the best controlled similar 
source and the long term variability of that source.

                   Table 6--Summary of MACT Floor Results for the Organic HAP for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                                                  Dioxin/Furan
                                                                                 CO (ppm @ 3    (TEQ) (ng/dscm @
                 Subcategory                             Parameter             percent oxygen)      7 percent
                                                                                                     oxygen)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal................................  Avg of top performer..........              4.29          1.52E-03
                                              99% UPL of top performer (test              6.53          2.82E-03
                                               runs).
Fluidized Bed--Coal.........................  Avg of top performer..........              8.26          9.05E-06
                                              99% UPL of top performer (test             *39.9          2.54E-05
                                               runs).
PC--Coal....................................  Avg of top performer..........              25.0          1.04E-03
                                              99% UPL of top performer (test             *97.5          1.47E-03
                                               runs).
Stoker--Biomass.............................  Avg of top performer..........               920          1.52E-05
                                              99% UPL of top performer (test             *3730          4.86E-05
                                               runs).
Fluidized Bed--Biomass......................  Avg of top performer..........              25.8          2.27E-03
                                              99% UPL of top performer (test              34.2          6.48E-03
                                               runs).
Suspension Burner/Dutch Oven................  Avg of top performer..........               352          9.52E-03
                                              99% UPL of top performer (test             *1050          2.79E-02
                                               runs).
Fuel Cell--Biomass..........................  Avg of top performer..........               110          2.42E-04

[[Page 32029]]

 
                                              99% UPL of top performer (test              *264          4.17E-04
                                               runs).
Units designed for Liquid fuel firing.......  Avg of top performer..........             0.125          1.09E-03
                                              99% UPL of top performer (test             0.125          1.52E-03
                                               runs).
Units designed for other gases firing.......  Avg of top performer..........            0.0129          2.67E-03
                                              99% UPL of top performer (test            0.0129          8.28E-03
                                               runs).
----------------------------------------------------------------------------------------------------------------
* Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit
  for the same subcategory.

    For organic HAP, as previously discussed above for the fuel-
related, we account for variability in setting floors, not only because 
variability is an element of performance, but because it is reasonable 
to assess best performance over time. Here, we know that CO (as a 
surrogate for non-dioxin organic HAP) emissions does not vary 
significantly over the operating range of the unit. Thus, we have not 
added any additional operational variability to account for operation 
at lower capacity rates.
    We are proposing a work practice standard under section 112(h) that 
would require an annual tune-up for new boilers and process heaters 
combusting natural gas or refinery gas. These boilers and process 
heaters are units included in the Gas 1 and metal processing furnace 
subcategories. We are specifically seeking comment on whether the 
application of measurement methodology to sources in this subcategory 
is impracticable due to technological or economic limitations, as 
specified in section 112(h)(2)(B).
    This proposal for new boilers and process heaters combusting 
natural gas or refinery gas is based on the same reasons discussed 
previously for existing boilers and process heaters combusting natural 
gas or refinery gas. That is, we believe that proposing emission 
standards for new gas-fired boilers and process heaters that result in 
the need to employ the same emission control system as needed for the 
other fuel types would have the negative benefit of providing a 
disincentive for switching to gas as a control technique (and a 
pollution prevention technique) for boilers and process heaters in the 
other fuel subcategories. In addition, emission limits on gas-fired 
boilers and process heaters may have the negative benefit of providing 
an incentive for a facility to switch from gas (considered a ``clean'' 
fuel) to a ``dirtier'' but cheaper fuel (i.e., coal). It would be 
inconsistent with the emissions reductions goals of the CAA, and of 
section 112 in particular, to adopt requirements that would result in 
an overall increase in HAP emissions. We are soliciting comment on the 
extent to which new facilities would be expected to switch away from 
natural gas to a ``dirtier'' fuel if emissions limits for new such 
facilities are adopted.
    Thus, a work practice, as discussed above for existing boilers and 
process heaters combusting natural gas or refinery gas, is being 
proposed to limit the emission of HAP for new natural gas-fired and 
refinery gas-fired boilers and process heaters.
    We request comments on whether the emission limits listed in Table 
7 of this preamble for new units in the Gas 1 and Metal Process Furnace 
subcategories should be promulgated. Comments should include detailed 
information regarding why emission limits for these gas-fired boilers 
and process heaters are appropriate.

                        Table 7--Summary of MACT Floor Results for New Units in the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Dioxin/Furan
                                                                                                                            CO (ppm @ 3     (Total TEQ)
                Subcategory                           Parameter             PM Lb/MMBtu     Mercury Lb/    HCl LB/MMBtu       percent      (ng/dscm @ 7
                                                                                               MMBtu                          oxygen)         percent
                                                                                                                                              oxygen)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing...........  Avg of top performer........         0.00013         9.4E-08         7.3E-05               5          0.0026
                                            99% UPL of top (test runs) =          0.0005         2.0E-07          0.0002              20            0.01
Metal Process Furnaces....................  Avg of top performer........          0.0065         3.3E-08         8.6E-05             0.5          0.0026
                                            99% UPL of top (test runs) =            0.02         2.0E-07          0.0002               2           0.004
--------------------------------------------------------------------------------------------------------------------------------------------------------

I. How did EPA consider beyond-the-floor for new units?

    The MACT floor level of control for new units is based on the 
emission control that is achieved in practice by the best controlled 
similar source within each of the subcategories. No technologies were 
identified that would achieve HAP reduction greater than the new source 
floors for the subcategories.
    Fuel switching to natural gas is a potential regulatory option 
beyond the new source floor level of control that would reduce HAP 
emissions from non-gas-fired units. However, based on current trends 
within the industry, EPA projects that the majority of new boilers and 
process heaters will be built to fire natural gas as opposed to solid 
and liquid fuels such that the overall emissions reductions associated 
with this option would be minimal. In addition, natural gas supplies 
are not available in some areas, and supplies to industrial customers 
can be limited during periods when natural gas demand exceeds supply. 
Thus, this potential control option may be unavailable to many sources 
in practice. Limited emissions reductions in combination with the high 
cost of fuel switching and considerations about the

[[Page 32030]]

availability and technical feasibility of fuel switching makes this an 
unreasonable regulatory option that was not considered further.\14\ 
Nonair quality health, environmental impacts, and energy effects were 
not significant factors. No beyond-the-floor options for gas-fired 
boilers were identified.
---------------------------------------------------------------------------

    \14\ Memorandum ``Development (2010) of Fuel Switching Costs and 
Emission Reductions for Industrial, Commercial, and Institutional 
Boilers and Process Heaters National Emission Standards for 
Hazardous Air Pollutants,'' April 2010.
---------------------------------------------------------------------------

    An energy assessment is a beyond-the-floor standard being proposed 
for existing facilities. However, we are not proposing it as a beyond-
the-floor option for new major source facilities since we believe it 
would not be cost effective because most projected new boilers or 
process heaters will be installed at existing major source facility 
which would have already conducted an energy assessment as required by 
this proposed rule. We also believe that any new greenfield major 
source facility having boilers or process heaters will be designed to 
operate with energy efficiency.
    Based on the analysis discussed above, EPA decided to not go beyond 
the MACT floor level of control for new sources in this proposed rule. 
A detailed description of the beyond-the-floor consideration is in the 
memorandum ``Methodology for Estimating Cost and Emissions Impacts for 
Industrial, Commercial, Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants'' in the 
docket.

J. Consideration of whether to set standards for HCl and other acid 
gases under section 112(d)(4)

    We are proposing to set a conventional MACT standard for HCl and, 
for the reasons explained elsewhere in today's notice, are proposing 
that the HCl limit also serve as a surrogate for other acid gas HAP. We 
also considered whether it was appropriate to exercise our 
discretionary authority to establish health-based emission standards 
under section 112(d)(4) for HCl and each of the other relevant HAP acid 
gases: Chlorine (Cl2), hydrogen fluoride (HF), and hydrogen 
cyanide (HCN) \15\ (since if it were regulated under section 112(d)(4), 
HCl may no longer be the appropriate surrogate for these other 
HAPs).\16\ This section sets forth the requirements of section 
112(d)(4), our analysis of the information available to us that 
informed the decision on whether to exercise discretion, questions 
regarding the application of 112(d)(4) and solicitation of comments, 
and explains how this case relates to prior decisions EPA has made 
under section 112(d)(4) with respect to HCl.
---------------------------------------------------------------------------

    \15\ Before considering whether to exercise her discretion under 
section 112(d)(4) for a particular pollutant, the Administrator must 
first conclude that a health threshold has been established for the 
pollutant.
    \16\ HCl can serve as a surrogate for the other acid gases in a 
technology-based MACT standard, because the control technology that 
would be used to control HCl would also reduce the other acid gases. 
By contrast, HCl would not be an appropriate surrogate for a health-
based emission standard that is protective against the potential 
adverse health effects from the other acid gases, because these 
gases (e.g., HCN) can act on biological organisms in a different 
manner than HCl, and each of the acid gases affects human health 
with a different dose-response relationship.
---------------------------------------------------------------------------

    As a general matter, section 112(d) requires MACT standards at 
least as stringent as the MACT floor to be set for all HAP emitted from 
major sources. However, section 112(d)(4) provides that for HAP with 
established health thresholds, the Administrator has the discretionary 
authority to consider such health thresholds when establishing emission 
standards under section 112(d). This provision is intended to allow EPA 
to establish emission standards other than conventional MACT standards, 
in cases where a less stringent emission standard will still ensure 
that the health threshold will not be exceeded, with an ample margin of 
safety. In order to exercise this discretion, EPA must first conclude 
that the HAP at issue has an established health threshold and must then 
provide for an ample margin of safety when considering the health 
threshold to set an emission standard.
    The legislative history of section 112(d)(4) indicates that 
Congress did not intend for this provision to provide a mechanism for 
EPA to delay issuance of emission standards for sources of HAPs. 
Finally, the legislative history also indicates that a health-based 
emission limit under section 112(d)(4) should be set at the level at 
which no observable effects occur, with an ample margin of safety. S. 
Rep. 101-228 at 171-72.
    It is clear the Administrator may exercise her discretionary 
authority under 112(d)(4) only with respect to pollutants with an 
health threshold. Where there is an established threshold, the 
Administrator interprets section 112(d)(4) to allow her to weigh 
additional factors, beyond any established health threshold, in making 
a judgment whether to set a standard for a specific pollutant based on 
the threshold, or instead follow the traditional path of developing a 
MACT standard after determining a MACT floor. In deciding whether to 
exercise her discretion for a threshold pollutant for a given source 
category, the Administrator interprets section 112(d)(4) to allow her 
to take into account factors such as the following: The potential for 
cumulative adverse health effects due to concurrent exposure to other 
HAPs with similar biological endpoints, from either the same or other 
source categories, where the concentration of the threshold pollutant 
emitted from the given source category is below the threshold; the 
potential impacts on ecosystems of releases of the pollutant; and 
reductions in criteria pollutant emissions and other co-benefits that 
would be achieved via the MACT standard. Each of these factors is 
directly relevant to the health and environmental outcomes at which 
section 112 of the Clean Air Act is fundamentally aimed. If the 
Administrator does determine that it is appropriate to set a standard 
based on a health threshold, she must develop emission standards that 
will ensure the public will not be exposed to levels of the pertinent 
HAP in excess of the health threshold, with an ample margin of safety.
    EPA has exercised its discretionary authority under section 
112(d)(4) in a handful of prior actions setting emissions standards for 
other major source categories, including the emissions standards issued 
in 2004 for commercial and industrial boilers and process heaters, 
which were vacated on other grounds by the U.S. Court of Appeals for 
the D.C. Circuit. In both the Pulp and Paper MACT, 63 FR at 18765 
(April 15, 1998), and Lime Manufacturing MACT, 67 FR at 78054 (December 
20, 2002), EPA invoked 112(d)(4) for HCl emissions for discrete units 
within the facility. In those actions, EPA concluded that HCl had an 
established health threshold (in those cases it was interpreted as the 
reference concentration for chronic effects, or RfC) and was not 
classified as a human carcinogen. In light of the absence of evidence 
of carcinogenic risk, the availability of information on non-
carcinogenic effects, and the limited potential health risk associated 
with the discrete units being regulated, EPA concluded that it was 
appropriate to exercise its discretion under section 112(d)(4) for HCl 
under the circumstances of those actions. EPA did not set an emission 
standard based on the health threshold; rather, the exercise of EPA's 
discretion in those cases in effect exempted HCl from the MACT 
requirement. In a more recent action, EPA decided not to propose a 
health-based emission standard for HCl

[[Page 32031]]

emissions under section 112(d)(4) for Portland Cement facilities, 74 FR 
at 21154 (May 6, 2009). EPA has never implemented a NESHAP that used 
section 112(d)(4) with respect to HF, Cl2 or HCN.\17\
---------------------------------------------------------------------------

    \17\ EPA has not classified HF, chlorine gas, or HCN with 
respect to carcinogenicity. However, at this time the Agency is not 
aware of any data that would suggest any of these HAPs are 
carcinogens.
---------------------------------------------------------------------------

    Since any emission standard under section 112(d)(4) must consider 
the established health threshold level, with an ample margin of safety, 
in this rulemaking EPA has considered the adverse health effects of the 
HAP acid gases, beginning with HCl. Research indicates that HCl is 
associated with chronic respiratory toxicity. In the case of HCl, this 
means that chronic inhalation of HCl can cause tissue damage in humans. 
Among other things, it is corrosive to mucous membranes and can cause 
damage to eyes, nose, throat, and the upper respiratory tract as well 
as pulmonary edema, bronchitis, gastritis, and dermatitis. Considering 
this respiratory toxicity, EPA has established a chronic reference 
concentration (RfC) for the inhalation of HCl of 20 [mu]g/m\3\. An RfC 
is defined as an estimate (with uncertainty spanning perhaps an order 
of magnitude) of a continuous inhalation exposure to the human 
population (including sensitive subgroups \18\) that is likely to be 
without an appreciable risk of deleterious effects during a lifetime. 
The development of the RfC for HCl reflected data only on its chronic 
respiratory toxicity. It did not take into account effects associated 
with acute exposure,\19\ and, in this situation, the IRIS health 
assessment did not evaluate the potential carcinogenicity of HCl (on 
which there are very limited studies). As a reference value for a 
single pollutant, the RfC also did not reflect any potential cumulative 
or synergistic effects of an individual's exposure to multiple HAPs or 
to a combination of HAPs and criteria pollutants. As the RfC 
calculation focused on health effects, it did not take into account the 
potential environmental impacts of HCl.
---------------------------------------------------------------------------

    \18\ ``Sensitive subgroups'' may refer to particular life 
stages, such as children or the elderly, or to those with particular 
medical conditions, such as asthmatics.
    \19\ California EPA considered acute toxicity and established a 
1-hour reference exposure level (REL) of 2.1 mg/m\3\. An REL is the 
concentration level at or below which no adverse health effects are 
anticipated for a specified exposure duration. RELs are designed to 
protect the most sensitive individuals in the population by the 
inclusion of margins of safety.
---------------------------------------------------------------------------

    With respect to the potential health effects of HCl, we know the 
following:
    1. Chronic exposure to concentrations at or below the RfC is not 
expected to cause chronic respiratory effects;
    2. Little research has been conducted on its carcinogenicity. The 
one occupational study of which we are aware found no evidence of 
carcinogenicity;
    3. There is a significant body of scientific literature addressing 
the health effects of acute exposure to HCl (California Office of 
Health Hazard Assessment, 2008. Acute Toxicity Summary for Hydrogen 
Chloride,  http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_final.pdf#page=112 EPA, 2001). However, we currently lack information 
on the peak short-term emissions of HCl from boilers, which might allow 
us to determine whether a chronic health-based emission standard for 
HCl would ensure that acute exposures will not pose any health 
concerns;
    4. We are aware of no studies explicitly addressing the toxicity of 
mixtures of HCl with other respiratory irritants. However, many of the 
other HAPs (and criteria pollutants) emitted by boilers also are 
respiratory irritants, and in the absence of information on 
interactions, EPA assumes an additive cumulative effect (Supplementary 
Guidance for Conducting Health Risk Assessment of Chemical Mixtures.  
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=20533). The fact 
that boilers can be located among a wide variety of industrial 
facilities makes predicting and assessing all possible mixtures of HCl 
and other emitted air pollutants difficult, if not impossible.
    In addition to potential health impacts, the Administrator also has 
evaluated the potential for environmental impacts when considering 
whether to exercise her discretion under section 112(d)(4). The 
legislative history states that employing a section 112(d)(4) standard 
rather than a conventional MACT standard ``shall not result in adverse 
environmental effects which would otherwise be reduced or eliminated.'' 
S. Rep. 101-228 at 171. When HCl gas encounters water in the 
atmosphere, it forms an acidic solution of hydrochloric acid. In areas 
where the deposition of acids derived from emissions of sulfur and 
nitrogen oxides are causing aquatic and/or terrestrial acidification, 
with accompanying ecological impacts, the deposition of hydrochloric 
acid could exacerbate these impacts. Being mindful of the legislative 
history, it is appropriate to consider potential adverse environmental 
effects in addition to adverse health effects when setting an emission 
standard for HCl under section 112(d)(4).
    Because the statute requires an ample margin of safety, it would be 
reasonable to set any section 112(d)(4) emission standard for a 
pollutant with a health threshold at a level that at least assures 
that, for the sources in the controlled category or subcategory, 
persons exposed to emissions of the pollutant would not experience the 
adverse health effects on which the threshold is based. In the case of 
this proposed rulemaking, we have concluded that we do not have 
sufficient information at this time to establish what the health-based 
emission standards would be for HCl or the other acid gases. Public 
comments are invited on our information and conclusion.
    When Congress established the technology-based MACT program in the 
1990 Clean Air Act Amendments, it recognized the challenges involved in 
evaluating health risk. Determining an emission standard that will 
protect the public health with an ample margin of safety is complex, in 
part because of the limited data available on cumulative impacts. In 
order to assess the feasibility of health-based standards in this rule, 
the agency believes it would need additional facility-specific 
emissions information. Such information would enable us to develop 
model plants for the eleven subcategories considered in the proposed 
rule and allow us to conduct the dispersion modeling necessary to 
establish health-based emission limits. These limits would need to be 
established to ensure that exposure is below the health threshold for 
sources in the subcategory, and account for the possibility of multiple 
exposures from co-located sources as well as potential short-term 
increases in emissions for these sources and their short-term impacts. 
Currently, the Agency has very limited information on facility-specific 
emissions, plant configurations, and overall fence-line characteristics 
for this large and diverse source category. This information is a 
precondition to establishing health-based emission standards that 
provide an ample margin of safety. To this end, the Agency is 
requesting information on these factors from the regulated community 
and others to allow us to evaluate the appropriateness and viability of 
health-based emission limits.
    EPA specifically requests comment on the following issues. 
Additional information on these issues is important to implement 
section 112(d)(4) in a reasonable and appropriate manner, if we were to 
establish emissions standards under that provision. First,

[[Page 32032]]

EPA requests comment on whether it would be appropriate to establish 
section 112(d)(4) standards for each acid gas described above, or 
whether EPA could set a single 112(d)(4) standard for one of the acid 
gases as a surrogate for the other acid gases. Commenters who believe a 
surrogate would be appropriate should also address the mechanism that 
should be used to determine the appropriate surrogate. In order to set 
individual standards under section 112(d)(4) for each acid gas, we 
would need to be able to conclude that each has an appropriate health 
threshold, that there is no scientific evidence that they are 
carcinogenic, and that the emission standard for each uses the best 
available science to consider the possibility of toxicologic 
interactions with the other emitted gases. Alternatively, if we were to 
establish a health-based emission standard for one of the acid gases as 
a surrogate for the others, in addition to the above considerations, we 
would need to demonstrate, based on a knowledge of the effectiveness of 
scrubbers for controlling each of the acid gases, that the surrogate 
emission standard effectively ensures that ambient levels of each of 
the other acid gases do not exceed their respective chronic health 
thresholds.
    EPA also solicits comments on whether there would be an additive 
effect if individual section 112(d)(4) standards are established for 
each acid gas, and if so, how we would simulate that effect. Individual 
acid gas standards under section 112(d)(4) would likely be established 
using the hazard quotient (HQ) approach, under which we would develop 
the ratio of the maximum ambient level to the chronic threshold. 
However, this approach would not by itself account for potential 
toxicologic interactions. Since all of the acid gases are respiratory 
irritants, one way to account for potential toxicologic interactions of 
these pollutants would be the use of the hazard index (HI) approach, as 
described in EPA's ``Guideline for the Health Risk Assessment of 
Chemical Mixtures.'' EPA requests comment on that approach, and on 
whether there are any other approaches to address such additive 
effects.
    Additionally, EPA requests comment on whether we should consider 
the affected sources (boilers) by themselves, or whether we should 
consider all HAP emissions at the facility when developing a 112(d)(4) 
standard. Given that section 112(d)(4) requires an ``ample margin of 
safety,'' EPA believes it should consider all reasonable circumstances 
in order to ensure such a margin. Since boilers are, in many cases, 
located at industrial sites with significant additional sources of HAP 
(e.g., petroleum refineries, furniture manufacturers, etc.), EPA 
requests comment on how we should consider the potential interactions 
of acid gases with other emitted respiratory irritants at these 
locations if we were to develop emission limits under section 
112(d)(4). Commenters are requested to provide any actual data that is 
available to make this type of demonstration. If no data are available, 
we request comment on whether such a demonstration could be made using 
a bounding calculation.
    EPA also requests comment on whether we should consider HAP 
emissions from neighboring facilities, and, if so, what the geographic 
scope of such consideration should be (e.g., 1 km, 3 km, etc.). We note 
that consideration of emissions from nearby facilities is a more 
difficult task than consideration of facility-wide emissions, since it 
requires information on all potential HAP emissions near all of the 
locations with boilers. Therefore, we request comment on whether such 
emissions should be considered in setting section 112(d)(4) emissions 
standards, and if so, how they should be considered. For example, the 
consideration could be limited in geographic scope (e.g., a radius of 3 
km), or could be based on ``average'' or ``high-end'' ambient levels of 
respiratory irritants seen in recent monitoring data or modeled 
estimates, since site-specific data might not be available on all 
respiratory irritants.
    Further, EPA requests comment on how to appropriately simulate all 
reasonable facility/exposure situations (e.g., using worst-case 
facility emissions coupled with worst-case population proximity, 
average emissions and population, or 90th percentile emissions and 
population). Such a simulation could be based on a sequential 
examination of the facilities with the highest-emitting boilers on-site 
using site-specific data, or it could use screening or bounding 
methodologies with high-end or worst-case exposure assumptions to 
remove facilities from a more site-specific examination. We request 
comment on these and other approaches.
    Finally, we considered the fact that setting conventional MACT 
standards for HCl as well as PM (as a surrogate for metals including 
manganese) would result in significant reductions in emissions of other 
pollutants, most notably SO2, non-condensable PM, and other 
non-HAP acid gases (e.g., hydrogen bromide) and would likely also 
result in additional reductions in emissions of mercury and other HAP 
metals (e.g., selenium). The additional reductions of SO2 
alone attributable to the proposed MACT standard for HCl are estimated 
to be 340,000 tons per year in the third year following promulgation of 
the proposed HCl standard. These are substantial reductions with 
substantial public health benefits. Although MACT standards may 
directly address only HAPs, not criteria pollutants, Congress did 
recognize, in the legislative history to section 112(d)(4), that MACT 
standards would have the collateral benefit of controlling criteria 
pollutants as well and viewed this as an important benefit of the air 
toxics program.\20\ Therefore, even where EPA concludes a HAP has a 
health threshold, the Agency may consider such benefits as a factor in 
determining whether to exercise its discretion under section 112(d)(4).
---------------------------------------------------------------------------

    \20\ See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172
---------------------------------------------------------------------------

    Given the limitations of the currently available information (i.e., 
the HAP mix where boilers are located, and the cumulative health 
impacts from co-located sources), the environmental effects of HCl, and 
the significant co-benefits of setting a conventional MACT standard for 
HCl, the Administrator is proposing not to exercise her discretion to 
use section 112(d)(4).
    This conclusion is not contrary to EPA's prior decisions where we 
found it appropriate to exercise the discretion to invoke the authority 
in section 112(d)(4) for HCl, since the circumstances in this case 
differ from previous considerations. Boilers and process heaters differ 
from the other source categories for which EPA has exercised its 
authority under section 112(d)(4) in ways that affect consideration of 
any health threshold for HCl. Commercial and industrial boilers and 
process heaters are much more likely to be co-located with multiple 
other sources of HAPs than are pulp and paper mills and lime 
manufacturing facilities. In addition, boilers and process heaters are 
often located at facilities in heavily populated urban areas where many 
other sources of HAPs exist. These factors make an analysis of the 
health impact of emissions from these sources on the exposed population 
significantly more complex than for many other source categories, and 
therefore make it more difficult to establish an ample margin of 
safety.
    Given the particular complexities of this source category (the 
location of boilers and process heaters near other significant sources 
of HAP emissions

[[Page 32033]]

and the use of HCl as a surrogate for other HAPs), we solicit comment 
on all of the conclusions in this section, including the way the agency 
has used 112(d)(4) previously, and in particular whether it would be 
feasible and appropriate to establish such a standard and, if so, the 
methodology by which it could be established.

K. How did we select the compliance requirements?

    We are proposing testing, monitoring, notification, and 
recordkeeping requirements that are adequate to assure continuous 
compliance with the requirement of this proposed rule. These 
requirements are described in detail in sections IV.K to IV.N. We 
selected these requirements based upon our determination of the 
information necessary to ensure that the emission standards and work 
practices are being followed and that emission control devices and 
equipment are maintained and operated properly. These proposed 
requirements ensure compliance with this proposed rule without imposing 
a significant additional burden for facilities that must implement 
them.
    We are proposing that compliance with the emission limits for PM, 
HCl, mercury, CO, and D/F be demonstrated by an initial performance 
test. To ensure continuous compliance with the proposed PM, HCl, and 
mercury emission limits, this proposed rule would require continuous 
parameter monitoring of control devices and recordkeeping. 
Additionally, this proposed rule would require annual performance tests 
to ensure, on an ongoing basis, that the air pollution control device 
is operating properly and its performance has not deteriorated. If 
initial compliance with the mercury and/or HCl emission limits are 
demonstrated by a fuel analysis performance test, this proposed rule 
would require fuel analyses monthly, with compliance determined based 
on an annual average.
    We evaluated the feasibility and cost of applying PM CEMS to 
boilers and process heaters. CEMS have been used in Europe to monitor 
PM emissions from a variety of industrial sources. Several electric 
utility companies in the United States have now installed or are 
planning to install PM CEMS. In recognition of the fact that PM CEMS 
are commercially available, EPA developed and promulgated Performance 
Specifications (PS) for PM CEMS (69 FR 1786, January 12, 2004). PS for 
PM CEMS are established under PS-11 in appendix B to 40 CFR part 60 for 
evaluating the acceptability of a PM CEM used for determining 
compliance with the emission standards on a continuous basis. For PM 
CEM monitoring, capital costs were estimated to be $88,000 per unit and 
annualized costs were estimated to be $33,000 per unit. We determined 
that requiring PM CEMS for units with heat input capacity greater or 
equal to 250 MMBtu/hr and combusting either coal, biomass, or oil is a 
reasonable monitoring option. We are requesting comment on the 
application of PM CEMS to boilers and process heaters, and the use of 
data from such systems for compliance determinations under this 
proposed rule.
    We reviewed cost information for CO CEMS to make the determination 
on whether to require CO CEMS or conducting annual CO testing to 
demonstrate continuous compliance with the CO emission limit. In 
evaluating the available cost information, we determined that requiring 
CO CEMS for units with heat input capacities greater or equal to 100 
MMBtu/hr is reasonable. This proposed rule would require units with 
heat input capacities less than 100 MMBtu/hr to conduct initial and 
annual performance (stack) tests.
    The majority of test methods that this proposed rule would require 
for the performance stack tests have been required under many other EPA 
standards. The only applicable voluntary consensus standard identified 
is ASTM Method D6784-02 (Ontario Hydro). The majority of emissions 
tests upon which the proposed emission limits are based were conducted 
using these test methods.
    When a performance test is conducted, we are proposing that 
parameter operating limits be determined during the tests. Performance 
tests to demonstrate compliance with any applicable emission limits are 
either stack tests or fuel analysis or a combination of both.
    To ensure continuous compliance with the proposed emission limits 
and/or operating limits, this proposed rule would require continuous 
parameter monitoring of control devices and recordkeeping. We selected 
the following requirements based on reasonable cost, ease of execution, 
and usefulness of the resulting data to both the owners or operators 
and EPA for ensuring continuous compliance with the emission limits 
and/or operating limits.
    We are proposing that certain parameters be continuously monitored 
for the types of control devices commonly used in the industry. These 
parameters include opacity monitoring except for wet scrubbers; pH, 
pressure drop and liquid flowrate for wet scrubbers; and sorbent 
injection rate for dry scrubbers. You must also install a bag leak 
detection system for fabric filters. If you cannot monitor opacity for 
control systems with an ESP then you must monitor the secondary current 
and voltage or total power input for the ESP. These monitoring 
parameters have been used in other standards for similar industries. 
The values of these parameters are established during the initial or 
most recent performance test that demonstrates compliance. These values 
are your operating limits for the control device.
    You would be required to set parameters based on 4-hour block 
averages during the compliance test, and demonstrate continuous 
compliance by monitoring 12-hour block average values for most 
parameters. We selected this averaging period to reflect operating 
conditions during the performance test to ensure the control system is 
continuously operating at the same or better level as during a 
performance test demonstrating compliance with the emission limits.
    To demonstrate continuous compliance with the emission and 
operating limits, you would also need daily records of the quantity, 
type, and origin of each fuel burned and hours of operation of the 
affected source. If you are complying with the chlorine fuel input 
option, you must keep records of the calculations supporting your 
determination of the chlorine content in the fuel.
    If a source elected to demonstrate compliance with the HCl or 
mercury limit by using fuel which has a statistically lower pollutant 
content than the emission limit, we are proposing that the source's 
operating limit is the emission limit of the applicable pollutant. 
Under this option, a source is not required to conduct performance 
stack tests. If a source demonstrates compliance with the HCl or 
mercury limit by using fuel with a statistically higher pollutant 
content than the applicable emission limit, but performance tests 
demonstrate that the source can meet the emission limits, then the 
source's operating limits are the operating limits of the control 
device (if used) and the fuel pollutant content of the fuel type/
mixture burned.
    This proposed rule would specify the testing methodology and 
procedures and the initial and continuous compliance requirements to be 
used when complying with the fuel analysis options. Fuel analysis tests 
for total chloride, gross calorific value, mercury, sample collection, 
and sample

[[Page 32034]]

preparation are included in this proposed rule.
    If you elect to comply based on fuel analysis, you will be required 
to statistically analyze, using the z-test, the data to determine the 
90th percentile confidence level. It is the 90th percentile confidence 
level that is required to be used to determine compliance with the 
applicable emission limit. The statistical approach is required to 
assist in ensuring continuous compliance by statistically accounting 
for the inherent variability in the fuel type.
    We are proposing that a source be required to recalculate the fuel 
pollutant content only if it burns a new fuel type or fuel mixture and 
conduct another performance test if the results of recalculating the 
fuel pollutant content are higher than the level established during the 
initial performance test.
    For boilers and process heaters with heat input capacities greater 
or equal to 100 MMBtu/hr, we are proposing that CO be continuously 
monitored to demonstrate that average CO emissions, on a 30-day rolling 
average, are at or below the proposed CO limit.
    For boilers and process heaters with heat input capacities between 
10 and 100 MMBtu/hr, we are proposing that a performance stack test of 
CO emissions be conducted to demonstrate compliance with the CO 
emission limit.

L. What alternative compliance provisions are being proposed?

    We are proposing that owners and operators of existing affected 
sources may demonstrate compliance by emissions averaging for units at 
the affected source that are within a single subcategory.
    As part of the EPA's general policy of encouraging the use of 
flexible compliance approaches where they can be properly monitored and 
enforced, we are including emissions averaging in this proposed rule. 
Emissions averaging can provide sources the flexibility to comply in 
the least costly manner while still maintaining regulation that is 
workable and enforceable. Emissions averaging would not be applicable 
to new sources and could only be used between boilers and process 
heaters in the same subcategory at a particular affected source. Also, 
owners or operators of existing sources subject to the Industrial 
Boiler NSPS (40 CFR part 60, subparts Db and Dc) would be required to 
continue to meet the PM emission standard of that NSPS regardless of 
whether or not they are using emissions averaging.
    Emissions averaging would allow owners and operators of an affected 
source to demonstrate that the source complies with the proposed 
emission limits by averaging the emissions from an individual affected 
unit that is emitting above the proposed emission limits with other 
affected units at the same facility that are emitting below the 
proposed emission limits.
    This proposed rule includes an emissions averaging compliance 
alternative because emissions averaging represents an equivalent, more 
flexible, and less costly alternative to controlling certain emission 
points to MACT levels. We have concluded that a limited form of 
averaging could be implemented that would not lessen the stringency of 
the MACT floor limits and would provide flexibility in compliance, cost 
and energy savings to owners and operators. We also recognize that we 
must ensure that any emissions averaging option can be implemented and 
enforced, will be clear to sources, and most importantly, will be no 
less stringent than unit by unit implementation of the MACT floor 
limits.
    EPA has concluded that it is permissible to establish within a 
NESHAP a unified compliance regimen that permits averaging within an 
affected source across individual affected units subject to the 
standard under certain conditions. Averaging across affected units is 
permitted only if it can be demonstrated that the total quantity of any 
particular HAP that may be emitted by that portion of a contiguous 
major source that is subject to the NESHAP will not be greater under 
the averaging mechanism than it could be if each individual affected 
unit complied separately with the applicable standard. Under this test, 
the practical outcome of averaging is equivalent to compliance with the 
MACT floor limits by each discrete unit, and the statutory requirement 
that the MACT standard reflect the maximum achievable emissions 
reductions is, therefore, fully effectuated.
    In past rulemakings, EPA has generally imposed certain limits on 
the scope and nature of emissions averaging programs. These limits 
include: (1) No averaging between different types of pollutants, (2) no 
averaging between sources that are not part of the same affected 
source, (3) no averaging between individual sources within a single 
major source if the individual sources are not subject to the same 
NESHAP, and (4) no averaging between existing sources and new sources.
    This proposed rule would fully satisfy each of these criteria. 
First, emissions averaging would only be permitted between individual 
sources at a single existing affected source, and would only be 
permitted between individual sources subject to the boiler and process 
heater NESHAP. Further, emissions averaging would not be permitted 
between two or more different affected sources. Finally, new sources 
could not use emissions averaging. Accordingly, we have concluded that 
the averaging of emissions across affected units is consistent with the 
CAA. In addition, the proposed rule would require each facility that 
intends to utilize emission averaging to submit an emission averaging 
plan, which provides additional assurance that the necessary criteria 
will be followed. In this emission averaging plan, the facility must 
include the identification of (1) all units in the averaging group, (2) 
the control technology installed, (3) the process parameter that will 
be monitored, (4) the specific control technology or pollution 
prevention measure to be used, (5) the test plan for the measurement of 
the HAP being averaged, and (6) the operating parameters to be 
monitored for each control device. Upon receipt, the regulatory 
authority would not be able to approve an emission averaging plan 
containing averaging between emissions of different types of pollutants 
or between sources in different subcategories.
    This proposed rule would also exclude new affected sources from the 
emissions averaging provision. EPA believes emissions averaging is not 
appropriate for new sources because it is most cost effective to 
integrate state-of-the-art controls into equipment design and to 
install the technology during construction of new sources. One reason 
we allow emissions averaging is to give existing sources flexibility to 
achieve compliance at diverse points with varying degrees of add-on 
control already in place in the most cost-effective and technically 
reasonable fashion. This flexibility is not needed for new sources 
because they can be designed and constructed with compliance in mind.
    With concern about the equivalency of emissions reductions from 
averaging and non-averaging in mind, we are also proposing under the 
emission averaging provision caps on the current emissions from each of 
the sources in the averaging group. The emissions for each unit in the 
averaging group would be capped at the emission level being achieved on 
the effective date of the final rule. These caps would ensure that 
emissions do not increase above the emission levels that sources 
currently are designed, operated, and maintained to achieve. In the 
absence of performance tests, in documenting these

[[Page 32035]]

caps, these sources will document the type, design, and operating 
specification of control devices installed on the effective date of the 
final rule to ensure that existing controls are not removed or operated 
less efficiently. By including this provision in this proposed rule, we 
would further ensure that emission averaging results in environmental 
benefits equivalent to or better than without emission averaging.
    In addition, we are proposing that a discount factor of ten percent 
would be applied when emissions averaging is used. This discount factor 
will further ensure that averaging will be at least as stringent as the 
MACT floor limits in the absence of averaging. The EPA is soliciting 
comment on use of a discount factor and whether ten percent is the 
appropriate discount factor. The emissions averaging provision would 
not apply to individual units if the unit shares a common stack with 
units in other subcategories, because in that circumstance it is not 
possible to distinguish the emissions from each individual unit.
    The emissions averaging provisions in this proposed rule are based 
in part on the emissions averaging provisions in the Hazardous Organic 
NESHAP (HON). The legal basis and rational for the HON emissions 
averaging provisions were provided in the preamble to the final HON (59 
FR 19425, April 22, 1994).

M. How did EPA determine compliance times for the proposed rule?

    Section 112 of the CAA specifies the dates by which affected 
sources must comply with the emission standards. New or reconstructed 
units must be in compliance with this proposed rule immediately upon 
startup or [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], 
whichever is later. Existing sources are allowed 3 years to comply with 
the final rule. This is the maximum period allowed by the CAA. We 
believe that 3 years for compliance is necessary to allow adequate time 
to design, install and test control systems that will be retrofitted 
onto existing boilers, as well as obtain permits for the use of add-on 
controls.

N. How did EPA determine the required records and reports for this 
proposed rule?

    You would be required to comply with the applicable requirements in 
the NESHAP General Provisions, subpart A of 40 CFR part 63, as 
described in Table 10 of the proposed subpart DDDDD. We evaluated the 
General Provisions requirements and included those we determined to be 
the minimum notification, recordkeeping, and reporting necessary to 
ensure compliance with, and effective enforcement of, this proposed 
rule.
    We are also requiring that you keep daily records of the total fuel 
use by each affected source, subject to an emission limit or work 
practice standard, along with a description of the fuel, the total fuel 
usage amounts and units of measure, and information on the supplier and 
original source of the fuel. This information is necessary to ensure 
that the affected source is complying with the emission limits from the 
correct subcategory.
    We would require additional recordkeeping if you chose to comply 
with the chlorine or mercury fuel input option. You would need to keep 
records of the calculations and supporting information used to develop 
the chlorine or mercury fuel input operating limit.

O. How does this proposed rule affect permits?

    The CAA requires that sources subject to this proposed rule be 
operated pursuant to a permit issued under EPA-approved State operating 
permit program. The operating permit programs are developed under title 
V of the CAA and the implementing regulations under 40 CFR parts 70 and 
71. If you are operating in the first 3 years of your operating permit, 
you will need to obtain a revised permit to incorporate this proposed 
rule. If you are in the last 2 years of your operating permit, you will 
need to incorporate this proposed rule into the next renewal of your 
permit.

P. Alternate Standard for Consideration

    As discussed above, EPA is proposing a definition of non-hazardous 
solid waste under RCRA in a concurrent notice. The proposed CAA section 
112(d) standards for boilers and process heaters were developed 
considering that proposed definition of solid waste. Therefore, the 
emission limits presented in Tables 1 through 5 above are based on 
subcategories established considering sources that are ICI boilers and 
process heaters under the proposed definition of solid waste under 
RCRA. However, the RCRA proposal also identifies and solicits comment 
on an alternative approach for defining solid waste, under which more 
units would be considered solid waste incineration units than under the 
proposed definition. As such, the alternative approach for defining 
solid waste under RCRA would result in a different, smaller population 
of units being covered by Boiler MACT. Consistent with EPA's 
solicitation of comment on an alternative proposed definition of solid 
waste under RCRA, we calculated MACT floors using emission rates for 
units that would be ICI boilers and process heaters under that 
alternative definition, using the same statistical procedures that were 
used to calculate the standards that are being proposed. Table 6 
reflects that calculation of MACT floor limits for the existing source 
subcategories that would be changed by the alternative definition of 
solid waste identified in the concurrent RCRA proposal, compared to the 
proposed definition of solid waste in that proposal. The MACT floor 
limits for the remaining existing source subcategories (Gas 1, Gas 2, 
and Liquid) would not change under the alternative definition of solid 
waste on which EPA is soliciting comment in the concurrent RCRA 
proposal, and are therefore not included in Table 8 because the MACT 
floor limits for those subcategories would be the same under the 
alternative definition of solid waste as under the proposed definition.

  Table 8--Existing MACT Floor Limits Using The ``Alternative Approach'' Under Consideration and Comment in the
                                         Concurrently Proposed RCRA Rule
                                   [Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
                                                                                                     Dioxins/
                                   Particulate      Hydrogen                     Carbon monoxide   Furans (total
          Subcategory              matter (PM)   chloride (HCl)   Mercury (Hg)    (CO) (ppm @ 3%  TEQ) (ng/dscm)
                                                                                     oxygen)          @ 7% O2
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker..........            0.03            0.02         4.0E-06               40         0.003
Existing--Coal Fluidized Bed...            0.03            0.02         4.0E-06               50         0.008
Existing--Pulverized Coal......            0.03            0.02         4.0E-06               90         0.004

[[Page 32036]]

 
Existing--Biomass Stoker.......            0.02            0.03         5.0E-07              180         0.00005
Existing--Biomass Fluidized Bed            0.02            0.03         5.0E-07           10,650         0.1
Existing--Biomass Suspension               0.02            0.03         5.0E-07            1,060         0.3
 Burner/Dutch Oven.............
Existing--Biomass Fuel Cells...            0.02            0.03         5.0E-07              460         0.02
----------------------------------------------------------------------------------------------------------------

    Comparing the emissions limits in Table 1 (based on the proposed 
definition of solid waste) with those in Table 8 (based on the 
alternative definition of solid waste), the MACT emission limits for PM 
and mercury for the biomass subcategories would be less stringent if 
they are based on the alternative definition of solid waste while the 
HCl emission limits for the coal and biomass subcategories would be 
more stringent if they are based on the alternative definition.
    The potential emissions reductions if the MACT floor limits are 
calculated based on the alternative definition of solid waste would be 
generally lower than the potential emissions reductions for MACT floors 
based on the proposed definition of solid waste, because 280 fewer 
boilers and process heaters would be subject to the boiler and process 
heater MACT standards under the alternative definition. These units 
would instead be considered CISWI units under the alternative 
definition of solid waste. For example, mercury emissions reduction 
would be 7 tons per year based on the alternative definition of solid 
waste (compared to 8 tons per year based on the proposed definition) 
and HCl emissions reduction would be 5,100 tons per year based on the 
alternative definition (compared to 37,000 tons per year based on the 
proposed definition). Most (181) of the 280 units that would be 
considered CISWI units under the alternative definition of solid waste 
proposed under RCRA are biomass-fired boilers or process heaters, with 
the others being in the coal and liquid fuel subcategories.
    The resulting total national cost impact for existing boilers and 
process heaters of the proposed emission limits based on the 
alternative definition of solid waste would be 8.0 billion dollars in 
capital expenditures and 2.4 billion dollars per year in total annual 
costs. This compares to $9.5 billion in capital costs and $2.9 billion 
in annual costs under the proposed definition of solid waste in the 
RCRA proposed rule. Table 9 of this preamble shows the capital and 
annual cost impacts for each subcategory under the alternative 
definition of solid waste. Costs include testing and monitoring costs, 
but not recordkeeping and reporting costs.

 Table 9--Summary of Capital and Annual Costs for Existing Sources Under the Alternative Solid Waste Definition
----------------------------------------------------------------------------------------------------------------
                                                                 Estimated/ projected     Capital     Annualized
               Source                       Subcategory           number of affected       costs         cost
                                                                        units             (10\6\$)   (10\6\$/yr)
----------------------------------------------------------------------------------------------------------------
Existing Units......................  Coal units.............  525....................        3,861        1,508
                                      Biomass units..........  239....................        1,250          317
                                      Liquid units...........  791....................        1,352          417
                                      Gas (NG/RG) units......  11,524.................           75          259
                                      Gas (other) units......  196....................        1,476          434
Energy Assessment...................  ALL....................  1,551 facilities.......  ...........         24.9
----------------------------------------------------------------------------------------------------------------

    A discussion of the methodology used to estimate cost impacts is 
presented in ``Methodology and Results of Estimating the Cost of 
Complying with the Industrial, Commercial, and Institutional Boiler and 
Process Heater NESHAP (2010)'' in the Docket.
    We are soliciting public comments on the emission limits listed in 
Table 6 of this preamble, consistent with EPA's solicitation of 
comments on the alternative definition of solid waste concurrently 
proposed under RCRA. As explained above, the MACT floor limits proposed 
today are based on the proposed definition of solid waste under RCRA. 
However, because EPA is seeking comment on an alternative definition of 
solid waste under RCRA, the Agency believes it is necessary to also 
solicit comment on what the MACT floor limits would be based on the 
universe of sources that would be subject to the boiler and process 
heater MACT under that alternative definition.

V. Impacts of the Proposed Rule

A. What are the air impacts?

    Table 10 of this preamble illustrates, for each basic fuel 
subcategory, the emissions reductions achieved by the proposed rule 
(i.e., the difference in emissions between a boiler or process heater 
controlled to the floor level of control and boilers or process heaters 
at the current baseline) for new and existing sources. Nationwide 
emissions of selected HAP (i.e., HCl, HF, mercury, metals, and VOC) 
will be reduced by 43,000 tons per year for existing units and 15 tons 
per year for new units. Emissions of HCl will be reduced by 37,000 tons 
per year for existing units and 9 tons per year for new units. 
Emissions of mercury will be reduced by 8 tons per year for existing 
units and 2.6 pounds per year for new units. Emissions of filterable PM 
will be reduced by 50,100 tons per year for existing units and 130 tons 
per year for new units. Emissions of non-mercury

[[Page 32037]]

metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, 
lead, manganese, nickel, and selenium) will be reduced by 3,200 tons 
per year for existing units and will be reduced by 0.6 ton per year for 
new units. In addition, emissions of SO2 are estimated to be 
reduced by 340,000 tons per year for existing sources and 500 tons per 
year for new sources. Emissions of dioxin/furans, on a total mass 
basis, will be reduced by 722 grams per year for existing units and 1 
gram per year for new units. A discussion of the methodology used to 
estimate emissions and emissions reductions is presented in 
``Estimation of Baseline Emissions and Emissions Reductions for 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
(2010)'' in the docket.

                     Table 10--Summary of Emissions Reductions for Existing and New Sources
                                                    [Tons/yr]
----------------------------------------------------------------------------------------------------------------
                                                                               Non
            Source                Subcategory        HCl           PM        mercury      Mercury        VOC
                                                                            metals \a\
----------------------------------------------------------------------------------------------------------------
Existing Units...............  Coal units......       35,450       17,000          770          7.1          490
                               Biomass units...          520       22,500          230          0.2          760
                               Liquid units....          840       10,400        2,200      0.00005          290
                               Gas 1 (NG/RG)               9          130          1.2         0.01           72
                                units.
                               Gas 2 (other)             220            0            0          0.2          170
                                units.
New Units....................  Coal units......            0            0            0            0            0
                               Biomass units...            0            0            0            0            0
                               Liquid units....            9          130          0.6       0.0007            3
                               Gas 1 units.....         0.01          0.1        0.001     0.000008         0.01
                               Gas 2 units.....            1            4         0.01       0.0006            1
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.

B. What are the water and solid waste impacts?

    The EPA estimated the additional water usage that would result from 
installing wet scrubbers to meet the emission limits for HCl would be 
2,400 million gallons per year for existing sources and 200,000 gallons 
per year for new sources. In addition to the increased water usage, an 
additional 730 million gallons per year of wastewater would be produced 
for existing sources and 140,000 gallons per year for new sources. The 
annual costs of treating the additional wastewater are $4.0 million for 
existing sources and $774 for new sources. These costs are accounted 
for in the control costs estimates.
    The EPA estimated the additional solid waste that would result from 
the MACT floor level of control to be 81,000 tons per year for existing 
sources and 149,800 tons per year for new sources. Solid waste is 
generated from flyash and dust captured in PM and mercury controls as 
well as from spent carbon that is injected into exhaust streams or used 
to filter gas streams. The costs of handling the additional solid waste 
generated are $3.4 million for existing sources and $6.3 million for 
new sources. These costs are also accounted for in the control costs 
estimates.
    A discussion of the methodology used to estimate impacts is 
presented in ``Estimation of Impacts for Industrial, Commercial, and 
Institutional Boilers and Process Heaters NESHAP (2010)'' in the 
Docket.

C. What are the energy impacts?

    The EPA expects an increase of approximately 2.995 million kilowatt 
hours (kWh) in national annual energy usage as a result of the proposed 
rule. Of this amount, 2,944 million kWh would be from existing sources 
and 11 million kWh are estimated from new sources. The increase results 
from the electricity required to operate control devices, such as wet 
scrubbers, electrostatic precipitators, and fabric filters which are 
expected to be installed to meet the proposed rule. Additionally, the 
EPA expects work practice standards such as boilers tune-ups and 
combustion controls will improve the efficiency of boilers, resulting 
in an estimated fuel savings of 42 trillion BTU each year from existing 
sources and an additional 100,000 million BTU each year. This fuel 
savings estimate includes only those fuel savings resulting from gas, 
liquid, and coal fuels and it is based on the assumption that the work 
practice standards will achieve 1 percent improvement in efficiency.

D. What are the control costs?

    To estimate the national cost impacts of the proposed rule for 
existing sources, we developed average baseline emission factors for 
each fuel type/control device combination based on the emission data 
obtained and contained in the Boiler MACT emission database. If a unit 
reported emission data, we assigned its unit-specific emission data as 
its baseline emissions. For units that did not report emission data, we 
assigned the appropriate emission factors to each existing unit in the 
inventory database, based on the average emission factors for boilers 
with similar fuel, design, and control devices. We then compared each 
unit's baseline emission factors to the proposed MACT floor emission 
limit to determine if control devices were needed to meet the emission 
limits. The control analysis considered fabric filters, carbon bed 
adsorbers, and activated carbon injection to be the primary control 
devices for mercury control, electrostatic precipitators for units 
meeting mercury limits but requiring additional control to meet the PM 
limits, wet scrubbers to meet the HCl limits, tune-ups, replacement 
burners, and combustion controls for CO and organic HAP control, and 
carbon injection for dioxin/furan control. We identified where one 
control device could achieve reductions in multiple pollutants, for 
example a fabric filter was expected to achieve both PM and mercury 
control in order to avoid overestimating the costs. We also included 
costs for testing and monitoring requirements contained in the proposed 
rule. The resulting total national cost impact of the proposed rule is 
9.5 billion dollars in capital expenditures and 3.2 billion dollars per 
year in total annual costs. Considering estimated fuel savings 
resulting from work practice standards and combustion controls, the 
total annualized costs are reduced to 2.9 billion dollars. The total 
capital and annual costs include costs for control devices, work 
practices, testing and monitoring. Table 11 of this preamble shows the 
capital and annual

[[Page 32038]]

cost impacts for each subcategory. Costs include testing and monitoring 
costs, but not recordkeeping and reporting costs.

                   Table 11--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                                     Annualized
                                                             Estimated/                Testing and  cost (10\6\$/
                                                             projected     Capital     monitoring        yr)
               Source                     Subcategory        number of      costs      annualized   (considering
                                                              affected     (10\6\$)       costs         fuel
                                                               units                   (10\6\$/yr)    savings)
----------------------------------------------------------------------------------------------------------------
Existing Units.....................  Coal units...........          578        4,468         62.4         1,619
                                     Biomass units........          420        2,003         35.5           609
                                     Liquid units.........          826        1,389         27.4           419
                                     Gas (NG/RG) units....       11,532           75          0            (260)
                                     Gas (other) units....          199        1,554         10.4           459
Energy Assessment..................  ALL..................  ...........  ...........  ............           26
New Units..........................  Coal units...........            0            0          0               0
                                     Biomass units........            0            0          0               0
                                     Liquid units.........           11           12          0.5           6.1
                                     Gas (NG/RG) units....           33          0.2          0            0.01
                                     Gas (other) units....            2          5.5          0.14          1.7
----------------------------------------------------------------------------------------------------------------

    Using Department of Energy projections on fuel expenditures, the 
number of additional boilers that could be potentially constructed was 
estimated. The resulting total national cost impact of the proposed 
rule in the 3rd year is 17 million dollars in capital expenditures and 
6.2 million dollars per year in total annual costs, when considering a 
1 percent fuel savings.
    Potential control device cost savings and increased recordkeeping 
and reporting costs associated with the emissions averaging provisions 
in the proposed rule are not accounted for in either the capital or 
annualized cost estimates.
    A discussion of the methodology used to estimate cost impacts is 
presented in ``Methodology and Results of Estimating the Cost of 
Complying with the Industrial, Commercial, and Institutional Boiler and 
Process Heater NESHAP (2010)'' in the Docket.

E. What are the economic impacts?

    The economic impact analysis (EIA) that is included in the RIA 
shows that the expected prices for industrial sectors could be 0.01 
percent higher and domestic production may fall by about 0.01 percent. 
Because of higher domestic prices imports may rise by 0.01 percent. In 
addition, impacts to affected energy markets show that prices may rise 
by 0.04 percent.
    Social costs are estimated to also be $2.9 billion in 2008 dollars. 
This is estimated to be made up of a $0.8 billion loss in domestic 
consumer surplus, a $2.5 billion loss in domestic producer surplus, a 
$0.1 billion increase in rest of the world surplus, and a $0.4 billion 
in net fuel savings not modeled in a way that can be used to attribute 
it to consumers and producers.
    EPA performed a screening analysis for impacts on small entities by 
comparing compliance costs to sales/revenues (e.g., sales and revenue 
tests). EPA's analysis found the tests were typically higher than 3 
percent for small entities included in the screening analysis. EPA has 
prepared an Initial Regulatory Flexibility Analysis (IRFA) that 
discusses alternative regulatory or policy options that minimize the 
rule's small entity impacts. It includes key information about key 
results from the Small Business Advocacy Review (SBAR) panel.
    Precise job effect estimates cannot be estimated with certainty. 
Morgenstern et al. (2002) identify three economic mechanisms by which 
pollution abatement activities can indirectly influence jobs:
     Higher production costs raise market prices, higher prices 
reduce consumption, and employment within an industry falls (``demand 
effect'');
     Pollution abatement activities require additional labor 
services to produce the same level of output (``cost effect''); and
     Post regulation production technologies may be more or 
less labor intensive (i.e., more/less labor is required per dollar of 
output) (``factor-shift effect'').
    Several empirical studies, including Morgenstern et al. (2002), 
suggest the net employment decline is zero or economically small (e.g., 
Cole and Elliot, 2007; Berman and Bui, 2001). However, others show the 
question has not been resolved in the literature (Henderson, 1996; 
Greenstone, 2002). Morgenstern's paper uses a six-year panel (U.S. 
Census data for plant-level prices, inputs (including labor), outputs, 
and environmental expenditures) to econometrically estimate the 
production technologies and industry-level demand elasticities. Their 
identification strategy leverages repeat plant-level observations over 
time and uses plant-level and year fixed effects (e.g., plant and time 
dummy variables). After estimating their model, Morgenstern show and 
compute the change in employment associated with an additional $1 
million ($1987) in environmental spending. Their estimates covers four 
manufacturing industries (pulp and paper, plastics, petroleum, and 
steel) and Morgenstern, et al. present results separately for the cost, 
factor shift, and demand effects, as well as the net effect. They also 
estimate and report an industry-wide average parameter that combines 
the four industry-wide estimates and weighting them by each industry's 
share of environmental expenditures.
    EPA has most often estimated employment changes associated with 
plant closures due to environmental regulation or changes in output for 
the regulated industry (EPA, 1999a; EPA, 2000). This analysis goes 
beyond what EPA has typically done in two ways. First, because the 
multimarket model provides estimates for changes in output for sectors 
not directly regulated, we were able to estimate a more comprehensive 
``demand effect.'' Secondly, parameters estimated in the Morgenstern 
paper were used to estimate all three effects (``demand,'' ``cost,'' 
and ``factor shift''). This transfer of results from the Morgenstern 
study is uncertain but avoids ignoring the ``cost effect'' and the 
``factor-shift effect.''
    We calculated ``demand effect'' employment changes by assuming that 
the number of jobs changes proportionally with multi-market model's 
simulated output changes. These results were calculated for all

[[Page 32039]]

sectors in the EPA model that show a change in output. The total job 
losses are estimated to be approximately 6,000.
    We also calculated a similar ``demand effect'' estimate that used 
the Morgenstern paper. To do this, we multiplied the point estimate for 
the total demand effect (-3.56 jobs per million ($1987) of 
environmental compliance expenditure) by the total environmental 
compliance expenditures used in the partial equilibrium model. For 
example, the job loss estimate is approximately 7,000 jobs (-3.56 x 
$3.5 billion x 0.60).\21\
---------------------------------------------------------------------------

    \21\ Since Morgenstern's analysis reports environmental 
expenditures in $1987, we make an inflation adjustment the 
engineering cost analysis using GDP implicit price deflator (64.76/
108.48) = 0.60).
---------------------------------------------------------------------------

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

                   Table 12--Employment Changes: 2013
------------------------------------------------------------------------
                     Estimation method                       1,000 Jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets) (demand                 -5
 effect only).............................................
Literature-based estimate (net effect [A + B + C below])..           +3
                                                             (-6 to +12)
    A. Literature-based estimate: Demand effect...........           -7
                                                             (-15 to +1)
    B. Literature-based estimate: Cost effect.............           +5
                                                              (+2 to +8)
    C. Literature-based estimate: Factor shift effect.....           +5
                                                              (0 to +10)
------------------------------------------------------------------------
Note: Totals may not add due to independent rounding. 95 percent
  confidence intervals for literature-based estimates are shown in
  parenthesis.

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

    We estimate the monetized benefits of this proposed regulatory 
action to be $17 billion to $41 billion (2008$, 3 percent discount 
rate) in the implementation year (2013). The monetized benefits of the 
proposed regulatory action at a 7 percent discount rate are $15 billion 
to $37 billion (2008$). Using alternate relationships between 
PM2.5 and premature mortality supplied by experts, higher 
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\22\ A summary of the 
monetized benefits estimates at discount rates of 3 percent and 7 
percent is in Table 13 of this preamble.
---------------------------------------------------------------------------

    \22\ Roman et al., 2008. Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S. Environ. Sci. Technol., 42, 7, 2268--2274.

[[Page 32040]]



  Table 13--Summary of the Monetized Benefits Estimates for the Proposed Boiler MACT for Major Sources in 2013
                                             [Billions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                            Estimated
                                             emission
                                            reductions    Total monetized benefits     Total monetized benefits
                                            (tons per        (3% discount rate)           (7% discount rate)
                                              year)
----------------------------------------------------------------------------------------------------------------
PM2.5....................................       29,020  $6.6 to $16................  $6.0 to $15.
PM2.5 Precursors
    SO2..................................      339,996  $10 to $25.................  $9.1 to $22.
    VOC..................................        1,786  $0.002 to $0.005...........  $0.002 to $0.005.
                                          ----------------------------------------------------------------------
        Total............................  ...........  $17 to $41.................  $15 to $37.
----------------------------------------------------------------------------------------------------------------
\1\All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers
  may not sum across rows. All fine particles are assumed to have equivalent health effects, but the benefit-per-
  ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form
  PM2.5. Benefits from reducing hazardous air pollutants (HAPs) are not included.

    These benefits estimates represent the total monetized human health 
benefits for populations exposed to less PM2.5 in 2013 from 
controls installed to reduce air pollutants in order to meet these 
standards. These estimates are calculated as the sum of the monetized 
value of avoided premature mortality and morbidity associated with 
reducing a ton of PM2.5 and PM2.5 precursor 
emissions. To estimate human health benefits derived from reducing 
PM2.5 and PM2.5 precursor emissions, we utilized 
the general approach and methodology on the laid out in Fann et al. 
(2009).\23\
---------------------------------------------------------------------------

    \23\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The influence 
of location, source, and emission type in estimates of the human 
health benefits of reducing a ton of air pollution.'' Air Qual Atmos 
Health (2009) 2:169-176.
---------------------------------------------------------------------------

    To generate the benefit-per-ton estimates, we used a model to 
convert emissions of direct PM2.5 and PM2.5 
precursors into changes in ambient PM2.5 levels and another 
model to estimate the changes in human health associated with that 
change in air quality. Finally, the monetized health benefits were 
divided by the emission reductions to create the benefit-per-ton 
estimates. Even though we assume that all fine particles have 
equivalent health effects, the benefit-per-ton estimates vary between 
precursors because each ton of precursor reduced has a different 
propensity to form PM2.5. For example, SOX has a 
lower benefit-per-ton estimate than direct PM2.5 because it 
does not form as much PM2.5, thus the exposure would be 
lower, and the monetized health benefits would be lower.
    For context, it is important to note that the magnitude of the PM 
benefits is largely driven by the concentration response function for 
premature mortality. Experts have advised EPA to consider a variety of 
assumptions, including estimates based both on empirical 
(epidemiological) studies and judgments elicited from scientific 
experts, to characterize the uncertainty in the relationship between 
PM2.5 concentrations and premature mortality. For this 
proposed rule we cite two key empirical studies, one based on the 
American Cancer Society cohort study \24\ and the extended Six Cities 
cohort study.\25\ In the RIA for this proposed rule, which is available 
in the docket, we also include benefits estimates derived from expert 
judgments and other assumptions.
---------------------------------------------------------------------------

    \24\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary 
Mortality, and Long-term Exposure to Fine Particulate Air 
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
    \25\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    This analysis does not include the type of detailed uncertainty 
assessment found in the 2006 PM2.5 NAAQS RIA because we lack 
the necessary air quality input and monitoring data to run the benefits 
model. However, the 2006 PM2.5 NAAQS benefits analysis \26\ 
provides an indication of the sensitivity of our results to various 
assumptions.
---------------------------------------------------------------------------

    \26\ U.S. Environmental Protection Agency, 2006. Final 
Regulatory Impact Analysis: PM2.5 NAAQS. Prepared by 
Office of Air and Radiation. October. Available on the Internet at 
http://www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    It should be emphasized that the monetized benefits estimates 
provided above do not include benefits from several important benefit 
categories, including reducing other air pollutants, ecosystem effects, 
and visibility impairment. The benefits from reducing carbon monoxide 
and hazardous air pollutants have not been monetized in this analysis, 
including reducing 330,000 tons of carbon monoxide, 37,000 tons of HCl, 
1,000 tons of HF each year, 7.5 tons of mercury, 3,200 tons of other 
metals, and 720 grams of dioxins/furans each year. Although we do not 
have sufficient information or modeling available to provide monetized 
estimates for this rulemaking, we include a qualitative assessment of 
the health effects of these air pollutants in the Regulatory Impact 
Analysis (RIA) for this proposed rule, which is available in the 
docket.
    The social costs of this proposed rulemaking are estimated to be 
$2.9 billion (2008$) in the implementation year, and the monetized 
benefits are $17 billion to $41 billion (2008$, 3 percent discount 
rate) for that same year. The benefits at a 7 percent discount rate are 
$15 billion to $37 billion (2008$). Thus, net benefits of this 
rulemaking are estimated at $14 billion to $38 billion (2008$, 3 
percent discount rate) and $12 billion to $34 billion (2008$, 7 percent 
discount rate). EPA believes that the benefits of the proposed rule are 
likely to exceed the costs even when taking into account the 
uncertainties in the cost and benefit estimates. A summary of the 
monetized benefits, social costs, and net benefits at discount rates of 
3 percent and 7 percent is in Table 14 of this preamble.

[[Page 32041]]



   Table 14--Summary of the Monetized Benefits, Social Costs, and Net
          Benefits for the Boiler MACT (Major Sources) in 2013
                         [Millions of 2008$] \1\
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
                             Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $17 to $41........  $15 to $37.
------------------------------------------------------------------------
Total Social Costs \3\..........  $2.9..............  $2.9.
------------------------------------------------------------------------
Net Benefits....................  $14 to $38........  $12 to $34.
------------------------------------------------------------------------
Non-monetized Benefits..........  340,000 tons of carbon monoxide.
                                  37,000 tons of HCl.
                                  1,000 tons of HF.
                                  7.5 tons of mercury.
                                  3,200 tons of other metals.
                                  720 grams of dioxins/furans.
                                  Health effects from NO2 and SO2
                                   exposure.
                                  Ecosystem effects.
                                  Visibility impairment.
 
         sProposed Option with Alternate Solid Waste Definition
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $3.1 to $7.7......  $2.8 to $6.9.
------------------------------------------------------------------------
Total Social Costs \3\..........  $2.2..............  $2.2.
------------------------------------------------------------------------
Net Benefits....................  $0.93 to $5.5.....  $0.64 to $4.7.
------------------------------------------------------------------------
Non-monetized Benefits..........  280,000 tons of carbon monoxide.
                                  5,100 tons of HCl.
                                  1,100 tons of HF.
                                  7.1 tons of mercury.
                                  1,600 tons of other metals.
                                  290 grams of dioxins/furans.
                                  Health effects from NO2 and SO2
                                   exposure.
------------------------------------------------------------------------
                                  Ecosystem effects.
------------------------------------------------------------------------
                                  Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
  rounded to two significant figures.
\2\ The total monetized benefits reflect the human health benefits
  associated with reducing exposure to PM2.5 through reductions of
  directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is
  important to note that the monetized benefits include many but not all
  health effects associated with PM2.5 exposure.
\3\ The methodology used to estimate social costs for one year in the
  multimarket model using surplus changes results in the same social
  costs for both discount rates.

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

VI. Public Participation and Requests for Comment

    We request comment on all aspects of this proposed rule.
    In 2004 we published a final rule for boilers and process heaters 
located at major source facilities (69 FR 55218, September 13, 2004). 
The final rule was vacated and remanded by the Court on June 19, 2007. 
We are reissuing our proposal, in response to the Court's decisions, in 
this notice. We received many comments on that vacated rule during its 
rulemaking and have attempted to take all those comments into account 
in this action. This proposal includes a variety of changes from the 
vacated rule, mostly centered on emission limits for the various HAP 
and subcategories.
    During this rulemaking, we conducted outreach to small entities and 
convened a Small Business Advocacy Review (SBAR) Panel to obtain advice 
and recommendation of representatives of the small entities that 
potentially would be subject to the requirements of this proposed rule. 
As part of the SBAR Panel process we conducted outreach with 
representatives from various small entities that would be affected by 
this proposed rule. We met with these small entity representatives 
(SERs) to discuss the potential rulemaking approaches and potential 
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials 
included background on the rulemaking, possible regulatory approaches, 
preliminary cost and economic impacts, and possible rulemaking 
alternatives. We met with SERs from the industries that will be 
impacted directly by this proposed rule to discuss the outreach 
materials and receive feedback on the approaches and alternatives 
detailed in the outreach packet. The Panel received written comments 
from the SERs following the meeting in response to discussions at the 
meeting and the questions posed to the SERs by the Agency. The SERs 
were specifically asked to provide comment on regulatory alternatives 
that could help to minimize the rule's impact on small businesses.

[[Page 32042]]

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

    Section 112(c)(6) of the CAA requires EPA to identify categories of 
sources of seven specified pollutants to assure that sources accounting 
for not less than 90 percent of the aggregate emissions of each such 
pollutant are subject to standards under CAA Section 112(d)(2) or 
112(d)(4). EPA has identified ``Industrial Coal Combustion,'' 
``Industrial Oil Combustion,'' Industrial Wood/Wood Residue 
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
categories that emits two of the seven CAA Section 112(c)(6) 
pollutants: POM and mercury. (The POM emitted is composed of 16 
polyaromatic hydrocarbons and extractable organic matter.) In the 
Federal Register notice Source Category Listing for Section 112(d)(2) 
Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838, 
17849, Table 2 (1998), EPA identified ``Industrial Coal Combustion,'' 
``Industrial Oil Combustion,'' ``Industrial Wood/Wood Residue 
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
category ``subject to regulation'' for purposes of CAA Section 
112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that 
these units emit.
    Specifically, as byproducts of combustion, the formation of POM is 
effectively reduced by the combustion and post-combustion practices 
required to comply with the CAA Section 112 standards. Any POM that do 
form during combustion are further controlled by the various post-
combustion controls. The add-on PM control systems (either fabric 
filter or wet scrubber) and activated carbon injection in the fabric 
filter-based systems further reduce emissions of these organic 
pollutants, and also reduce mercury emissions, as is evidenced by 
performance data. Specifically, the emission tests obtained at 
currently operating units show that the proposed MACT regulations will 
reduce mercury emissions by about 86 percent. It is, therefore, 
reasonable to conclude that POM emissions will be substantially 
controlled. Thus, while this proposed rule does not identify specific 
numerical emission limits for POM, emissions of POM are, for the 
reasons noted below, nonetheless ``subject to regulation'' for purposes 
of Section 112(c)(6) of the CAA.
    In lieu of establishing numerical emissions limits for pollutants 
such as POM, we regulate surrogate substances. While we have not 
identified specific numerical limits for POM, we believe CO serves as 
an effective surrogate for this HAP, because CO, like POM, is formed as 
a byproduct of combustion.
    Consequently, we have concluded that the emissions limits for CO 
function as a surrogate for control of POM, such that it is not 
necessary to propose numerical emissions limits for POM with respect to 
boilers and process heaters to satisfy CAA Section 112(c)(6).
    To further address POM and mercury emissions, this proposed rule 
also includes an energy assessment provision that encourages 
modifications to the facility to reduce energy demand that lead to 
these emissions.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is an ``economically significant regulatory action'' because it 
is likely to have an annual effect on the economy of $100 million or 
more or adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities.
    Accordingly, EPA submitted this action to the Office of Management 
and Budget (OMB) for review under EO 12866 and any changes in response 
to OMB recommendations have been documented in the docket for this 
action. For more information on the costs and benefits for this rule, 
please refer to Table 14 of this preamble.

B. Executive Order 13132, Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications.'' ``Policies that have 
federalism implications'' is defined in the Executive Order to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.
    This proposed rule does not have federalism implications. It will 
not have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. Thus, Executive Order 13132 does 
not apply to this proposed rule. In the spirit of Executive Order 
13132, and consistent with EPA policy to promote communications between 
EPA and State and local governments, EPA specifically solicited comment 
on this proposed rule from State and local officials.

C. Executive Order 13175, Consultation and Coordination With Indian 
Tribal Governments

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

D. Executive Order 13045, Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any 
rule that: (1) Is determined to be ``economically significant'' as 
defined under Executive Order 12866, and (2) concerns an environmental 
health or safety risk that EPA has reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health or 
safety effects of this planned rule on children, and explain why this 
planned regulation is preferable to other potentially effective

[[Page 32043]]

and reasonably feasible alternatives considered by the Agency.
    This proposed rule is not subject to Executive Order 13045 because 
the Agency does not believe the environmental health risks or safety 
risks addressed by this action present a disproportionate risk to 
children. The reason for this determination is that this proposed rule 
is based solely on technology performance.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to this 
proposed rule.

E. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, we 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
1 year. Before promulgating a rule for which a written statement is 
needed, section 205 of the UMRA generally requires us to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows us to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, we must develop a small 
government agency plan under section 203 of the UMRA. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    We have determined that this proposed rule contains a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and Tribal governments, in the aggregate, or the private 
sector in any 1 year. Accordingly, we have prepared a written statement 
entitled ``Unfunded Mandates Reform Act Analysis for the Proposed 
Industrial Boilers and Process Heaters NESHAP'' under section 202 of 
the UMRA which is summarized below.
1. Statutory Authority
    As discussed in section I of this preamble, the statutory authority 
for this proposed rulemaking is section 112 of the CAA. Title III of 
the CAA Amendments was enacted to reduce nationwide air toxic 
emissions. Section 112(b) of the CAA lists the 188 chemicals, 
compounds, or groups of chemicals deemed by Congress to be HAP. These 
toxic air pollutants are to be regulated by NESHAP.
    Section 112(d) of the CAA directs us to develop NESHAP which 
require existing and new major sources to control emissions of HAP 
using MACT based standards. This NESHAP applies to all industrial, 
commercial, and institutional boilers and process heaters located at 
major sources of HAP emissions.
    In compliance with section 205(a) of the UMRA, we identified and 
considered a reasonable number of regulatory alternatives. Additional 
information on the costs and environmental impacts of these regulatory 
alternatives is presented in the docket.
    The regulatory alternative upon which the proposed rule is based 
represents the MACT floor for industrial boilers and process heaters 
and, as a result, it is the least costly and least burdensome 
alternative.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for the proposed rule 
including the Agency's assessment of costs and benefits, is detailed in 
the ``Regulatory Impact Analysis for the Proposed Industrial Boilers 
and Process Heaters MACT'' in the docket. Based on estimated compliance 
costs associated with the proposed rule and the predicted change in 
prices and production in the affected industries, the estimated social 
costs of the proposed rule are $2.9 billion (2008 dollars).
    It is estimated that 3 years after implementation of the proposed 
rule, HAPs would be reduced by thousands of tons, including reductions 
in hydrochloric acid, hydrogen fluoride, metallic HAP including 
mercury, and several other organic HAP from boilers and process 
heaters. Studies have determined a relationship between exposure to 
these HAP and the onset of cancer, however, the Agency is unable to 
provide a monetized estimate of the HAP benefits at this time. In 
addition, there are significant reductions in PM2.5 and in 
SO2 that would occur, including 29 thousand tons of 
PM2.5 and 340 thousand tons of SO2. These 
reductions occur within 3 years after the implementation of the 
proposed regulation and are expected to continue throughout the life of 
the affected sources. The major health effect associated with reducing 
PM2.5 and PM2.5 precursors (such as 
SO2) is a reduction in premature mortality. Other health 
effects associated with PM2.5 emission reductions include 
avoiding cases of chronic bronchitis, heart attacks, asthma attacks, 
and work-lost days (i.e., days when employees are unable to work). 
While we are unable to monetize the benefits associated with the HAP 
emissions reductions, we are able to monetize the benefits associated 
with the PM2.5 and SO2 emissions reductions. For 
SO2 and PM2.5, we estimated the benefits 
associated with health effects of PM but were unable to quantify all 
categories of benefits (particularly those associated with ecosystem 
and visibility effects). Our estimates of the monetized benefits in 
2013 associated with the implementation of the proposed alternative is 
a range from $17 billion (2008 dollars) to $41 billion (2008 dollars) 
when using a 3 percent discount rate (or from $15 billion (2008 
dollars) to $37 billion (2008 dollars) when using a 7 percent discount 
rate). This estimate, at a 3 percent discount rate, is about $14 
billion (2008 dollars) to $38 billion (2008 dollars) higher than the 
estimated social costs shown earlier in this section. The general 
approach used to value benefits is discussed in more detail earlier in 
this preamble. For more detailed information on the benefits estimated 
for the proposed rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
    The Unfunded Mandates Act requires that we estimate, where accurate 
estimation is reasonably feasible, future compliance costs imposed by 
the proposed rule and any disproportionate budgetary effects. Our 
estimates of the future compliance costs of the proposed rule are 
discussed previously in this preamble.
    We do not believe that there will be any disproportionate budgetary 
effects of the proposed rule on any particular areas of the country, 
State or local governments, types of communities

[[Page 32044]]

(e.g., urban, rural), or particular industry segments. See the results 
of the ``Economic Impact Analysis of the Proposed Industrial Boilers 
and Process Heaters NESHAP,'' the results of which are discussed 
previously in this preamble.
4. Effects on the National Economy
    The Unfunded Mandates Act requires that we estimate the effect of 
the proposed rule on the national economy. To the extent feasible, we 
must estimate the effect on productivity, economic growth, full 
employment, creation of productive jobs, and international 
competitiveness of the U.S. goods and services, if we determine that 
accurate estimates are reasonably feasible and that such effect is 
relevant and material.
    The nationwide economic impact of the proposed rule is presented in 
the ``Economic Impact Analysis for the Industrial Boilers and Process 
Heaters MACT'' in the docket. This analysis provides estimates of the 
effect of the proposed rule on some of the categories mentioned above. 
The results of the economic impact analysis are summarized previously 
in this preamble. The results show that there will be a small impact on 
prices and output, and little impact on communities that may be 
affected by the proposed rule. In addition, there should be little 
impact on energy markets (in this case, coal, natural gas, petroleum 
products, and electricity). Hence, the potential impacts on the 
categories mentioned above should be small.
5. Consultation With Government Officials
    The Unfunded Mandates Act requires that we describe the extent of 
the Agency's prior consultation with affected State, local, and tribal 
officials, summarize the officials' comments or concerns, and summarize 
our response to those comments or concerns. In addition, section 203 of 
the UMRA requires that we develop a plan for informing and advising 
small governments that may be significantly or uniquely impacted by a 
proposal. Although the proposed rule does not affect any State, local, 
or Tribal governments, we have consulted with State and local air 
pollution control officials. We also have held meetings on the proposed 
rule with many of the stakeholders from numerous individual companies, 
environmental groups, consultants and vendors, labor unions, and other 
interested parties. We have added materials to the Air Docket to 
document these meetings.
    In addition, we have determined that the proposed rule contains no 
regulatory requirements that might significantly or uniquely affect 
small governments. While some small governments may have some sources 
affected by the proposed rule, the impacts are not expected to be 
significant. Therefore, today's proposed rule is not subject to the 
requirements of section 203 of the UMRA.

F. Regulatory Flexibility Act (RFA), as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et 
seq.

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business 
according to Small Business Administration (SBA) size standards by the 
North American Industry Classification System category of the owning 
entity. The range of small business size standards for the 40 affected 
industries ranges from 500 to 1,000 employees, except for petroleum 
refining and electric utilities. In these latter two industries, the 
size standard is 1,500 employees and a mass throughput of 75,000 
barrels/day or less, and 4 million kilowatt-hours of production or 
less, respectively; (2) a small governmental jurisdiction that is a 
government of a city, county, town, school district or special district 
with a population of less than 50,000; and (3) a small organization 
that is any not-for-profit enterprise which is independently owned and 
operated and is not dominant in its field.
    Because an initial screening analysis for impact on small entities 
indicated a likely significant impact for substantial numbers, EPA 
convened a SBAR Panel to obtain advice and recommendation of 
representatives of the small entities that potentially would be subject 
to the requirements of this rule.
(a) Panel Process and Panel Outreach
    As required by section 609(b) of the RFA, as amended by SBREFA, EPA 
also has conducted outreach to small entities and on January 22, 2009 
EPA's Small Business Advocacy Chairperson convened a Panel under 
section 609(b) of the RFA. In addition to the Chair, the Panel 
consisted of the Director of the Sector Policies and Programs Division 
within EPA's Office of Air and Radiation, the Chief Counsel for 
Advocacy of the Small Business Administration, and the Administrator of 
the Office of Information and Regulatory Affairs within the Office of 
Management and Budget.
    As part of the SBAR Panel process we conducted outreach with 
representatives from 14 various small entities that would be affected 
by this rule. The small entity representatives (SERs) included 
associations representing schools, churches, hotels/motels, wood 
product facilities and manufacturers of home furnishings. We met with 
these SERs to discuss the potential rulemaking approaches and potential 
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials 
included background on the rulemaking, possible regulatory approaches, 
preliminary cost and economic impacts, and possible rulemaking 
alternatives. The Panel met with SERs from the industries that will be 
impacted directly by this rule on February 10, 2009 to discuss the 
outreach materials and receive feedback on the approaches and 
alternatives detailed in the outreach packet. (EPA also met with SERs 
on November 13, 2008 for an initial outreach meeting.) The Panel 
received written comments from the SERs following the meeting in 
response to discussions at the meeting and the questions posed to the 
SERs by the Agency. The SERs were specifically asked to provide comment 
on regulatory alternatives that could help to minimize the rule's 
impact on small businesses.
(1) Panel Recommendations for Small Business Flexibilities
    The Panel recommended that EPA consider and seek comment on a wide 
range of regulatory alternatives to mitigate the impacts of the 
rulemaking on small businesses, including those flexibility options 
described below. The following section summarizes the SBAR Panel 
recommendations. EPA has proposed provisions consistent with four of 
the Panel's recommendations.
    Consistent with the RFA/SBREFA requirements, the Panel evaluated 
the assembled materials and small-entity comments on issues related to 
elements of the IRFA. A copy of the Final Panel Report (including all 
comments received from SERs in response to the Panel's outreach meeting 
as well as summaries of both outreach meetings that were held with the 
SERs is included in the docket for this proposed rule. A summary of the 
Panel

[[Page 32045]]

recommendations is detailed below. As noted above, this proposal 
includes proposed provisions for all but one of the Panel 
recommendations.
(a) Work Practice Standards
    The panel recommended that EPA consider requiring annual tune-ups, 
including standardized criteria outlining proper tune-up methods 
targeted at smaller boiler operators. The panel further recommended 
that EPA take comment on the efficacy of energy assessments/audits at 
improving combustion efficiency and the cost of performing the 
assessments, especially to smaller boiler operators.
    A work practice standard, instead of MACT emission limits, may be 
proposed if it can be justified under section 112(h) of the CAA, that 
is, it is impracticable to enforce the emission standards due to 
technical or economic limitations. Work practice standards could reduce 
fuel use and improve combustion efficiency which would result in 
reduced emissions.
    In general, SERs commented that a regulatory approach to improve 
combustion efficiency, such as work practice standards, would have 
positive impacts with respect to the environment and energy use and 
save on compliance costs. The SERs were concerned with work practice 
standards that would require energy assessments and implementation of 
assessment findings. The basis of these concerns rested upon the 
uncertainty that there is no guarantee that there are available funds 
to implement a particular assessment's findings.
(b) Subcategorization
    The Panel recommended that EPA allow subcategorizations suggested 
by the SERs, unless EPA finds that a subcategorization is inconsistent 
with the Clean Air Act.
    SERs commented that subcategorization is a key concept that could 
ensure that like boilers are compared with similar boilers so that MACT 
floors are more reasonable and could be achieved by all units within a 
subcategory using appropriate emission reduction strategies. SERs 
commented that EPA should subcategorize based on fuel type, boiler 
type, duty cycle, and location.
(c) Health Based Compliance Alternatives (HBCA)
    The Panel recommended that EPA adopt the HBCA as a regulatory 
flexibility option for the Boiler MACT rulemaking. The panel 
recognized, however, that EPA has concerns about its legal authority to 
provide an HBCA under the Clean Air Act, and EPA may ultimately 
determine that this flexibility is inconsistent with the Clean Air Act.
    SERs commented that adopting an HBCA would perhaps be the most 
important step EPA could take to mitigate the serious financial harm 
the Boiler MACT would otherwise inflict on small entities using solid 
fuels nationwide and, therefore, HBCA should be a critical component of 
any future rule to lessen impact on small entities.
(d) Emissions Averaging
    The Panel recommended that EPA consider a provision for emission 
averaging and long averaging times for the proposed emission limits.
    SERs commented that a measure EPA should consider to lessen the 
regulatory burden of complying with Boiler MACT is to allow emissions 
averaging at sources with multiple regulated units. SERs commented that 
another approach that can aide small entity compliance is to set longer 
averaging times (i.e., 30-days or more) rather than looking at a mere 
3-run (hour) average for performance. Given the inherent variability in 
boiler performance, an annual or quarterly averaging period for all HAP 
would prevent a single spike in emissions from throwing a unit into 
non-compliance.
(e) Compliance Costs
    The Panel recommended that EPA carefully weigh the potential burden 
of compliance requirements and consider for small entities options such 
as, emission averaging within facility, reduced monitoring/testing 
requirements, or allowing more time for compliance.
    SERs noted that recordkeeping activities, as written in the vacated 
boiler MACT, would be especially challenging for small entities that do 
not have a dedicated environmental affairs department.

G. Paperwork Reduction Act

    The information collection requirements in the proposed rule will 
be submitted for approval to the Office of Management and Budget under 
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information 
Collection Request (ICR) document has been prepared by EPA (ICR No. 
2028.05).
    The information requirements are based on notification, 
recordkeeping, and reporting requirements in the NESHAP General 
Provisions (40 CFR part 63, subpart A), which are mandatory for all 
operators subject to national emission standards. These recordkeeping 
and reporting requirements are specifically authorized by section 114 
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant 
to the recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to Agency policies set 
forth in 40 CFR part 2, subpart B.
    The proposed rule would require maintenance inspections of the 
control devices but would not require any notifications or reports 
beyond those required by the General Provisions. The recordkeeping 
requirements require only the specific information needed to determine 
compliance.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the standards) is estimated to be $87.6 million. This includes 208,832 
labor hours per year at a total labor cost of $19.8 million per year, 
and total non-labor capital costs of $67.8 million per year. This 
estimate includes initial and annual performance test, conducting and 
documenting an energy assessment, conducting and documenting a tune-up, 
semiannual excess emission reports, maintenance inspections, developing 
a monitoring plan, notifications, and recordkeeping. Monitoring, 
testing, tune-up and energy assessment costs and cost were also 
included in the cost estimates presented in the control costs impacts 
estimates in section IV.D of this preamble. The total burden for the 
Federal government (averaged over the first 3 years after the effective 
date of the standard) is estimated to be 93,648 hours per year at a 
total labor cost of $4.9 million per year.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An Agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control

[[Page 32046]]

numbers for our regulations are listed in 40 CFR part 9 and 48 CFR 
chapter 15.
    To comment on EPA's need for this information, the accuracy of the 
provided burden estimates, and any suggested methods for minimizing 
respondent burden, including the use of automated collection 
techniques, EPA has established a public docket for this action, which 
includes this ICR, under Docket ID number EPA-HQ-OAR-2002-0058. Submit 
any comments related to the ICR to EPA and OMB. See ADDRESSES section 
at the beginning of this preamble for where to submit comments to EPA. 
Send comments to OMB at the Office of Information and Regulatory 
Affairs, Office of Management and Budget, 725 17th Street, NW., 
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is 
required to make a decision concerning the ICR between 30 and 60 days 
after June 4, 2010, a comment to OMB is best assured of having its full 
effect if OMB receives it by July 6, 2010. The final rule will respond 
to any OMB or public comments on the information collection 
requirements contained in this proposal.

H. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the 
EPA to use voluntary consensus standards in their regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, business practices) developed or adopted by one or 
more voluntary consensus bodies. The NTTAA directs EPA to provide 
Congress, through annual reports to the Office of Management and 
Budget, with explanations when an agency does not use available and 
applicable voluntary consensus standards.
    This rulemaking involves technical standards. The EPA cites the 
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A, 
3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with 
the NTTAA, EPA conducted searches to identify voluntary consensus 
standards in addition to these EPA methods. No applicable voluntary 
consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. 
The search and review results have been documented and are placed in 
the docket for the proposed rule.
    The three voluntary consensus standards described below were 
identified as acceptable alternatives to EPA test methods for the 
purposes of the proposed rule.
    The voluntary consensus standard ASME PTC 19-10-1981-Part 10, 
``Flue and Exhaust Gas Analyses,'' is cited in the proposed rule for 
its manual method for measuring the oxygen, carbon dioxide, and carbon 
monoxide content of exhaust gas. This part of ASME PTC 19-10-1981--Part 
10 is an acceptable alternative to Method 3B.
    The voluntary consensus standard ASTM D6522-00, ``Standard Test 
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and 
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers and Process Heaters Using 
Portable Analyzers'' is an acceptable alternative to EPA Method 3A for 
identifying carbon monoxide and oxygen concentrations for the proposed 
rule when the fuel is natural gas.
    The voluntary consensus standard ASTM Z65907, ``Standard Method for 
Both Speciated and Elemental Mercury Determination,'' is an acceptable 
alternative to EPA Method 29 (portion for mercury only) for the purpose 
of the proposed rule. This standard can be used in the proposed rule to 
determine the mercury concentration in stack gases for boilers with 
rated heat input capacities of greater than 250 MMBtu per hour.
    In addition to the voluntary consensus standards EPA uses in the 
proposed rule, the search for emissions measurement procedures 
identified 15 other voluntary consensus standards. The EPA determined 
that 13 of these 15 standards identified for measuring emissions of the 
HAP or surrogates subject to emission standards in the proposed rule 
were impractical alternatives to EPA test methods for the purposes of 
the rule. Therefore, EPA does not intend to adopt these standards for 
this purpose. The reasons for this determination for the 13 methods are 
discussed below.
    The voluntary consensus standard ASTM D3154-00, ``Standard Method 
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as 
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the 
proposed rulemaking since the standard appears to lack in quality 
control and quality assurance requirements. Specifically, ASTM D3154-00 
does not include the following: (1) Proof that openings of standard 
pitot tube have not plugged during the test; (2) if differential 
pressure gauges other than inclined manometers (e.g., magnehelic 
gauges) are used, their calibration must be checked after each test 
series; and (3) the frequency and validity range for calibration of the 
temperature sensors.
    The voluntary consensus standard ASTM D3464-96 (2001), ``Standard 
Test Method Average Velocity in a Duct Using a Thermal Anemometer,'' is 
impractical as an alternative to EPA Method 2 for the purposes of the 
proposed rule primarily because applicability specifications are not 
clearly defined, e.g., range of gas composition, temperature limits. 
Also, the lack of supporting quality assurance data for the calibration 
procedures and specifications, and certain variability issues that are 
not adequately addressed by the standard limit EPA's ability to make a 
definitive comparison of the method in these areas.
    The voluntary consensus standard ISO 10780:1994, ``Stationary 
Source Emissions-Measurement of Velocity and Volume Flowrate of Gas 
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in 
the proposed rule. The standard recommends the use of an L-shaped 
pitot, which historically has not been recommended by EPA. The EPA 
specifies the S-type design which has large openings that are less 
likely to plug up with dust.
    The voluntary consensus standard, CAN/CSA Z223.2-M86(1999), 
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide, 
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed 
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA 
Method 3A since it does not include quantitative specifications for 
measurement system performance, most notably the calibration procedures 
and instrument performance characteristics. The instrument performance 
characteristics that are provided are nonmandatory and also do not 
provide the same level of quality assurance as the EPA methods. For 
example, the zero and span/calibration drift is only checked weekly, 
whereas the EPA methods requires drift checks after each run.
    Two very similar voluntary consensus standards, ASTM D5835-95 
(2001), ``Standard Practice for Sampling Stationary Source Emissions 
for Automated Determination of Gas Concentration,'' and ISO 10396:1993, 
``Stationary Source Emissions: Sampling for the Automated Determination 
of Gas Concentrations,'' are impractical alternatives to EPA Method 3A 
for the purposes of the proposed rule because they lack in detail and 
quality assurance/quality control requirements. Specifically, these two 
standards do not

[[Page 32047]]

include the following: (1) Sensitivity of the method; (2) acceptable 
levels of analyzer calibration error; (3) acceptable levels of sampling 
system bias; (4) zero drift and calibration drift limits, time span, 
and required testing frequency; (5) a method to test the interference 
response of the analyzer; (6) procedures to determine the minimum 
sampling time per run and minimum measurement time; and (7) 
specifications for data recorders, in terms of resolution (all types) 
and recording intervals (digital and analog recorders, only).
    The voluntary consensus standard ISO 12039:2001, ``Stationary 
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and 
Oxygen--Automated Methods,'' is not acceptable as an alternative to EPA 
Method 3A. This ISO standard is similar to EPA Method 3A, but is 
missing some key features. In terms of sampling, the hardware required 
by ISO 12039:2001 does not include a 3-way calibration valve assembly 
or equivalent to block the sample gas flow while calibration gases are 
introduced. In its calibration procedures, ISO 12039:2001 only 
specifies a two-point calibration while EPA Method 3A specifies a 
three-point calibration. Also, ISO 12039:2001 does not specify 
performance criteria for calibration error, calibration drift, or 
sampling system bias tests as in the EPA method, although checks of 
these quality control features are required by the ISO standard.
    The voluntary consensus standard ASME PTC-38-80 R85 (1985), 
``Determination of the Concentration of Particulate Matter in Gas 
Streams,'' is not acceptable as an alternative for EPA Method 5 because 
ASTM PTC-38-80 is not specific about equipment requirements, and 
instead presents the options available and the pro's and con's of each 
option. The key specific differences between ASME PTC-38-80 and the EPA 
methods are that the ASME standard: (1) Allows in-stack filter 
placement as compared to the out-of-stack filter placement in EPA 
Methods 5 and 17; (2) allows many different types of nozzles, pitots, 
and filtering equipment; (3) does not specify a filter weighing 
protocol or a minimum allowable filter weight fluctuation as in the EPA 
methods; and (4) allows filter paper to be only 99 percent efficient, 
as compared to the 99.95 percent efficiency required by the EPA 
methods.
    The voluntary consensus standard ASTM D3685/D3685M-98, ``Test 
Methods for Sampling and Determination of Particulate Matter in Stack 
Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the 
following areas that are needed to produce quality, representative 
particulate data: (1) Requirement that the filter holder temperature 
should be between 120[deg]C and 134[deg]C, and not just ``above the 
acid dew-point;'' (2) detailed specifications for measuring and 
monitoring the filter holder temperature during sampling; (3) 
procedures similar to EPA Methods 1, 2, 3, and 4, that are required by 
EPA Method 5; (4) technical guidance for performing the Method 5 
sampling procedures, e.g., maintaining and monitoring sampling train 
operating temperatures, specific leak check guidelines and procedures, 
and use of reagent blanks for determining and subtracting background 
contamination; and (5) detailed equipment and/or operational 
requirements, e.g., component exchange leak checks, use of glass 
cyclones for heavy particulate loading and/or water droplets, operating 
under a negative stack pressure, exchanging particulate loaded filters, 
sampling preparation and implementation guidance, sample recovery 
guidance, data reduction guidance, and particulate sample calculations 
input.
    The voluntary consensus standard ISO 9096:1992, ``Determination of 
Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying 
Ducts--Manual Gravimetric Method,'' is not acceptable as an alternative 
for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 
1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA 
Method 5 for collection of particulate matter. The standard ISO 9096 
does not provide applicable technical guidance for performing many of 
the integral procedures specified in Methods 1, 2, and 5. Major 
performance and operational details are lacking or nonexistent, and 
detailed quality assurance/quality control guidance for the sampling 
operations required to produce quality, representative particulate data 
(e.g., guidance for maintaining and monitoring train operating 
temperatures, specific leak check guidelines and procedures, and sample 
preparation and recovery procedures) are not provided by the standard, 
as in EPA Method 5. Also, details of equipment and/or operational 
requirements, such as those specified in EPA Method 5, are not included 
in the ISO standard, e.g., stack gas moisture measurements, data 
reduction guidance, and particulate sample calculations.
    The voluntary consensus standard CAN/CSA Z223.1-M1977, ``Method for 
the Determination of Particulate Mass Flows in Enclosed Gas Streams,'' 
is not acceptable as an alternative for EPA Method 5. Detailed 
technical procedures and quality control measures that are required in 
EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, 
CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing 
requirement to repeat weighing every 6 hours until a constant weight is 
achieved. Third, EPA Method 5 requires the filter weight to be reported 
to the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the 
nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot 
for velocity measurement when plugging of the tube opening is not 
expected to be a problem. Whereas, EPA Method 5 requires an S-shaped 
pitot.
    The voluntary consensus standard EN 1911-1,2,3 (1998), ``Stationary 
Source Emissions-Manual Method of Determination of HCl--Part 1: 
Sampling of Gases Ratified European Text--Part 2: Gaseous Compounds 
Absorption Ratified European Text--Part 3: Adsorption Solutions 
Analysis and Calculation Ratified European Text,'' is impractical as an 
alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot 
be considered equivalent to EPA Method 26 or 26A because the sample 
absorbing solution (water) would be expected to capture both HCl and 
chlorine gas, if present, without the ability to distinguish between 
the two. The EPA Methods 26 and 26A use an acidified absorbing solution 
to first separate HCl and chlorine gas so that they can be selectively 
absorbed, analyzed, and reported separately. In addition, in EN 1911 
the absorption efficiency for chlorine gas would be expected to vary as 
the pH of the water changed during sampling.
    The voluntary consensus standard EN 13211 (1998), is not acceptable 
as an alternative to the mercury portion of EPA Method 29 primarily 
because it is not validated for use with impingers, as in the EPA 
method, although the method describes procedures for the use of 
impingers. This European standard is validated for the use of fritted 
bubblers only and requires the use of a side (split) stream arrangement 
for isokinetic sampling because of the low sampling rate of the 
bubblers (up to 3 liters per minute, maximum). Also, only two bubblers 
(or impingers) are required by EN 13211, whereas EPA Method 29 require 
the use of six impingers. In addition, EN 13211 does not include many 
of the quality control procedures of EPA Method 29, especially for the 
use and calibration of temperature sensors and controllers, sampling 
train assembly and disassembly, and filter weighing.

[[Page 32048]]

    Two of the 15 voluntary consensus standards identified in this 
search were not available at the time the review was conducted for the 
purposes of the proposed rule because they are under development by a 
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by 
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR 
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot 
Primary Flowmeters,'' for EPA Method 2.
    Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR 
part 63, list the EPA testing methods included in the proposed rule. 
Under Sec.  63.7(f) and Sec.  63.8(f) of subpart A of the General 
Provisions, a source may apply to EPA for permission to use alternative 
test methods or alternative monitoring requirements in place of any of 
the EPA testing methods, performance specifications, or procedures.

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

    Executive Order 13211, (66 FR 28355, May 22, 2001), provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Information and Regulatory Affairs, Office of Management and Budget, a 
Statement of Energy Effects for certain actions identified as 
significant energy actions. Section 4(b) of Executive Order 13211 
defines ``significant energy actions'' as ``any action by an agency 
(normally published in the Federal Register) that promulgates or is 
expected to lead to the promulgation of a final rule or regulation, 
including notices of inquiry, advance notices of proposed rulemaking, 
and notices of proposed rulemaking: (1)(i) That is a significant 
regulatory action under Executive Order 12866 or any successor order, 
and (ii) is likely to have a significant adverse effect on the supply, 
distribution, or use of energy; or (2) that is designated by the 
Administrator of the Office of Information and Regulatory Affairs as a 
significant energy action.'' The proposed rule is not a ``significant 
regulatory action'' because it is not likely to have a significant 
adverse effect on the supply, distribution, or use of energy. The basis 
for the determination is as follows.
    We estimate a 0.14% price increase for the energy sector and a 
0.07% percentage change in production. We estimate a 0.18% increase in 
energy imports. For more information on the estimated energy effects, 
please refer to the economic impact analysis for the proposed rule. The 
analysis is available in the public docket.
    Therefore, we conclude that the proposed rule when implemented is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice (EJ). Its main 
provision directs Federal agencies, to the greatest extent practicable 
and permitted by law, to make environmental justice part of their 
mission by identifying and addressing, as appropriate, 
disproportionately high and adverse human health or environmental 
effects of their programs, policies, and activities on minority 
populations, low-income, and Tribal populations in the United States.
    This proposed action establishes national emission standards for 
new and existing industrial, commercial, institutional boilers and 
process heaters that combust non-waste materials (i.e. natural gas, 
process gas, fuel oil, biomass, and coal) and that are located at a 
major source. The EPA estimates that there are approximately 13,555 
units located at 1,608 facilities covered by this rule.
    The proposed rule will reduce emissions of all the listed HAP that 
come from boilers and process heaters. This includes metals (mercury, 
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and 
selenium), organics (POM, acetaldehyde, acrolein, benzene, dioxins, 
ethylene dichloride, formaldehyde, and PCB), hydrochloric acid, and 
hydrofluoric acid. Adverse health effects from these pollutants include 
cancer, irritation of the lungs, skin, and mucus membranes; effects on 
the central nervous system, damage to the kidneys, and other acute 
health disorders. The rule will also result in substantial reductions 
of criteria pollutants such as carbon monoxide (CO), nitrogen oxides 
(NOX), particulate matter (PM), and sulfur dioxide 
(SO2). Sulfur dioxide and NO2 are precursors for 
the formation of PM2.5 and ozone. Reducing these emissions 
will reduce ozone and PM2.5 formation and associated health 
effects, such as adult premature mortality, chronic and acute 
bronchitis, asthma, and other respiratory and cardiovascular diseases. 
(Please refer to the RIA contained in the docket for this rulemaking.)
    Pursuant to E.O. 12898 EPA has undertaken to determine the 
aggregate demographic makeup of the communities near affected sources. 
This analysis used ``proximity-to-a-source'' to identify the 
populations considered to be living near affected sources, such that 
they have notable exposures to current emissions from these sources. In 
this approach EPA reviewed the distributions of different socio-
demographic groups in the locations of the expected emission reductions 
from this rule. The review identified those census blocks within a 
circular distance of 3 miles of affected sources and determined the 
demographic and socio-economic composition (e.g. race, income, 
education, etc) of these census blocks. The radius of 3 miles (or 
approximately 5 kilometers) has been used in other demographic analyses 
focused on areas around potential sources.27 28 29 30 In 
addition, air modeling experience has shown that beyond 3 miles the 
influence of an individual source of emissions can generally be 
considered to be small, both in absolute terms and relative to the 
influence of other sources (assuming there are other sources in the 
area, as is typical in urban areas).
---------------------------------------------------------------------------

    \27\ U.S. GAO (Government Accountability Office). Demographics 
of People Living Near Waste Facilities. Washington DC: Government 
Printing Office; 1995.
    \28\ Mohai P, Saha R. ``Reassessing Racial and Socio-economic 
Disparities in Environmental Justice Research''. Demography. 
2006;43(2): 383-399.
    \29\ Mennis J. ``Using Geographic Information Systems to Create 
and Analyze Statistical Surfaces of Populations and Risk for 
Environmental Justice Analysis''. Social Science Quarterly, 
2002;83(1):281-297.
    \30\ Bullard RD, Mohai P, Wright B, Saha R, et al. Toxic Waste 
and Race at Twenty 1987-2007. United Church of Christ. March, 2007.
---------------------------------------------------------------------------

    EPA's demographic analysis showed that major source boilers are 
located in areas where minorities' share of the population living 
within a three-mile buffer is higher than the national average. For 
these same areas, the percent of the population below the poverty line 
is also higher than the national average.\31\ Based on the fact that 
the rule does not allow emission increases, the EPA has determined that 
the proposed rule will not have disproportionately high and adverse 
human health or environmental effects on minority, low-income, or 
Tribal populations. However, to the extent that any minority, low 
income, or Tribal subpopulation is disproportionately impacted by the 
current emissions as a result of the proximity of their homes to these 
sources, that subpopulation also

[[Page 32049]]

stands to see increased environmental and health benefit from the 
emissions reductions called for by this rule.
---------------------------------------------------------------------------

    \31\ The results of the demographic analysis are presented in 
``Review of Environmental Justice Impacts'', April 2010, a copy of 
which is available in the docket.
---------------------------------------------------------------------------

    EPA defines ``Environmental Justice'' to include meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and polices. To promote 
meaningful involvement, EPA has developed a communication and outreach 
strategy to ensure that interested communities have access to this 
proposed rule, are aware of its content, and have an opportunity to 
comment during the comment period. During the comment period, EPA will 
publicize the rulemaking via EJ newsletters, Tribal newsletters, EJ 
listservs, and the Internet, including the Office of Policy, Economics, 
and Innovation's (OPEI) Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/). EPA will also provide general 
rulemaking fact sheets (e.g., why is this important for my community) 
for EJ community groups and conduct conference calls with interested 
communities. In addition, state and federal permitting requirements 
will provide state and local governments and members of affected 
communities the opportunity to provide comments on the permit 
conditions associated with permitting the sources affected by this 
rulemaking.

List of Subjects in 40 CFR Part 63

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

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

PART 63--[AMENDED]

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

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

    2. Part 63 is amended by revising subpart DDDDD to read as follows:

Subpart DDDDD--National Emission Standards for Hazardous Air 
Pollutants for Major Sources: Industrial, Commercial, and 
Institutional Boilers and Process Heaters

Sec.

What This Subpart Covers

63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this subpart?
63.7491 Are any boilers or process heaters not subject to this 
subpart?
63.7495 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards

63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limitations, work practice standards, and 
operating limits must I meet?

General Compliance Requirements

63.7505 What are my general requirements for complying with this 
subpart?

Testing, Fuel Analyses, and Initial Compliance Requirements

63.7510 What are my initial compliance requirements and by what date 
must I conduct them?
63.7515 When must I conduct subsequent performance tests or fuel 
analyses?
63.7520 What stack tests and procedures must I use for the 
performance tests?
63.7521 What fuel analyses and procedures must I use for the 
performance tests?
63.7522 Can I use emission averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and 
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission 
limitations and work practice standards?

Continuous Compliance Requirements

63.7535 How do I monitor and collect data to demonstrate continuous 
compliance?
63.7540 How do I demonstrate continuous compliance with the emission 
limitations and work practice standards?
63.7541 How do I demonstrate continuous compliance under the 
emission averaging provision?

Notifications, Reports, and Records

63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?

Other Requirements and Information

63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or 
Reconstructed Boilers and Process Heaters
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing 
Boilers and Process Heaters (Units with heat input capacity of 10 
million Btu per hour or greater)
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers 
and Process Heaters
Table 5 to Subpart DDDDD of Part 63--Performance Testing 
Requirements
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous 
Compliance
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
Table 10 to Subpart DDDDD of Part 63--Applicability of General 
Provisions to Subpart DDDDD

What This Subpart Covers


Sec.  63.7480  What is the purpose of this subpart?

    This subpart establishes national emission limitations and work 
practice standards for hazardous air pollutants (HAP) emitted from 
industrial, commercial, and institutional boilers and process heaters 
located at major sources of HAP. This subpart also establishes 
requirements to demonstrate initial and continuous compliance with the 
emission limitations and work practice standards.


Sec.  63.7485  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an 
industrial, commercial, or institutional boiler or process heater as 
defined in Sec.  63.7575 that is located at, or is part of, a major 
source of HAP as defined in Sec.  63.2 or Sec.  63.761 (40 CFR part 63, 
subpart HH, National Emission Standards for Hazardous Air Pollutants 
from Oil and Natural Gas Production Facilities), except as specified in 
Sec.  63.7491.


Sec.  63.7490  What is the affected source of this subpart?

    (a) This subpart applies to new, reconstructed, and existing 
affected sources as described in paragraphs (a)(1) and (2) of this 
section.
    (1) The affected source of this subpart is the collection of all 
existing industrial, commercial, and institutional boilers and process 
heaters within a subcategory located at a major source as defined in 
Sec.  63.7575.
    (2) The affected source of this subpart is each new or 
reconstructed industrial, commercial, or institutional boiler or 
process heater located at a major source as defined in Sec.  63.7575.
    (b) A boiler or process heater is new if you commence construction 
of the boiler or process heater after June 4, 2010, and you meet the 
applicability

[[Page 32050]]

criteria at the time you commence construction.
    (c) A boiler or process heater is reconstructed if you meet the 
reconstruction criteria as defined in Sec.  63.2, you commence 
reconstruction after June 4, 2010, and you meet the applicability 
criteria at the time you commence reconstruction.
    (d) A boiler or process heater is existing if it is not new or 
reconstructed.


Sec.  63.7491  Are any boilers or process heaters not subject to this 
subpart?

    The types of boilers and process heaters listed in paragraphs (a) 
through (j) of this section are not subject to this subpart.
    (a) An electric utility steam generating unit.
    (b) A recovery boiler or furnace covered by 40 CFR part 63, subpart 
MM.
    (c) A boiler or process heater that is used specifically for 
research and development. This does not include units that provide heat 
or steam to a process at a research and development facility.
    (d) A hot water heater as defined in this subpart.
    (e) A refining kettle covered by 40 CFR part 63, subpart X.
    (f) An ethylene cracking furnace covered by 40 CFR part 63, subpart 
YY.
    (g) Blast furnace stoves as described in the EPA document, entitled 
``National Emission Standards for Hazardous Air Pollutants (NESHAP) for 
Integrated Iron and Steel Plants--Background Information for Proposed 
Standards,'' (EPA-453/R-01-005).
    (h) Any boiler or process heater specifically listed as an affected 
source in another standard(s) under 40 CFR part 63.
    (i) Temporary boilers as defined in this subpart.
    (j) Blast furnace gas fuel-fired boilers and process heaters as 
defined in this subpart.


Sec.  63.7495  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed boiler or process heater, 
you must comply with this subpart by [DATE THE FINAL RULE IS PUBLISHED 
IN THE FEDERAL REGISTER] or upon startup of your boiler or process 
heater, whichever is later.
    (b) If you have an existing boiler or process heater, you must 
comply with this subpart no later than [3 YEARS AFTER DATE THE FINAL 
RULE IS PUBLISHED IN THE FEDERAL REGISTER].
    (c) If you have an area source that increases its emissions or its 
potential to emit such that it becomes a major source of HAP, 
paragraphs (c)(1) and (2) of this section apply to you.
    (1) Any new or reconstructed boiler or process heater at the 
existing source must be in compliance with this subpart upon startup.
    (2) Any existing boiler or process heater at the existing source 
must be in compliance with this subpart within 3 years after the source 
becomes a major source.
    (d) You must meet the notification requirements in Sec.  63.7545 
according to the schedule in Sec.  63.7545 and in subpart A of this 
part. Some of the notifications must be submitted before you are 
required to comply with the emission limits and work practice standards 
in this subpart.

Emission Limitations and Work Practice Standards


Sec.  63.7499  What are the subcategories of boilers and process 
heaters?

    (a) The subcategories of boilers and process heaters are:
    (1) Pulverized coal units,
    (2) Stokers designed to burn coal,
    (3) Fluidized bed units designed to burn coal,
    (4) Stokers designed to burn biomass,
    (5) Fluidized bed units designed to burn biomass,
    (6) Suspension burners/Dutch Ovens designed to burn biomass,
    (7) Fuel Cells designed to burn biomass,
    (8) Units designed to burn liquid fuel,
    (9) Units designed to burn natural gas/refinery gas,
    (10) Units designed to burn other gases, and
    (11) Metal process furnaces.
    (b) Each subcategory is defined in Sec.  63.7575.


Sec.  63.7500  What emission limits, work practice standards, and 
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) and (2) of 
this section. You must meet these requirements at all times.
    (1) You must meet each emission limit and work practice standard in 
Table 1 through 3 to this subpart that applies to your boiler or 
process heater, for each boiler or process heater at your source, 
except as provided under Sec.  63.7522.
    (2) You must meet each operating limit in Table 4 to this subpart 
that applies to your boiler or process heater. If you use a control 
device or combination of control devices not covered in Table 4 to this 
subpart, or you wish to establish and monitor an alternative operating 
limit and alternative monitoring parameters, you must apply to the 
United States Environmental Protection Agency (EPA) Administrator for 
approval of alternative monitoring under Sec.  63.8(f).
    (b) As provided in Sec.  63.6(g), EPA may approve use of an 
alternative to the work practice standards in this section.

General Compliance Requirements


Sec.  63.7505  What are my general requirements for complying with this 
subpart?

    (a) You must be in compliance with the emission limits and 
operating limits in this subpart. These limits apply to you at all 
times.
    (b) At all times you must operate and maintain any affected source, 
including associated air pollution control equipment and monitoring 
equipment, in a manner consistent with safety and good air pollution 
control practices for minimizing emissions. The general duty to 
minimize emissions does not require you to make any further efforts to 
reduce emissions if levels required by this standard have been 
achieved. Determination of whether such operation and maintenance 
procedures are being used will be based on information available to the 
Administrator which may include, but is not limited to, monitoring 
results, review of operation and maintenance procedures, review of 
operation and maintenance records, and inspection of the source.
    (c) You can demonstrate compliance with the applicable emission 
limit for HCl or mercury using fuel analysis if the emission rate 
calculated according to Sec.  63.7530(d) is less than the applicable 
emission limit. Otherwise, you must demonstrate compliance for HCl or 
mercury using performance stack testing. You must demonstrate 
compliance with all other applicable limits using performance stack 
testing, or the continuous monitoring system (CMS) where applicable.
    (d) If you demonstrate compliance with any applicable emission 
limit through performance stack testing, you must develop a site-
specific monitoring plan according to the requirements in paragraphs 
(d)(1) through (4) of this section. This requirement also applies to 
you if you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
    (1) For each CMS required in this section, you must develop, and 
submit to the permitting authority for approval upon request, a site-
specific monitoring plan that addresses paragraphs (d)(1)(i) through 
(iii) of this section. You must submit this site-specific monitoring 
plan, if requested, at least 60 days before

[[Page 32051]]

your initial performance evaluation of your CMS.
    (i) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device);
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations).
    (2) In your site-specific monitoring plan, you must also address 
paragraphs (d)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  63.8(c)(1)(i) and (ii), (c)(3), and 
(c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in 
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation 
according to the site-specific monitoring plan.

Testing, Fuel Analyses, and Initial Compliance Requirements


Sec.  63.7510  What are my initial compliance requirements and by what 
date must I conduct them?

    (a) For affected sources that elect to demonstrate compliance with 
any of the emission limits of this subpart through performance stack 
testing, your initial compliance requirements include conducting 
performance stack tests according to Sec.  63.7520 and Table 5 to this 
subpart, conducting a fuel analysis for each type of fuel burned in 
your boiler or process heater according to Sec.  63.7521 and Table 6 to 
this subpart, establishing operating limits according to Sec.  63.7530 
and Table 7 to this subpart, and conducting CMS performance evaluations 
according to Sec.  63.7525. For affected sources that burn a single 
type of fuel, you are exempted from the initial compliance requirements 
of conducting a fuel analysis for each type of fuel burned in your 
boiler or process heater according to Sec.  63.7521 and Table 6 to this 
subpart.
    (b) For affected sources that elect to demonstrate compliance with 
the emission limits for HCl or mercury through fuel analysis, your 
initial compliance requirement is to conduct a fuel analysis for each 
type of fuel burned in your boiler or process heater according to Sec.  
63.7521 and Table 6 to this subpart and establish operating limits 
according to Sec.  63.7530 and Table 8 to this subpart.
    (c) If your boiler or process heater has a heat input capacity less 
than 100 MMBtu per hour, your initial compliance demonstration for CO 
is conducting a performance stack test for CO according to Table 5 to 
this subpart. If your boiler or process heater has a heat input 
capacity of 100 MMBtu per hour or greater, your initial compliance 
demonstration for CO is conducting a performance evaluation of your 
continuous emission monitoring system for CO according to Sec.  
63.7525(a).
    (d) If your boiler or process heater has a heat input capacity of 
250 MMBtu per hour or greater and combusts coal, biomass, or residual 
oil, your initial compliance demonstration for PM is conducting a 
performance evaluation of your continuous emission monitoring system 
for PM according to Sec.  63.7525(b).
    (e) For existing affected sources, you must demonstrate initial 
compliance no later than 180 days after the compliance date that is 
specified for your source in Sec.  63.7495 and according to the 
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this 
subpart.
    (f) If your new or reconstructed affected source commenced 
construction or reconstruction between June 4, 2010 and [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
demonstrate initial compliance with either the proposed emission limits 
or the promulgated emission limits no later than 180 days after [DATE 
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or 
within 180 days after startup of the source, whichever is later, 
according to Sec.  63.7(a)(2)(ix).
    (g) If your new or reconstructed affected source commenced 
construction or reconstruction between June 4, 2010, and [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], and you 
chose to comply with the proposed emission limits when demonstrating 
initial compliance, you must conduct a second compliance demonstration 
for the promulgated emission limits within 3 years after [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 
3 years after startup of the affected source, whichever is later.
    (h) If your new or reconstructed affected source commences 
construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF 
THE FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial 
compliance with the promulgated emission limits no later than 180 days 
after startup of the source.


Sec.  63.7515  When must I conduct subsequent performance tests or fuel 
analyses?

    (a) You must conduct all applicable performance tests according to 
Sec.  63.7520 on an annual basis, unless you follow the requirements 
listed in paragraphs (b) through (e) of this section. Annual 
performance tests must be completed between 10 and 12 months after the 
previous performance test, unless you follow the requirements listed in 
paragraphs (b) through (e) of this section.
    (b) You can conduct performance stack tests less often for a given 
pollutant if your performance stack tests for the pollutant for at 
least 3 consecutive years show that your emissions are at or below 75 
percent of the emission limit, and if there are no changes in the 
operation of the affected source or air pollution control equipment 
that could increase emissions. In this case, you do not have to conduct 
a performance test for that pollutant for the next 2 years. You must 
conduct a performance test during the third year and no more than 36 
months after the previous performance test. This reduced testing option 
does not apply to performance stack tests for dioxin/furan. If you 
elect to demonstrate compliance using emission averaging under Sec.  
63.7522, you must continue to conduct performance stack tests annually.
    (c) If your boiler or process heater continues to meet the emission 
limit for the pollutant, you may choose to conduct performance stack 
tests for the pollutant every third year if your emissions are at or 
below 75 percent of the emission limit, and if there are no changes in 
the operation of the affected source or air pollution control equipment 
that could increase emissions, but each such performance test must be 
conducted no more than 36 months after the previous performance test. 
This reduced testing option does not apply to performance stack tests 
for dioxin/furan. If you elect to demonstrate compliance using emission 
averaging under Sec.  63.7522, you must continue to conduct performance 
stack tests annually.

[[Page 32052]]

    (d) If a performance test shows emissions exceeded 75 percent of 
the emission limit, you must conduct annual performance tests for that 
pollutant until all performance tests over a consecutive 3-year period 
show compliance.
    (e) If you are required to meet an applicable work practice 
standard, you must conduct annual performance tune-ups according to 
Sec.  63.7520. Each annual tune-up must be conducted between 10 and 12 
months after the previous tune-up.
    (f) If you demonstrate compliance with the mercury or HCl based on 
fuel analysis, you must conduct a monthly fuel analysis according to 
Sec.  63.7521 for each type of fuel burned. If you burn a new type of 
fuel, you must conduct a fuel analysis before burning the new type of 
fuel in your boiler or process heater. You must still meet all 
applicable continuous compliance requirements in Sec.  63.7540.
    (g) You must report the results of performance tests (stack test 
and fuel analyses) within 60 days after the completion of the 
performance tests. This report must also verify that the operating 
limits for your affected source have not changed or provide 
documentation of revised operating parameters established according to 
Sec.  63.7530 and Table 7 to this subpart, as applicable. The reports 
for all subsequent performance tests must include all applicable 
information required in Sec.  63.7550.


Sec.  63.7520  What stack tests and procedures must I use for the 
performance tests?

    (a) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific test 
plan according to the requirements in Sec.  63.7(c).
    (b) You must conduct each performance test according to the 
requirements in Table 5 to this subpart.
    (c) You must conduct each performance stack test under the specific 
conditions listed in Tables 5 and 7 to this subpart. You must conduct 
performance stack tests at the maximum normal operating load while 
burning the type of fuel or mixture of fuels that has the highest 
content of chlorine and mercury, and you must demonstrate initial 
compliance and establish your operating limits based on these tests. 
These requirements could result in the need to conduct more than one 
performance test.
    (d) You must conduct three separate test runs for each performance 
test required in this section, as specified in Sec.  63.7(e)(3). Each 
test run must last at least 4 hours.
    (e) To determine compliance with the emission limits, you must use 
the F[dash]Factor methodology and equations in sections 12.2 and 12.3 
of EPA Method 19 of appendix A to part 60 of this chapter to convert 
the measured particulate matter concentrations, the measured HCl 
concentrations, and the measured mercury concentrations that result 
from the initial performance test to pounds per million Btu heat input 
emission rates using F-factors.


Sec.  63.7521  What fuel analyses and procedures must I use for the 
performance tests?

    (a) You must conduct performance fuel analysis tests according to 
the procedures in paragraphs (b) through (e) of this section and Table 
6 to this subpart, as applicable.
    (b) You must develop and submit a site-specific fuel analysis plan 
to the EPA Administrator for review and approval according to the 
following procedures and requirements in paragraphs (b)(1) and (2) of 
this section.
    (1) You must submit the fuel analysis plan no later than 60 days 
before the date that you intend to demonstrate compliance.
    (2) You must include the information contained in paragraphs 
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
    (i) The identification of all fuel types anticipated to be burned 
in each boiler or process heater.
    (ii) For each fuel type, the notification of whether you or a fuel 
supplier will be conducting the fuel analysis.
    (iii) For each fuel type, a detailed description of the sample 
location and specific procedures to be used for collecting and 
preparing the composite samples if your procedures are different from 
paragraph (c) or (d) of this section. Samples should be collected at a 
location that most accurately represents the fuel type, where possible, 
at a point prior to mixing with other dissimilar fuel types.
    (iv) For each fuel type, the analytical methods from Table 6, with 
the expected minimum detection levels, to be used for the measurement 
of chlorine or mercury.
    (v) If you request to use an alternative analytical method other 
than those required by Table 6 to this subpart, you must also include a 
detailed description of the methods and procedures that you are 
proposing to use. Methods in Table 6 shall be used until the requested 
alternative is approved.
    (vi) If you will be using fuel analysis from a fuel supplier in 
lieu of site-specific sampling and analysis, the fuel supplier must use 
the analytical methods required by Table 6 to this subpart.
    (c) At a minimum, you must obtain three composite fuel samples for 
each fuel type according to the procedures in paragraph (c)(1) or (2) 
of this section.
    (1) If sampling from a belt (or screw) feeder, collect fuel samples 
according to paragraphs (c)(1)(i) and (ii) of this section.
    (i) Stop the belt and withdraw a 6-inch wide sample from the full 
cross-section of the stopped belt to obtain a minimum two pounds of 
sample. You must collect all the material (fines and coarse) in the 
full cross-section. You must transfer the sample to a clean plastic 
bag.
    (ii) Each composite sample will consist of a minimum of three 
samples collected at approximately equal 1-hour intervals during the 
testing period.
    (2) If sampling from a fuel pile or truck, you must collect fuel 
samples according to paragraphs (c)(2)(i) through (iii) of this 
section.
    (i) For each composite sample, you must select a minimum of five 
sampling locations uniformly spaced over the surface of the pile.
    (ii) At each sampling site, you must dig into the pile to a depth 
of 18 inches. You must insert a clean flat square shovel into the hole 
and withdraw a sample, making sure that large pieces do not fall off 
during sampling.
    (iii) You must transfer all samples to a clean plastic bag for 
further processing.
    (d) You must prepare each composite sample according to the 
procedures in paragraphs (d)(1) through (7) of this section.
    (1) You must thoroughly mix and pour the entire composite sample 
over a clean plastic sheet.
    (2) You must break sample pieces larger than 3 inches into smaller 
sizes.
    (3) You must make a pie shape with the entire composite sample and 
subdivide it into four equal parts.
    (4) You must separate one of the quarter samples as the first 
subset.
    (5) If this subset is too large for grinding, you must repeat the 
procedure in paragraph (d)(3) of this section with the quarter sample 
and obtain a one-quarter subset from this sample.
    (6) You must grind the sample in a mill.
    (7) You must use the procedure in paragraph (d)(3) of this section 
to obtain a one-quarter subsample for analysis. If the quarter sample 
is too large, subdivide it further using the same procedure.
    (e) You must determine the concentration of pollutants in the fuel 
(mercury and/or chlorine) in units of

[[Page 32053]]

pounds per million Btu of each composite sample for each fuel type 
according to the procedures in Table 6 to this subpart.


Sec.  63.7522  Can I use emission averaging to comply with this 
subpart?

    (a) As an alternative to meeting the requirements of Sec.  63.7500 
for particulate matter, HCl, or mercury on a boiler or process heater-
specific basis, if you have more than one existing boiler or process 
heater in any subcategory located at your facility, you may demonstrate 
compliance by emission averaging, if your averaged emissions are within 
90 percent of the applicable emission limit, according to the 
procedures in this section.
    (b) Separate stack requirements. For a group of two or more 
existing boilers or process heaters in the same subcategory that each 
vent to a separate stack, you may average particulate matter, HCl, and 
mercury emissions to demonstrate compliance with the limits in Table 2 
to this subpart if you satisfy the requirements in paragraphs (c), (d), 
(e), (f), and (g) of this section.
    (c) For each existing boiler or process heater in the averaging 
group, the emission rate achieved during the initial compliance test 
for the HAP being averaged must not exceed the emission level that was 
being achieved on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE 
IN THE FEDERAL REGISTER] or the control technology employed during the 
initial compliance test must not be less effective for the HAP being 
averaged than the control technology employed on [THE DATE 30 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] .
    (d) The averaged emissions rate from the existing boilers and 
process heaters participating in the emissions averaging option must be 
in compliance with the limits in Table 2 to this subpart at all times 
following the compliance date specified in Sec.  63.7495.
    (e) You must demonstrate initial compliance according to paragraph 
(e)(1) or (2) of this section.
    (1) You must use Equation 1 of this section to demonstrate that the 
particulate matter, HCl, and mercury emissions from all existing units 
participating in the emissions averaging option do not exceed the 
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.003

Where:

Ave Weighted Emissions = Average weighted emissions for particulate 
matter, HCl, or mercury, in units of pounds per million Btu of heat 
input.
Er = Emission rate (as calculated according to Table 5 to this 
subpart for particulate matter, HCl, or mercury or by fuel analysis 
for HCl or mercury as calculated by the applicable equation in Sec.  
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in 
units of pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of 
million Btu per hour.
n = Number of units participating in the emissions averaging option.
0.90 = Required discount factor.

    (2) If you are not capable of monitoring heat input, and the boiler 
generates steam, you may use Equation 2 of this section as an 
alternative to using Equation 1 of this section to demonstrate that the 
particulate matter, HCl, and mercury emissions from all existing units 
participating in the emissions averaging option do not exceed the 
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.004

Where:

Ave Weighted Emissions = Average weighted emission level for PM, 
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this 
subpart for particulate matter, HCl, or mercury or by fuel analysis 
for HCl or mercury as calculated by the applicable equation in Sec.  
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in 
units of pounds per million Btu of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance 
test, in units of million Btu of heat input per pounds of steam 
generated for unit, i.
0.90 = Required discount factor.

    (f) You must demonstrate compliance on a monthly basis determined 
at the end of every month (12 times per year) according to paragraphs 
(f)(1) through (3) of this section. The first monthly period begins on 
the compliance date specified in Sec.  63.7495.
    (1) For each calendar month, you must use Equation 3 of this 
section to calculate the monthly average weighted emission rate using 
the actual heat capacity for each existing unit participating in the 
emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.005

Where:

Ave Weighted Emissions = monthly average weighted emission level for 
particulate matter, HCl, or mercury, in units of pounds per million 
Btu of heat input.
Er = Emission rate, (as calculated during the most recent compliance 
test, (as calculated according to Table 5 to this subpart for 
particulate matter, HCl, or mercury or by fuel analysis for HCl or 
mercury as calculated by the applicable equation in Sec.  
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in 
units of pounds per million Btu of heat input.
Hb = The average heat input for each calendar month of boiler, i, in 
units of million Btu.
n = Number of units participating in the emissions averaging option.

[[Page 32054]]

0.90 = Required discount factor.

    (2) If you are not capable of monitoring heat input, you may use 
Equation 4 of this section as an alternative to using Equation 3 of 
this section to calculate the monthly weighted emission rate using the 
actual steam generation from the units participating in the emissions 
averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.006

Where:

Ave Weighted Emissions = monthly average weighted emission level for 
PM, HCl, or mercury, in units of pounds per million Btu of heat 
input.
Er = Emission rate, (as calculated during the most recent compliance 
test (as calculated according to Table 5 to this subpart for 
particulate matter, HCl, or mercury or by fuel analysis for HCl or 
mercury as calculated by the applicable equation in Sec.  
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in 
units of pounds per million Btu of heat input.
Sa = Actual steam generation for each calendar month by boiler, i, 
in units of pounds.
Cf = Conversion factor, as calculated during the most recent 
compliance test, in units of million Btu of heat input per pounds of 
steam generated for unit, i.
0.90 = Required discount factor.

    (3) Until 12 monthly weighted average emission rates have been 
accumulated, calculate and report only the monthly average weighted 
emission rate determined under paragraph (f)(1) or (2) of this section. 
After 12 monthly weighted average emission rates have been accumulated, 
for each subsequent calendar month, use Equation 5 of this section to 
calculate the 12-month rolling average of the monthly weighted average 
emission rates for the current month and the previous 11 months.
[GRAPHIC] [TIFF OMITTED] TP04JN10.007

Where:

Eavg = 12-month rolling average emission rate, (pounds per million 
Btu heat input)
ERi = Monthly weighted average, for month ``i'', (pounds per million 
Btu heat input)(as calculated by (f)(1) or (2))

    (g) You must develop, and submit to the applicable regulatory 
authority for review and approval upon request, an implementation plan 
for emission averaging according to the following procedures and 
requirements in paragraphs (g)(1) through (4).
    (1) You must submit the implementation plan no later than 180 days 
before the date that the facility intends to demonstrate compliance 
using the emission averaging option.
    (2) You must include the information contained in paragraphs 
(g)(2)(i) through (vii) of this section in your implementation plan for 
all emission sources included in an emissions average:
    (i) The identification of all existing boilers and process heaters 
in the averaging group, including for each either the applicable HAP 
emission level or the control technology installed as of [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] and the 
date on which you are requesting emission averaging to commence;
    (ii) The process parameter (heat input or steam generated) that 
will be monitored for each averaging group;
    (iii) The specific control technology or pollution prevention 
measure to be used for each emission boiler or process heater in the 
averaging group and the date of its installation or application. If the 
pollution prevention measure reduces or eliminates emissions from 
multiple boilers or process heaters, the owner or operator must 
identify each boiler or process heater;
    (iv) The test plan for the measurement of particulate matter, HCl, 
or mercury emissions in accordance with the requirements in Sec.  
63.7520;
    (v) The operating parameters to be monitored for each control 
system or device consistent with 63.7500 and Table 4, and a description 
of how the operating limits will be determined;
    (vi) If you request to monitor an alternative operating parameter 
pursuant to Sec.  63.7525, you must also include:
    (A) A description of the parameter(s) to be monitored and an 
explanation of the criteria used to select the parameter(s); and
    (B) A description of the methods and procedures that will be used 
to demonstrate that the parameter indicates proper operation of the 
control device; the frequency and content of monitoring, reporting, and 
recordkeeping requirements; and a demonstration, to the satisfaction of 
the applicable regulatory authority, that the proposed monitoring 
frequency is sufficient to represent control device operating 
conditions; and
    (vii) A demonstration that compliance with each of the applicable 
emission limit(s) will be achieved under representative operating 
conditions.
    (3) The regulatory authority shall review and approve or disapprove 
the plan according to the following criteria:
    (i) Whether the content of the plan includes all of the information 
specified in paragraph (g)(2) of this section; and
    (ii) Whether the plan presents sufficient information to determine 
that compliance will be achieved and maintained.
    (4) The applicable regulatory authority shall not approve an 
emission averaging implementation plan containing any of the following 
provisions:
    (i) Any averaging between emissions of differing pollutants or 
between differing sources; or
    (ii) The inclusion of any emission source other than an existing 
unit in the same subcategory.
    (h) Common stack requirements. For a group of two or more existing 
affected units, each of which vents through a single common stack, you 
may average particulate matter, HCl and mercury emissions to 
demonstrate compliance with the limits in Table 2 to this subpart if 
you satisfy the requirements in paragraph (i) or (j) of this section.
    (i) For a group of two or more existing units in the same 
subcategory, each of which vents through a common emissions control 
system to a common stack, that does not receive emissions from units in 
other subcategories or categories, you may treat such averaging group 
as a single existing unit for

[[Page 32055]]

purposes of this subpart and comply with the requirements of this 
subpart as if the group were a single unit.
    (j) For all other groups of units subject to paragraph (h) of this 
section, the owner or operator may elect to:
    (1) Conduct performance tests according to procedures specified in 
Sec.  63.7520 in the common stack if affected units from other 
subcategories vent to the common stack. The emission limits that the 
group must comply with are determined by the use of equation 6.
[GRAPHIC] [TIFF OMITTED] TP04JN10.008

Where:

En = HAP emission limit, lb/MMBtu, ppm, or ng/dscm;
ELi = Appropriate emission limit from Table 2 to this 
subpart for unit i, in units of lb/MMBtu, ppm or ng/dscm;
Hi = Heat input from unit i, MMBtu;

    (2) Conduct performance tests according to procedures specified in 
Sec.  63.7520 in the common stack. If affected units from nonaffected 
units vent to the common stack, the units from nonaffected units must 
be shut down or vented to a different stack during the performance 
test); and
    (3) Meet the applicable operating limit specified in Sec.  63.7540 
and Table 8 to this subpart for each emissions control system (except 
that, if each unit venting to the common stack has an applicable 
opacity operating limit, then a single continuous opacity monitoring 
system may be located in the common stack instead of in each duct to 
the common stack).
    (k) Combination requirements. The common stack of a group of two or 
more existing boilers or process heaters in the same subcategory 
subject to paragraph (h) of this section may be treated as a separate 
stack for purposes of paragraph (b) of this section and included in an 
emissions averaging group subject to paragraph (b) of this section.


Sec.  63.7525  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If your boiler or process heater has a heat input capacity of 
100 MMBtu per hour or greater, you must install, operate, and maintain 
a continuous emission monitoring system (CEMS) for CO and oxygen 
according to the procedures in paragraphs (a)(1) through (6) of this 
section by the compliance date specified in Sec.  63.7495. The CO and 
oxygen shall be monitored at the same location at the outlet of the 
boiler or process heater.
    (1) Each CEMS must be installed, operated, and maintained according 
to the applicable procedures under Performance Specification (PS) 3 or 
4A of 40 CFR part 60, appendix B, and according to the site-specific 
monitoring plan developed according to Sec.  63.7505(d).
    (2) You must conduct a performance evaluation of each CEMS 
according to the requirements in Sec.  63.8 and according to PS 4A of 
40 CFR part 60, appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period.
    (4) The CEMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must calculate and record a 30-day rolling average emission 
rate on a daily basis. A new 30-day rolling average emission rate is 
calculated as the average of all of the hourly CO emission data for the 
preceding 30 operating days.
    (6) For purposes of calculating data averages, you must use all the 
data collected during all periods in assessing compliance. Any period 
for which the monitoring system is out of control and data are not 
available for required calculations constitutes a deviation from the 
monitoring requirements.
    (b) If your boiler or process heater has a heat input capacity of 
250 MMBtu per hour or greater and combusts coal, biomass, or residual 
oil, you must install, certify, maintain, and operate a CEMS measuring 
PM emissions discharged to the atmosphere and record the output of the 
system as specified in paragraphs (b)(1) through (b)(6) of this 
section.
    (1) Each CEMS shall be installed, certified, operated, and 
maintained according to the requirements in Sec.  63.7540(a)(8).
    (2) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of a new unit or within 
180 days of the compliance date for an existing unit, as specified 
under Sec.  63.7495 of this subpart.
    (3) Compliance with the applicable emissions limit shall be 
determined based on the 24-hour daily (block) average of the hourly 
arithmetic average emissions concentrations using the continuous 
monitoring system outlet data. The 24-hour block arithmetic average 
emission concentration shall be calculated using EPA Reference Method 
19 of appendix A of 40 CFR part 60.
    (4) Obtain valid CEMS hourly averages for all operating hours on a 
30-day rolling average basis. At least two data points per hour shall 
be used to calculate each 1-hour arithmetic average.
    (5) The 1-hour arithmetic averages required shall be expressed in 
lb/MMBtu and shall be used to calculate the boiler operating day daily 
arithmetic average emissions.
    (6) When PM emissions data are not obtained because of CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments, 
emissions data shall be obtained by using other monitoring systems as 
approved by the Administrator or EPA Reference Method 19 of appendix A 
of 40 CFR part 60 to provide, as necessary, valid emissions data for 
all operating hours per 30-day rolling average.
    (c) If you have an applicable opacity operating limit, you must 
install, operate, certify and maintain each continuous opacity 
monitoring system (COMS) according to the procedures in paragraphs 
(c)(1) through (7) of this section by the compliance date specified in 
Sec.  63.7495.
    (1) Each COMS must be installed, operated, and maintained according 
to PS 1 of 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each COMS 
according to the requirements in Sec.  63.8 and according to PS 1 of 40 
CFR part 60, appendix B.
    (3) As specified in Sec.  63.8(c)(4)(i), each COMS must complete a 
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
    (4) The COMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  63.8(d). At a minimum, the 
monitoring plan must include a daily calibration drift assessment, a 
quarterly performance audit, and an annual zero alignment audit of each 
COMS.
    (6) You must operate and maintain each COMS according to the 
requirements in the monitoring plan and the requirements of Sec.  
63.8(e). You must identify periods the COMS is out of control including 
any periods that the COMS fails to pass a daily calibration drift 
assessment, a quarterly performance audit, or an annual zero alignment 
audit. Any 6-minute period for which the monitoring system is out of 
control and data are not available for required calculations 
constitutes a deviation from the monitoring requirements.
    (7) You must determine and record all the 6-minute averages (and 1-
hour block

[[Page 32056]]

averages as applicable) collected for periods during which the COMS is 
not out of control.
    (d) If you have an operating limit that requires the use of a CMS, 
you must install, operate, and maintain each continuous parameter 
monitoring system (CPMS) according to the procedures in paragraphs 
(d)(1) through (5) of this section by the compliance date specified in 
Sec.  63.7495.
    (1) The CPMS must complete a minimum of one cycle of operation for 
each successive 15-minute period. You must have a minimum of four 
successive cycles of operation to have a valid hour of data.
    (2) Except for monitoring malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must conduct all monitoring in continuous operation at all times 
that the unit is operating. A monitoring malfunction is any sudden, 
infrequent, not reasonably preventable failure of the monitoring to 
provide valid data. Monitoring failures that are caused in part by poor 
maintenance or careless operation are not malfunctions.
    (3) For purposes of calculating data averages, you must not use 
data recorded during monitoring malfunctions, associated repairs, out 
of control periods, or required quality assurance or control 
activities. You must use all the data collected during all other 
periods in assessing compliance. Any 15-minute period for which the 
monitoring system is out-of-control and data are not available for 
required calculations constitutes a deviation from the monitoring 
requirements.
    (4) You must determine the 3-hour block average of all recorded 
readings, except as provided in paragraph (c)(3) of this section.
    (5) You must record the results of each inspection, calibration, 
and validation check.
    (e) If you have an operating limit that requires the use of a flow 
measurement device, you must meet the requirements in paragraphs (d) 
and (e)(1) through (4) of this section.
    (1) You must locate the flow sensor and other necessary equipment 
in a position that provides a representative flow.
    (2) You must use a flow sensor with a measurement sensitivity of 2 
percent of the flow rate.
    (3) You must reduce swirling flow or abnormal velocity 
distributions due to upstream and downstream disturbances.
    (4) You must conduct a flow sensor calibration check at least 
semiannually.
    (f) If you have an operating limit that requires the use of a 
pressure measurement device, you must meet the requirements in 
paragraphs (d) and (f)(1) through (6) of this section.
    (1) Locate the pressure sensor(s) in a position that provides a 
representative measurement of the pressure.
    (2) Minimize or eliminate pulsating pressure, vibration, and 
internal and external corrosion.
    (3) Use a gauge with a minimum tolerance of 1.27 centimeters of 
water or a transducer with a minimum tolerance of 1 percent of the 
pressure range.
    (4) Check pressure tap pluggage daily.
    (5) Using a manometer, you must check gauge calibration quarterly 
and transducer calibration monthly.
    (6) Conduct calibration checks any time the sensor exceeds the 
manufacturer's specified maximum operating pressure range or install a 
new pressure sensor.
    (g) If you have an operating limit that requires the use of a pH 
measurement device, you must meet the requirements in paragraphs (d) 
and (g)(1) through (3) of this section.
    (1) Locate the pH sensor in a position that provides a 
representative measurement of scrubber effluent pH.
    (2) Ensure the sample is properly mixed and representative of the 
fluid to be measured.
    (3) Check the pH meter's calibration on at least two points every 8 
hours of process operation.
    (h) If you have an operating limit that requires the use of 
equipment to monitor voltage and secondary amperage (or total power 
input) of an electrostatic precipitator (ESP), you must use voltage and 
secondary current monitoring equipment to measure voltage and secondary 
current to the ESP.
    (i) If you have an operating limit that requires the use of 
equipment to monitor sorbent injection rate (e.g., weigh belt, weigh 
hopper, or hopper flow measurement device), you must meet the 
requirements in paragraphs (c) and (i)(1) through (3) of this section.
    (1) Locate the device in a position(s) that provides a 
representative measurement of the total sorbent injection rate.
    (2) Install and calibrate the device in accordance with 
manufacturer's procedures and specifications.
    (3) At least annually, calibrate the device in accordance with the 
manufacturer's procedures and specifications.
    (j) If you elect to use a fabric filter bag leak detection system 
to comply with the requirements of this subpart, you must install, 
calibrate, maintain, and continuously operate a bag leak detection 
system as specified in paragraphs (j)(1) through (8) of this section.
    (1) You must install and operate a bag leak detection system for 
each exhaust stack of the fabric filter.
    (2) Each bag leak detection system must be installed, operated, 
calibrated, and maintained in a manner consistent with the 
manufacturer's written specifications and recommendations and in 
accordance with the guidance provided in EPA-454/R-98-015, September 
1997.
    (3) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting particulate matter emissions at 
concentrations of 10 milligrams per actual cubic meter or less.
    (4) The bag leak detection system sensor must provide output of 
relative or absolute particulate matter loadings.
    (5) The bag leak detection system must be equipped with a device to 
continuously record the output signal from the sensor.
    (6) The bag leak detection system must be equipped with an alarm 
system that will sound automatically when an increase in relative 
particulate matter emissions over a preset level is detected. The alarm 
must be located where it is easily heard by plant operating personnel.
    (7) For positive pressure fabric filter systems that do not duct 
all compartments of cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
    (8) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors.


Sec.  63.7530  How do I demonstrate initial compliance with the 
emission limits and work practice standards?

    (a) You must demonstrate initial compliance with each emission 
limit that applies to you by conducting initial performance tests 
(performance stack tests and fuel analyses) and establishing operating 
limits, as applicable, according to Sec.  63.7520, paragraph (c) of 
this section, and Tables 5 and 7 to this subpart.
    (b) If you demonstrate compliance through performance stack 
testing, you must establish each site-specific operating limit in Table 
2 to this subpart that applies to you according to the requirements in 
Sec.  63.7520, Table 7 to this subpart, and paragraph (c)(4) of this 
section, as applicable. You must also

[[Page 32057]]

conduct fuel analyses according to Sec.  63.7521 and establish maximum 
fuel pollutant input levels according to paragraphs (c)(1) through (3) 
of this section, as applicable.
    (1) You must establish the maximum chlorine fuel input 
(Cinput) during the initial performance testing according to 
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your boiler or process heater that has the highest content of 
chlorine.
    (ii) During the performance testing for HCl, you must determine the 
fraction of the total heat input for each fuel type burned 
(Qi) based on the fuel mixture that has the highest content 
of chlorine, and the average chlorine concentration of each fuel type 
burned (Ci).
    (iii) You must establish a maximum chlorine input level using 
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.009

Where:

Clinput = Maximum amount of chlorine entering the boiler 
or process heater through fuels burned in units of pounds per 
million Btu.
Ci = Arithmetic average concentration of chlorine in fuel 
type, i, analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
Qi = Fraction of total heat input from fuel type, i, 
based on the fuel mixture that has the highest content of chlorine. 
If you do not burn multiple fuel types during the performance 
testing, it is not necessary to determine the value of this term. 
Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of chlorine.

    (2) You must establish the maximum mercury fuel input level 
(Mercuryinput) during the initial performance testing using 
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your boiler or process heater that has the highest content of 
mercury.
    (ii) During the compliance demonstration for mercury, you must 
determine the fraction of total heat input for each fuel burned 
(Qi) based on the fuel mixture that has the highest content 
of mercury, and the average mercury concentration of each fuel type 
burned (HGi).
    (iii) You must establish a maximum mercury input level using 
Equation 8 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.010

Where:

Mercuryinput = Maximum amount of mercury entering the 
boiler or process heater through fuels burned in units of pounds per 
million Btu.
HGi = Arithmetic average concentration of mercury in fuel 
type, i, analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
Qi = Fraction of total heat input from fuel type, i, 
based on the fuel mixture that has the highest mercury content. If 
you do not burn multiple fuel types during the performance test, it 
is not necessary to determine the value of this term. Insert a value 
of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of mercury.

    (3) You must establish parameter operating limits according to 
paragraphs (c)(4)(i) through (iv) of this section.
    (i) For a wet scrubber, you must establish the minimum scrubber 
effluent pH, liquid flowrate, and pressure drop as defined in Sec.  
63.7575, as your operating limits during the three-run performance 
test. If you use a wet scrubber and you conduct separate performance 
tests for particulate matter, HCl, and mercury emissions, you must 
establish one set of minimum scrubber effluent pH, liquid flowrate, and 
pressure drop operating limits. The minimum scrubber effluent pH 
operating limit must be established during the HCl performance test. If 
you conduct multiple performance tests, you must set the minimum liquid 
flowrate and pressure drop operating limits at the highest minimum 
values established during the performance tests.
    (ii) For an electrostatic precipitator, you must establish the 
minimum voltage and secondary current (or total power input), as 
defined in Sec.  63.7575, as your operating limits during the three-run 
performance test.
    (iii) For a dry scrubber, you must establish the minimum sorbent 
injection rate for each sorbent, as defined in Sec.  63.7575, as your 
operating limit during the three-run performance test.
    (iv) The operating limit for boilers or process heaters with fabric 
filters that choose to demonstrate continuous compliance through bag 
leak detection systems is that a bag leak detection system be installed 
according to the requirements in Sec.  63.7525, and that each fabric 
filter must be operated such that the bag leak detection system alarm 
does not sound more than 5 percent of the operating time during a 6-
month period.
    (c) If you elect to demonstrate compliance with an applicable 
emission limit through fuel analysis, you must conduct fuel analyses 
according to Sec.  63.7521 and follow the procedures in paragraphs 
(c)(1) through (5) of this section.
    (1) If you burn more than one fuel type, you must determine the 
fuel mixture you could burn in your boiler or process heater that would 
result in the maximum emission rates of the pollutants that you elect 
to demonstrate compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel 
pollutant concentration of the composite samples analyzed for each fuel 
type using the one-sided z-statistic test described in Equation 9 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.011

Where:

P90 = 90th percentile confidence level pollutant 
concentration, in pounds per million Btu.
mean = Arithmetic average of the fuel pollutant concentration in the 
fuel samples analyzed according to Sec.  63.7521, in units of pounds 
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel 
samples analyzed according to Sec.  63.7521, in units of pounds per 
million Btu.
t = t distribution critical value for 90th percentile (0.1) 
probability for the appropriate degrees of freedom (number of 
samples minus one) as obtained from a Distribution Critical Value 
Table.

    (3) To demonstrate compliance with the applicable emission limit 
for HCl, the HCl emission rate that you calculate for your boiler or 
process heater using Equation 10 of this section must not exceed the 
applicable emission limit for HCl.

[[Page 32058]]

[GRAPHIC] [TIFF OMITTED] TP04JN10.012

Where:

HCl = HCl emission rate from the boiler or process heater in units 
of pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of 
chlorine in fuel type, i, in units of pounds per million Btu as 
calculated according to Equation 8 of this section.
     Qi= Fraction of total heat input from fuel type, i, 
based on the fuel mixture that has the highest content of chlorine. 
If you do not burn multiple fuel types, it is not necessary to 
determine the value of this term. Insert a value of ``1'' for 
Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    (4) To demonstrate compliance with the applicable emission limit 
for mercury, the mercury emission rate that you calculate for your 
boiler or process heater using Equation 11 of this section must not 
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TP04JN10.013

Where:

Mercury = Mercury emission rate from the boiler or process heater in 
units of pounds per million Btu.
HGi90 = 90th percentile confidence level concentration of 
mercury in fuel, i, in units of pounds per million Btu as calculated 
according to Equation 8 of this section.
Qi = Fraction of total heat input from fuel type, i, 
based on the fuel mixture that has the highest mercury content. If 
you do not burn multiple fuel types, it is not necessary to 
determine the value of this term. Insert a value of ``1'' for 
Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest mercury content.

    (d) If you own or operate an existing unit with a heat input 
capacity of 10 million Btu per hour or less, you must submit a signed 
statement in the Notification of Compliance Status report that 
indicates that you conducted a tune-up of the unit.
    (e) You must submit the energy assessment report, along with a 
signed certification that the assessment is an accurate depiction of 
your facility.
    (f) You must submit the Notification of Compliance Status 
containing the results of the initial compliance demonstration 
according to the requirements in Sec.  63.7545(e).

Continuous Compliance Requirements


Sec.  63.7535  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) You must monitor and collect data according to this section and 
the site-specific monitoring plan required by Sec.  63.7505(d).
    (b) Except for monitor malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must monitor continuously (or collect data at all required 
intervals) at all times that the affected source is operating.
    (c) You may not use data recorded during monitoring malfunctions, 
associated repairs, or required quality assurance or control activities 
in data averages and calculations used to report emission or operating 
levels. You must use all the data collected during all other periods in 
assessing the operation of the control device and associated control 
system.


Sec.  63.7540  How do I demonstrate continuous compliance with the 
emission limits and work practice standards?

    (a) You must demonstrate continuous compliance with each emission 
limit, operating limit, and work practice standard in Tables 1 through 
3 to this subpart that applies to you according to the methods 
specified in Table 8 to this subpart and paragraphs (a)(1) through (10) 
of this section.
    (1) Following the date on which the initial performance test is 
completed or is required to be completed under Sec. Sec.  63.7 and 
63.7510, whichever date comes first, you must not operate above any of 
the applicable maximum operating limits or below any of the applicable 
minimum operating limits listed in Table 4 to this subpart at any 
times. Operation above the established maximum or below the established 
minimum operating limits shall constitute a deviation of established 
operating limits. Operating limits must be confirmed or reestablished 
during performance tests.
    (2) As specified in Sec.  63.7550(c), you must keep records of the 
type and amount of all fuels burned in each boiler or process heater 
during the reporting period to demonstrate that all fuel types and 
mixtures of fuels burned would either result in lower emissions of HCl 
and mercury, than the applicable emission limit for each pollutant (if 
you demonstrate compliance through fuel analysis), or result in lower 
fuel input of chlorine and mercury than the maximum values calculated 
during the last performance tests (if you demonstrate compliance 
through performance stack testing).
    (3) If you demonstrate compliance with an applicable HCl emission 
limit through fuel analysis and you plan to burn a new type of fuel, 
you must recalculate the HCl emission rate using Equation 9 of Sec.  
63.7530 according to paragraphs (a)(3)(i) through (iii) of this 
section.
    (i) You must determine the chlorine concentration for any new fuel 
type in units of pounds per million Btu, based on supplier data or your 
own fuel analysis, according to the provisions in your site-specific 
fuel analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of chlorine.
    (iii) Recalculate the HCl emission rate from your boiler or process 
heater under these new conditions using Equation 9 of Sec.  63.7530. 
The recalculated HCl emission rate must be less than the applicable 
emission limit.
    (4) If you demonstrate compliance with an applicable HCl emission 
limit through performance testing and you plan to burn a new type of 
fuel or a new mixture of fuels, you must recalculate the maximum 
chlorine input using Equation 5 of Sec.  63.7530. If the results of 
recalculating the maximum chlorine input using Equation 5 of Sec.  
63.7530 are higher than the maximum chlorine input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.7520 to demonstrate 
that the HCl emissions do not exceed the emission limit. You must also 
establish new operating limits based on this performance test according 
to the procedures in Sec.  63.7530(c).
    (5) If you demonstrate compliance with an applicable mercury 
emission limit through fuel analysis, and you plan to burn a new type 
of fuel, you must recalculate the mercury emission rate using Equation 
11 of Sec.  63.7530 according to the procedures specified in paragraphs 
(a)(7)(i) through (iii) of this section.
    (i) You must determine the mercury concentration for any new fuel 
type in

[[Page 32059]]

units of pounds per million Btu, based on supplier data or your own 
fuel analysis, according to the provisions in your site-specific fuel 
analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of mercury.
    (iii) Recalculate the mercury emission rate from your boiler or 
process heater under these new conditions using Equation 11 of Sec.  
63.7530. The recalculated mercury emission rate must be less than the 
applicable emission limit.
    (6) If you demonstrate compliance with an applicable mercury 
emission limit through performance testing, and you plan to burn a new 
type of fuel or a new mixture of fuels, you must recalculate the 
maximum mercury input using Equation 7 of Sec.  63.7530. If the results 
of recalculating the maximum mercury input using Equation 7 of Sec.  
63.7530 are higher than the maximum mercury input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.7520 to demonstrate 
that the mercury emissions do not exceed the emission limit. You must 
also establish new operating limits based on this performance test 
according to the procedures in Sec.  63.7530(c).
    (7) If your unit is controlled with a fabric filter, and you 
demonstrate continuous compliance using a bag leak detection system, 
you must initiate corrective action within 1 hour of a bag leak 
detection system alarm and complete corrective actions as soon as 
practical, and operate and maintain the fabric filter system such that 
the alarm does not sound more than 5 percent of the operating time 
during a 6-month period. You must also keep records of the date, time, 
and duration of each alarm, the time corrective action was initiated 
and completed, and a brief description of the cause of the alarm and 
the corrective action taken. You must also record the percent of the 
operating time during each 6-month period that the alarm sounds. In 
calculating this operating time percentage, if inspection of the fabric 
filter demonstrates that no corrective action is required, no alarm 
time is counted. If corrective action is required, each alarm shall be 
counted as a minimum of 1 hour. If you take longer than 1 hour to 
initiate corrective action, the alarm time shall be counted as the 
actual amount of time taken to initiate corrective action.
    (8) If you are required to install a CEMS according to Sec.  
63.7525(a), then you must meet the requirements in paragraphs (a)(8)(i) 
through (iii) of this section.
    (i) You must continuously monitor CO according to Sec. Sec.  
63.7525(a) and 63.7535.
    (ii) Maintain a CO emission level below or at your applicable CO 
standard in Tables 1 or 2 to this subpart at all times.
    (iii) Keep records of CO levels according to Sec.  63.7555(b).
    (9) The owner or operator of an affected source using a CEMS 
measuring PM emissions to meet requirements of this subpart shall 
install, certify, operate, and maintain the CEMS as specified in 
paragraphs (a)(9)(i) through (a)(9)(iv) of this section.
    (i) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13 of 40 
CFR, Performance Specification 11 in appendix B of 40 CFR part 60, and 
procedure 2 in appendix F of 40 CFR part 60.
    (ii) During each PM correlation testing run of the CEMS required by 
Performance Specification 11 in appendix B of 40 CFR part 60, PM and O2 
(or CO2) data shall be collected concurrently (or within a 30- to 60-
minute period) by both the CEMS and conducting performance tests using 
Method 5 or 5B of appendix A-3 of 40 CFR part 60 or Method 17 of 
appendix A-6 of 40 CFR part 60.
    (iii) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of 40 CFR part 60. Relative Response Audits must be performed annually 
and Response Correlation Audits must be performed every 3 years.
    (iv) After December 31, 2011, within 60 days after the date of 
completing each performance evaluation conducted to demonstrate 
compliance with this subpart, the owner or operator of the affected 
facility must submit the test data to EPA by successfully entering the 
data electronically into EPA's WebFIRE database through EPA's Central 
Data Exchange. The owner or operator of an affected facility shall 
enter the test data into EPA's data base using the Electronic Reporting 
Tool (ERT) or other compatible electronic spreadsheet.
    (10) If your boiler or process heater is in either the Gas 1 (NG/
RG) or Metal Process Furnace subcategories and have a heat input 
capacity of 10 million Btu per hour or greater, you must conduct a 
tune-up of the boiler or process heater annually to demonstrate 
continuous compliance as specified in paragraphs (a)(10)(i) through 
(a)(10)(vi) of this section.
    (i) Inspect the burner, and clean or replace any components of the 
burner as necessary;
    (ii) Inspect the flame pattern and make any adjustments to the 
burner necessary to optimize the flame pattern consistent with the 
manufacturer's specifications;
    (iii) Inspect the system controlling the air-to-fuel ratio, and 
ensure that it is correctly calibrated and functioning properly;
    (iv) Minimize total emissions of CO consistent with the 
manufacturer's specifications;
    (v) Measure the concentration in the effluent stream of CO in parts 
per million, by volume, dry basis (ppmvd), before and after the 
adjustments are made; and
    (vi) Maintain on-site and submit, if requested by the 
Administrator, an annual report containing the information in 
paragraphs (a)(10)(vi)(A) through (C) of this section,
    (A) The concentrations of CO in the effluent stream in ppmvd, and 
oxygen in percent dry basis, measured before and after the adjustments 
of the boiler;
    (B) A description of any corrective actions taken as a part of the 
combustion adjustment; and
    (C) The type and amount of fuel used over the 12 months prior to 
the annual adjustment.
    (11) If your boiler or process heater has a heat input capacity of 
less than 10 million Btu per hour, you must conduct a tune-up of the 
boiler or process heater biennially to demonstrate continuous 
compliance as specified in paragraphs (a)(10)(i) through (a)(10)(vi) of 
this section.
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 through 4 to this 
subpart that apply to you. These instances are deviations from the 
emission limits in this subpart. These deviations must be reported 
according to the requirements in Sec.  63.7550.


Sec.  63.7541  How do I demonstrate continuous compliance under the 
emission averaging provision?

    (a) Following the compliance date, the owner or operator must 
demonstrate compliance with this subpart on a continuous basis by 
meeting the requirements of paragraphs (a)(1) through (5) of this 
section.
    (1) For each calendar month, demonstrate compliance with the 
average weighted emissions limit for the existing units participating 
in the

[[Page 32060]]

emissions averaging option as determined in Sec.  63.7522(f) and (g);
    (2) You must maintain the applicable opacity limit according to 
paragraphs (a)(2)(i) through (ii) of this section.
    (i) For each existing unit participating in the emissions averaging 
option that is equipped with a dry control system and not vented to a 
common stack, maintain opacity at or below the applicable limit.
    (ii) For each group of units participating in the emissions 
averaging option where each unit in the group is equipped with a dry 
control system and vented to a common stack that does not receive 
emissions from nonaffected units, maintain opacity at or below the 
applicable limit at the common stack;
    (3) For each existing unit participating in the emissions averaging 
option that is equipped with a wet scrubber, maintain the 3-hour 
average parameter values at or below the operating limits established 
during the most recent performance test; and
    (4) For each existing unit participating in the emissions averaging 
option that has an approved alternative operating plan, maintain the 3-
hour average parameter values at or below the operating limits 
established in the most recent performance test.
    (5) For each existing unit participating in the emissions averaging 
option venting to a common stack configuration containing affected 
units from other subcategories, maintain the appropriate operating 
limit for each unit as specified in Table 4 to this subpart that 
applies.
    (b) Any instance where the owner or operator fails to comply with 
the continuous monitoring requirements in paragraphs (a)(1) through (5) 
of this section is a deviation.

Notification, Reports, and Records


Sec.  63.7545  What notifications must I submit and when?

    (a) You must submit all of the notifications in Sec. Sec.  63.7(b) 
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply 
to you by the dates specified.
    (b) As specified in Sec.  63.9(b)(2), if you startup your affected 
source before [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 
FEDERAL REGISTER], you must submit an Initial Notification not later 
than 120 days after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE 
IN THE FEDERAL REGISTER].
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup 
your new or reconstructed affected source on or after [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
submit an Initial Notification not later than 15 days after the actual 
date of startup of the affected source.
    (d) If you are required to conduct a performance test you must 
submit a Notification of Intent to conduct a performance test at least 
30 days before the performance test is scheduled to begin.
    (e) If you are required to conduct an initial compliance 
demonstration as specified in Sec.  63.7530(a), you must submit a 
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii). 
For each initial compliance demonstration, you must submit the 
Notification of Compliance Status, including all performance test 
results and fuel analyses, before the close of business on the 60th day 
following the completion of the performance test and/or other initial 
compliance demonstrations according to Sec.  63.10(d)(2). The 
Notification of Compliance Status report must contain all the 
information specified in paragraphs (e)(1) through (9) of this section, 
as applicable.
    (1) A description of the affected source(s) including 
identification of which subcategory the source is in, the design 
capacity of the source, a description of the add-on controls used on 
the source, description of the fuel(s) burned, including whether the 
fuel(s) were determined by you or EPA through a petition process to be 
a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from 
discarded non-hazardous secondary materials within the meaning of 40 
CFR 241.3, and justification for the selection of fuel(s) burned during 
the performance test.
    (2) Summary of the results of all performance tests (stack tests 
and fuel analyses) and calculations conducted to demonstrate initial 
compliance including all established operating limits.
    (3) A summary of the CO emissions monitoring data and the maximum 
CO emission levels recorded during the performance test to show that 
you have met any applicable emission standard in Table 1 or 2 to this 
subpart.
    (4) Identification of whether you plan to demonstrate compliance 
with each applicable emission limit through performance stack testing 
or fuel analysis.
    (5) Identification of whether you plan to demonstrate compliance by 
emissions averaging.
    (6) A signed certification that you have met all applicable 
emission limits and work practice standards.
    (7) If you had a deviation from any emission limit, work practice 
standard, or operating limit, you must also submit a description of the 
deviation, the duration of the deviation, and the corrective action 
taken in the Notification of Compliance Status report.
    (f) If you operate a natural gas-fired boiler or process heater 
that is subject to this subpart, and you intend to use a fuel other 
than natural gas or equivalent to fire the affected unit, you must 
submit a notification of alternative fuel use within 48 hours of the 
declaration of a period of natural gas curtailment or supply 
interruption, as defined in Sec.  63.7575. The notification must 
include the information specified in paragraphs (f)(1) through (5) of 
this section.
    (1) Company name and address.
    (2) Identification of the affected unit.
    (3) Reason you are unable to use natural gas or equivalent fuel, 
including the date when the natural gas curtailment was declared or the 
natural gas supply interruption began.
    (4) Type of alternative fuel that you intend to use.
    (5) Dates when the alternative fuel use is expected to begin and 
end.


Sec.  63.7550  What reports must I submit and when?

    (a) You must submit each report in Table 9 to this subpart that 
applies to you.
    (b) Unless the EPA Administrator has approved a different schedule 
for submission of reports under Sec.  63.10(a), you must submit each 
report by the date in Table 9 to this subpart and according to the 
requirements in paragraphs (b)(1) through (5) of this section.
    (1) The first compliance report must cover the period beginning on 
the compliance date that is specified for your affected source in Sec.  
63.7495 and ending on June 30 or December 31, whichever date is the 
first date that occurs at least 180 days after the compliance date that 
is specified for your source in Sec.  63.7495.
    (2) The first compliance report must be postmarked or delivered no 
later than July 31 or January 31, whichever date is the first date 
following the end of the first calendar half after the compliance date 
that is specified for your source in Sec.  63.7495.
    (3) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (4) Each subsequent compliance report must be postmarked or 
delivered no later than July 31 or January 31, whichever date is the 
first date following the end of the semiannual reporting period.

[[Page 32061]]

    (5) For each affected source that is subject to permitting 
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the 
permitting authority has established dates for submitting semiannual 
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance 
reports according to the dates the permitting authority has established 
instead of according to the dates in paragraphs (b)(1) through (4) of 
this section.
    (c) The compliance report must contain the information required in 
paragraphs (c)(1) through (9) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official with that official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (3) Date of report and beginning and ending dates of the reporting 
period.
    (4) The total fuel use by each affected source subject to an 
emission limit, for each calendar month within the semiannual reporting 
period, including, but not limited to, a description of the fuel, 
whether the fuel has received a non-waste determination by EPA or your 
basis for concluding that the fuel is not a waste, and the total fuel 
usage amount with units of measure.
    (5) A summary of the results of the annual performance tests and 
documentation of any operating limits that were reestablished during 
this test, if applicable. If you are conducting stack tests once every 
three years consistent with Sec.  63.7515(b) or (c), the date of the 
last three stack tests, a comparison of the emission level you achieved 
in the last three stack tests to the 90 percent emission limit 
threshold required in Sec.  63.7515(b) or (c), and a statement as to 
whether there have been any operational changes since the last stack 
test that could increase emissions.
    (6) A signed statement indicating that you burned no new types of 
fuel. Or, if you did burn a new type of fuel, you must submit the 
calculation of chlorine input, using Equation 5 of Sec.  63.7530, that 
demonstrates that your source is still within its maximum chlorine 
input level established during the previous performance testing (for 
sources that demonstrate compliance through performance testing) or you 
must submit the calculation of HCl emission rate using Equation 9 of 
Sec.  63.7530 that demonstrates that your source is still meeting the 
emission limit for HCl emissions (for boilers or process heaters that 
demonstrate compliance through fuel analysis). If you burned a new type 
of fuel, you must submit the calculation of mercury input, using 
Equation 7 of Sec.  63.7530, that demonstrates that your source is 
still within its maximum mercury input level established during the 
previous performance testing (for sources that demonstrate compliance 
through performance testing), or you must submit the calculation of 
mercury emission rate using Equation 11 of Sec.  63.7530 that 
demonstrates that your source is still meeting the emission limit for 
mercury emissions (for boilers or process heaters that demonstrate 
compliance through fuel analysis).
    (7) If you wish to burn a new type of fuel and you cannot 
demonstrate compliance with the maximum chlorine input operating limit 
using Equation 5 of Sec.  63.7530 or the maximum mercury input 
operating limit using Equation 7 of Sec.  63.7530, you must include in 
the compliance report a statement indicating the intent to conduct a 
new performance test within 60 days of starting to burn the new fuel.
    (8) If there are no deviations from any emission limits or 
operating limits in this subpart that apply to you, a statement that 
there were no deviations from the emission limits or operating limits 
during the reporting period.
    (9) If there were no deviations from the monitoring requirements 
including no periods during which the CMSs, including CEMS, COMS, and 
CPMS, were out of control as specified in Sec.  63.8(c)(7), a statement 
that there were no deviations and no periods during which the CMS were 
out of control during the reporting period.
    (d) For each deviation from an emission limit or operating limit in 
this subpart that occurs at an affected source where you are not using 
a CMS to comply with that emission limit or operating limit, the 
compliance report must additionally contain the information required in 
paragraphs (d)(1) through (4) of this section.
    (1) The total operating time of each affected source during the 
reporting period.
    (2) A description of the deviation and which emission limit or 
operating limit from which you deviated.
    (3) Information on the number, duration, and cause of deviations 
(including unknown cause), as applicable, and the corrective action 
taken.
    (4) A copy of the test report if the annual performance test showed 
a deviation from the emission limits.
    (e) For each deviation from an emission limit, operating limit, and 
monitoring requirement in this subpart occurring at an affected source 
where you are using a CMS to comply with that emission limit or 
operating limit, you must include the information required in 
paragraphs (e) (1) through (12) of this section. This includes any 
deviations from your site-specific monitoring plan as required in Sec.  
63.7505(d).
    (1) The date and time that each deviation started and stopped and 
description of the nature of the deviation (i.e., what you deviated 
from).
    (2) The date and time that each CMS was inoperative, except for 
zero (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control, 
including the information in Sec.  63.8(c)(8).
    (4) The date and time that each deviation started and stopped, and 
whether each deviation occurred during a period of startup, shutdown, 
or malfunction or during another period.
    (5) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (6) An analysis of the total duration of the deviations during the 
reporting period into those that are due to startup, shutdown, control 
equipment problems, process problems, other known causes, and other 
unknown causes.
    (7) A summary of the total duration of CMSs downtime during the 
reporting period and the total duration of CMS downtime as a percent of 
the total source operating time during that reporting period.
    (8) An identification of each parameter that was monitored at the 
affected source for which there was a deviation.
    (9) A brief description of the source for which there was a 
deviation.
    (10) A brief description of each CMS for which there was a 
deviation.
    (11) The date of the latest CMS certification or audit for the 
system for which there was a deviation.
    (12) A description of any changes in CMSs, processes, or controls 
since the last reporting period for the source for which there was a 
deviation.
    (f) Each affected source that has obtained a title V operating 
permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all 
deviations as defined in this subpart in the semiannual monitoring 
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A). If an affected source submits a compliance report 
pursuant to Table 9 to this subpart along with, or as part of, the 
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all 
required information concerning deviations from any

[[Page 32062]]

emission limit, operating limit, or work practice requirement in this 
subpart, submission of the compliance report satisfies any obligation 
to report the same deviations in the semiannual monitoring report. 
However, submission of a compliance report does not otherwise affect 
any obligation the affected source may have to report deviations from 
permit requirements to the permit authority.
    (g) In addition to the information required in Sec.  63.9(h)(2), 
your notification must include the following certification(s) of 
compliance, as applicable, and signed by a responsible official:
    (1) ``This facility complies with the requirements in Sec.  
63.7540(a)(10) to conduct an annual tune-up of the unit''.
    (2) ``This facility has had an energy assessment performed 
according to Sec.  63.7530(e).''
    (3) ``No secondary materials that are solid waste were combusted in 
any affected unit.''
    (h) After December 31, 2011, within 60 days after the date of 
completing each performance evaluation conducted to demonstrate 
compliance with this subpart, the owner or operator of the affected 
facility must submit the test data to EPA by entering the data 
electronically into EPA's WebFIRE data base through EPA's Central Data 
Exchange. The owner or operator of an affected facility shall enter the 
test data into EPA's data base using the Electronic Reporting Tool or 
other compatible electronic spreadsheet. Only performance evaluation 
data collected using methods compatible with ERT are subject to this 
requirement to be submitted electronically into EPA's WebFIRE database.


Sec.  63.7555  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) and (2) of 
this section.
    (1) A copy of each notification and report that you submitted to 
comply with this subpart, including all documentation supporting any 
Initial Notification or Notification of Compliance Status or semiannual 
compliance report that you submitted, according to the requirements in 
Sec.  63.10(b)(2)(xiv).
    (2) Records of performance stack tests, fuel analyses, or other 
compliance demonstrations, performance evaluations, and opacity 
observations as required in Sec.  63.10(b)(2)(viii).
    (b) For each CEMS, CPMS, and COMS, you must keep records according 
to paragraphs (b)(1) through (5) of this section.
    (1) Records described in Sec.  63.10(b)(2)(vi) through (xi).
    (2) Monitoring data for continuous opacity monitoring system during 
a performance evaluation as required in Sec.  63.6(h)(7)(i) and (ii).
    (3) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (4) Request for alternatives to relative accuracy test for CEMS as 
required in Sec.  63.8(f)(6)(i).
    (5) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (c) You must keep the records required in Table 8 to this subpart 
including records of all monitoring data and calculated averages for 
applicable operating limits such as opacity, pressure drop, and pH to 
show continuous compliance with each emission limit and operating limit 
that applies to you.
    (d) For each boiler or process heater subject to an emission limit, 
you must also keep the records in paragraphs (d)(1) through (5) of this 
section.
    (1) You must keep records of monthly fuel use by each boiler or 
process heater, including the type(s) of fuel and amount(s) used.
    (2) If you combust non-hazardous secondary materials that have been 
determined not to be solid waste pursuant to 40 CFR 41.3(b)(1), you 
must keep a record which documents how the secondary material meets 
each of the legitimacy criteria. If you combust a fuel that has been 
processed from a discarded non-hazardous secondary material pursuant to 
40 CFR 241.3(b)(2), you must keep records as to how the operations that 
produced the fuel satisfies the definition of processing in 40 CFR 
241.2. If the fuel received a non-waste determination pursuant to the 
petition process submitted under 40 CFR 241.3(c), you must keep a 
record which documents how the fuel satisfies the requirements of the 
petition process.
    (3) You must keep records of monthly hours of operation by each 
boiler or process heater. This requirement applies only to limited-use 
boilers and process heaters.
    (4) A copy of all calculations and supporting documentation of 
maximum chlorine fuel input, using Equation 5 of Sec.  63.7530, that 
were done to demonstrate continuous compliance with the HCl emission 
limit, for sources that demonstrate compliance through performance 
testing. For sources that demonstrate compliance through fuel analysis, 
a copy of all calculations and supporting documentation of HCl emission 
rates, using Equation 9 of Sec.  63.7530, that were done to demonstrate 
compliance with the HCl emission limit. Supporting documentation should 
include results of any fuel analyses and basis for the estimates of 
maximum chlorine fuel input or HCl emission rates. You can use the 
results from one fuel analysis for multiple boilers and process heaters 
provided they are all burning the same fuel type. However, you must 
calculate chlorine fuel input, or HCl emission rate, for each boiler 
and process heater.
    (5) A copy of all calculations and supporting documentation of 
maximum mercury fuel input, using Equation 7 of Sec.  63.7530, that 
were done to demonstrate continuous compliance with the mercury 
emission limit for sources that demonstrate compliance through 
performance testing. For sources that demonstrate compliance through 
fuel analysis, a copy of all calculations and supporting documentation 
of mercury emission rates, using Equation 11 of Sec.  63.7530, that 
were done to demonstrate compliance with the mercury emission limit. 
Supporting documentation should include results of any fuel analyses 
and basis for the estimates of maximum mercury fuel input or mercury 
emission rates. You can use the results from one fuel analysis for 
multiple boilers and process heaters provided they are all burning the 
same fuel type. However, you must calculate mercury fuel input, or 
mercury emission rates, for each boiler and process heater.
    (6) If consistent with Sec.  63.7555(b) and (c), you choose to 
stack test less frequently than annually, you must keep annual records 
that document that your emissions in the previous stack test(s) were 
less than 90 percent of the applicable emission limit, and document 
that there was no change in source operations including fuel 
composition and operation of air pollution control equipment that would 
cause emissions of the relevant pollutant to increase within the past 
year.
    (7) If you operate a gaseous fuel unit that is subject to the 
emission limits specified in Table 1 or 2 to this subpart, and you 
intend to use a fuel other than natural gas or equivalent to fire the 
affected unit, you must keep records of the information required by the 
notification under Sec.  63.7550, and records of the total hours per 
calendar year that liquid fuel is burned.
    (e) If you elect to average emissions consistent with Sec.  
63.7522, you must additionally keep a copy of the emission averaging 
implementation plan required in Sec.  63.7522(g), all calculations 
required

[[Page 32063]]

under Sec.  63.7522, including daily records of heat input or steam 
generation, as applicable, and monitoring records consistent with Sec.  
63.7541.


Sec.  63.7560  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec.  63.10(b)(1).
    (b) As specified in Sec.  63.10(b)(1), you must keep each record 
for 5 years following the date of each occurrence, measurement, 
maintenance, corrective action, report, or record.
    (c) You must keep each record on site for at least 2 years after 
the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec.  63.10(b)(1). You can keep 
the records off site for the remaining 3 years.

Other Requirements and Information


Sec.  63.7565  What parts of the General Provisions apply to me?

    Table 10 to this subpart shows which parts of the General 
Provisions in Sec. Sec.  63.1 through 63.15 apply to you.


Sec.  63.7570  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by U.S. EPA, or a 
delegated authority such as your State, local, or tribal agency. If the 
EPA Administrator has delegated authority to your State, local, or 
tribal agency, then that agency (as well as the U.S. EPA) has the 
authority to implement and enforce this subpart. You should contact 
your EPA Regional Office to find out if this subpart is delegated to 
your State, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a State, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities listed in paragraphs (b)(1) through (5) of 
this section are retained by the EPA Administrator and are not 
transferred to the State, local, or tribal agency, however, the U.S. 
EPA retains oversight of this subpart and can take enforcement actions, 
as appropriate.
    (1) Approval of alternatives to the non-opacity emission limits and 
work practice standards in Sec.  63.7500(a) and (b) under Sec.  
63.6(g).
    (2) Approval of alternative opacity emission limits in Sec.  
63.7500(a) under Sec.  63.6(h)(9).
    (3) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90, and alternative analytical methods requested under 
63.7521(b)(2).
    (4) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90, and approval of alternative operating 
parameters under 63.7500(a)(2) and 63.7522(g)(2).
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(e) and as defined in Sec.  63.90.


Sec.  63.7575  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act (CAA), 
in Sec.  63.2 (the General Provisions), and in this section as follows:
    Bag leak detection system means a group of instruments that are 
capable of monitoring particulate matter loadings in the exhaust of a 
fabric filter (i.e., baghouse) in order to detect bag failures. A bag 
leak detection system includes, but is not limited to, an instrument 
that operates on electrodynamic, triboelectric, light scattering, light 
transmittance, or other principle to monitor relative particulate 
matter loadings.
    Biomass fuel means but is not limited to, wood residue, and wood 
products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust, 
sanderdust, chips, scraps, slabs, millings, and shavings); animal 
manure, including litter and other bedding materials; vegetative 
agricultural and silvicultural materials, such as logging residues 
(slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut, 
rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean 
hulls and grounds. This definition of biomass fuel is not intended to 
suggest that these materials are or are not solid waste.
    Blast furnace gas fuel-fired boiler or process heater means an 
industrial/commercial/institutional boiler or process heater that 
receives 90 percent or more of its total heat input (based on an annual 
average) from blast furnace gas.
    Boiler means an enclosed device using controlled flame combustion 
and having the primary purpose of recovering thermal energy in the form 
of steam or hot water. A device combusting solid waste, as defined in 
40 CFR 241.3, is not a boiler. Waste heat boilers are excluded from 
this definition.
    Boiler system means the boiler and associated components, such as, 
the feedwater system, the combustion air system, the fuel system 
(including burners), blowdown system, combustion control system, and 
energy consuming systems.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials in ASTM D388-991.\1\, ``Standard Specification for 
Classification of Coals by Rank'' \1\ (incorporated by reference, see 
Sec.  63.14(b)), coal refuse, and petroleum coke. Synthetic fuels 
derived from coal for the purpose of creating useful heat including, 
but not limited to, solvent-refined coal, coal-oil mixtures, and coal-
water mixtures, for the purposes of this subpart. Coal derived gases 
are excluded from this definition.
    Coal refuse means any by-product of coal mining or coal cleaning 
operations with an ash content greater than 50 percent (by weight) and 
a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per 
pound) on a dry basis.
    Commercial/institutional boiler means a boiler used in commercial 
establishments or institutional establishments such as medical centers, 
research centers, institutions of higher education, hotels, and 
laundries to provide electricity, steam, and/or hot water.
    Common stack means the exhaust of emissions from two or more 
affected units through a single flue.
    Cost-effective energy conservation measure means a measure that is 
implemented to improve the energy efficiency of the boiler or facility 
that has a payback (return of investment) period of two years or less.
    Deviation. (1) Deviation means any instance in which an affected 
source subject to this subpart, or an owner or operator of such a 
source:
    (i) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard; or
    (ii) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit.
    (2) A deviation is not always a violation. The determination of 
whether a deviation constitutes a violation of the standard is up to 
the discretion of the entity responsible for enforcement of the 
standards.
    Distillate oil means fuel oils, including recycled oils, that 
comply with the specifications for fuel oil numbers 1 and 2, as defined 
by the American Society for Testing and Materials in ASTM D396-02a, 
``Standard Specifications for Fuel Oils'' \1\ (incorporated by 
reference, see Sec.  63.14(b)).
    Dry scrubber means an add-on air pollution control system that 
injects dry alkaline sorbent (dry injection) or sprays an alkaline 
sorbent (spray dryer) to react

[[Page 32064]]

with and neutralize acid gas in the exhaust stream forming a dry powder 
material. Sorbent injection systems in fluidized bed boilers and 
process heaters are included in this definition.
    Dutch oven means a unit having a refractory-walled cell connected 
to a conventional boiler setting. Fuel materials are introduced through 
an opening in the roof of the Dutch oven and burn in a pile on its 
floor.
    Electric utility steam generating unit means a fossil fuel-fired 
combustion unit of more than 25 megawatts that serves a generator that 
produces electricity for sale. A fossil fuel-fired unit that 
cogenerates steam and electricity and supplies more than one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit.
    Electrostatic precipitator means an add-on air pollution control 
device used to capture particulate matter by charging the particles 
using an electrostatic field, collecting the particles using a grounded 
collecting surface, and transporting the particles into a hopper.
    Energy assessment means an in-depth assessment of a facility to 
identify immediate and long-term opportunities to save energy, focusing 
on the steam and process heating systems which involves a thorough 
examination of potential savings from energy efficiency improvements, 
waste minimization and pollution prevention, and productivity 
improvement.
    Equivalent means the following only as this term is used in Table 6 
to subpart DDDDD:
    (1) An equivalent sample collection procedure means a published 
voluntary consensus standard or practice (VCS) or EPA method that 
includes collection of a minimum of three composite fuel samples, with 
each composite consisting of a minimum of three increments collected at 
approximately equal intervals over the test period.
    (2) An equivalent sample compositing procedure means a published 
VCS or EPA method to systematically mix and obtain a representative 
subsample (part) of the composite sample.
    (3) An equivalent sample preparation procedure means a published 
VCS or EPA method that: Clearly states that the standard, practice or 
method is appropriate for the pollutant and the fuel matrix; or is 
cited as an appropriate sample preparation standard, practice or method 
for the pollutant in the chosen VCS or EPA determinative or analytical 
method.
    (4) An equivalent procedure for determining heat content means a 
published VCS or EPA method to obtain gross calorific (or higher 
heating) value.
    (5) An equivalent procedure for determining fuel moisture content 
means a published VCS or EPA method to obtain moisture content. If the 
sample analysis plan calls for determining metals (especially the 
mercury, selenium, or arsenic) using an aliquot of the dried sample, 
then the drying temperature must be modified to prevent vaporizing 
these metals. On the other hand, if metals analysis is done on an ``as 
received'' basis, a separate aliquot can be dried to determine moisture 
content and the metals concentration mathematically adjusted to a dry 
basis.
    (6) An equivalent pollutant (mercury) determinative or analytical 
procedure means a published VCS or EPA method that clearly states that 
the standard, practice, or method is appropriate for the pollutant and 
the fuel matrix and has a published detection limit equal to or lower 
than the methods listed in Table 6 to subpart DDDDD for the same 
purpose.
    Fabric filter means an add-on air pollution control device used to 
capture particulate matter by filtering gas streams through filter 
media, also known as a baghouse.
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including the requirements of 40 
CFR parts 60 and 61, requirements within any applicable State 
implementation plan, and any permit requirements established under 40 
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
    Fuel type means each category of fuels that share a common name or 
classification. Examples include, but are not limited to, bituminous 
coal, subbituminous coal, lignite, anthracite, biomass, residual oil. 
Individual fuel types received from different suppliers are not 
considered new fuel types.
    Fluidized bed boiler means a boiler utilizing a fluidized bed 
combustion process.
    Fluidized bed combustion means a process where a fuel is burned in 
a bed of granulated particles which are maintained in a mobile 
suspension by the forward flow of air and combustion products.
    Fuel cell means a boiler type in which the fuel is dropped onto 
suspended fixed grates and is fired in a pile. The refractory-lined 
fuel cell uses combustion air preheating and positioning of secondary 
and tertiary air injection ports to improve boiler efficiency.
    Gaseous fuel includes, but is not limited to, natural gas, process 
gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast 
furnace gas is exempted from this definition.
    Heat input means heat derived from combustion of fuel in a boiler 
or process heater and does not include the heat input from preheated 
combustion air, recirculated flue gases, or exhaust gases from other 
sources such as gas turbines, internal combustion engines, kilns, etc.
    Hot water heater means a closed vessel with a capacity of no more 
than 120 U.S. gallons in which water is heated by combustion of gaseous 
or liquid fuel and is withdrawn for use external to the vessel at 
pressures not exceeding 160 psig, including the apparatus by which the 
heat is generated and all controls and devices necessary to prevent 
water temperatures from exceeding 210 [deg] F (99 [deg] C).
    Industrial boiler means a boiler used in manufacturing, processing, 
mining, and refining or any other industry to provide steam, hot water, 
and/or electricity.
    Liquid fuel includes, but is not limited to, distillate oil, 
residual oil, on-spec used oil, and biodiesel.
    Liquid fuel subcategory includes any boiler or process heater of 
any design that burns more than 10 percent liquid fuel and less than 10 
percent solid fuel, on an annual heat input basis.
    Metal process furnaces include natural gas-fired annealing 
furnaces, preheat furnaces, reheat furnaces, aging furnaces, and heat 
treat furnaces.
    Minimum pressure drop means 90 percent of the test average pressure 
drop measured according to Table 7 to this subpart during the most 
recent performance test demonstrating compliance with the applicable 
emission limit.
    Minimum scrubber effluent pH means 90 percent of the test average 
effluent pH measured at the outlet of the wet scrubber according to 
Table 7 to this subpart during the most recent performance test 
demonstrating compliance with the applicable hydrogen chloride emission 
limit.
    Minimum scrubber flow rate means 90 percent of the test average 
flow rate measured according to Table 7 to this subpart during the most 
recent performance test demonstrating compliance with the applicable 
emission limit.
    Minimum sorbent injection rate means 90 percent of the test average 
sorbent (or activated carbon) injection rate for each sorbent measured 
according to Table 7 to this subpart during the most recent performance 
test

[[Page 32065]]

demonstrating compliance with the applicable emission limits.
    Minimum voltage or amperage means 90 percent of the test average 
voltage or amperage to the electrostatic precipitator measured 
according to Table 7 to this subpart during the most recent performance 
test demonstrating compliance with the applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath the earth's surface, of 
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society for 
Testing and Materials in ASTM D1835-03a, ``Standard Specification for 
Liquid Petroleum Gases'' (incorporated by reference, see Sec.  
63.14(b)).
    Opacity means the degree to which emissions reduce the transmission 
of light and obscure the view of an object in the background.
    Particulate matter means any finely divided solid or liquid 
material, other than uncombined water, as measured by the test methods 
specified under this subpart, or an alternative method.
    Period of natural gas curtailment or supply interruption means a 
period of time during which the supply of natural gas to an affected 
facility is halted for reasons beyond the control of the facility. An 
increase in the cost or unit price of natural gas does not constitute a 
period of natural gas curtailment or supply interruption.
    Process heater means an enclosed device using controlled flame, 
that is not a boiler, and the unit's primary purpose is to transfer 
heat indirectly to a process material (liquid, gas, or solid) or to a 
heat transfer material for use in a process unit, instead of generating 
steam. Process heaters are devices in which the combustion gases do not 
directly come into contact with process materials. A device combusting 
solid waste, as defined in 40 CFR 241.3, is not a process heater. 
Process heaters do not include units used for comfort heat or space 
heat, food preparation for on-site consumption, or autoclaves.
    Pulverized coal boiler means a boiler in which pulverized coal is 
introduced into an air stream that carries the coal to the combustion 
chamber of the boiler where it is fired in suspension.
    Qualified personnel means specialists in evaluating energy systems, 
such as those who have successfully completed the DOE Qualified 
Specialist program for all systems, Certified Energy Manager certified 
by the Association of Energy Engineers, or the equivalent.
    Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, 
as defined by the American Society for Testing and Materials in ASTM 
D396-02a, ``Standard Specifications for Fuel Oils \1\'' (incorporated 
by reference, see Sec.  63.14(b)).
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    Stoker means a unit consisting of a mechanically operated fuel 
feeding mechanism, a stationary or moving grate to support the burning 
of fuel and admit undergrate air to the fuel, an overfire air system to 
complete combustion, and an ash discharge system. There are two general 
types of stokers: Underfeed and overfeed. Overfeed stokers include mass 
feed and spreader stokers.
    Suspension boiler means a unit designed to feed the fuel by means 
of fuel distributors. The distributors inject air at the point where 
the fuel is introduced into the boiler in order to spread the fuel 
material over the boiler width. The drying (and much of the combustion) 
occurs while the material is suspended in air. The combustion of the 
fuel material is completed on a grate or floor below. Suspension 
boilers almost universally are designed to have high heat release rates 
to quickly dry the wet fuel as it is blown into the boilers.
    Temporary boiler means any gaseous or liquid fuel boiler that is 
designed to, and is capable of, being carried or moved from one 
location to another. A temporary boiler that remains at a location for 
more than 180 consecutive days is no longer considered to be a 
temporary boiler. Any temporary boiler that replaces a temporary boiler 
at a location and is intended to perform the same or similar function 
will be included in calculating the consecutive time period.
    Tune-up means adjustments made to a boiler in accordance with 
procedures supplied by the manufacturer (or an approved specialist) to 
optimize the combustion efficiency.
    Unit designed to burn biomass subcategory includes any boiler or 
process heater that burns at least 10 percent biomass, but less than 10 
percent coal, on a heat input basis on an annual average, either alone 
or in combination with liquid fuels or gaseous fuels.
    Unit designed to burn coal subcategory includes any boiler or 
process heater that burns any coal alone or at least 10 percent coal on 
a heat input basis on an annual average in combination with biomass, 
liquid fuels, or gaseous fuels.
    Unit designed to burn gas 1 (NG/RG) subcategory includes any boiler 
or process heater that burns at least 90 percent natural gas and/or 
refinery gas on a heat input basis on an annual average.
    Unit designed to burn gas 2 (other) subcategory includes any boiler 
or process heater that burns gaseous fuels other than natural gas and/
or refinery gas not combined with any solid or liquid fuels.
    Unit designed to burn oil subcategory includes any boiler or 
process heater that burns any liquid fuel, but less than 10 percent 
solid fuel on a heat input basis on an annual average, either alone or 
in combination with gaseous fuels. Gaseous fuel boilers and process 
heaters that burn liquid fuel during periods of gas curtailment, gas 
supply emergencies or for periodic testing of liquid fuel not to exceed 
a combined total of 48 hours during any calendar year are not included 
in this definition.
    Voluntary Consensus Standards or VCS mean technical standards 
(e.g., materials specifications, test methods, sampling procedures, 
business practices) developed or adopted by one or more voluntary 
consensus bodies. EPA/OAQPS has by precedent only used VCS that are 
written in English. Examples of VCS bodies are: American Society of 
Testing and Materials (ASTM), American Society of Mechanical Engineers 
(ASME), International Standards Organization (ISO), Standards Australia 
(AS), British Standards (BS), Canadian Standards (CSA), European 
Standard (EN or CEN) and German Engineering Standards (VDI). The types 
of standards that are not considered VCS are standards developed by: 
The U.S. states, e.g., California (CARB) and Texas (TCEQ); industry 
groups, such as American Petroleum Institute (API), Gas Processors 
Association (GPA), and Gas Research Institute (GRI); and other branches 
of the U.S. government, e.g., Department of Defense (DOD) and 
Department of Transportation (DOT). This does not preclude EPA from 
using standards developed by groups that are not VCS bodies within 
their rule. When this occurs, EPA has done searches and reviews for VCS 
equivalent to these non-EPA methods.
    Waste heat boiler means a device that recovers normally unused 
energy and converts it to usable heat. Waste heat recovery boilers 
incorporating duct or supplemental burners that are designed to supply 
50 percent or more of the total rated heat input capacity of the waste 
heat boiler are not considered waste heat boilers, but are considered 
boilers. Waste heat boilers are also referred to as heat recovery steam 
generators.

[[Page 32066]]

    Waste heat process heater means an enclosed device that recovers 
normally unused energy and converts it to usable heat. Waste heat 
process heaters incorporating duct or supplemental burners that are 
designed to supply 50 percent or more of the total rated heat input 
capacity of the waste heat process heater are not considered waste heat 
process heaters, but are considered process heaters. Waste heat process 
heaters are also referred to as recuperative process heaters.
    Wet scrubber means any add-on air pollution control device that 
mixes an aqueous stream or slurry with the exhaust gases from a boiler 
or process heater to control emissions of particulate matter and/or to 
absorb and neutralize acid gases, such as hydrogen chloride.
    Work practice standard means any design, equipment, work practice, 
or operational standard, or combination thereof, that is promulgated 
pursuant to section 112(h) of the CAA.

Tables to Subpart DDDDD of Part 63

    As stated in Sec.  63.7500, you must comply with the following 
applicable emission limits:

     Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or
                Reconstructed Boilers and Process Heaters
------------------------------------------------------------------------
                                                     You must meet the
   If your boiler or process    For the following    following emission
 heater is in this subcategory   pollutants . . .     limits and work
             . . .                                 practice  standards .
                                                            . .
------------------------------------------------------------------------
1. Pulverized coal............  a. Particulate     0.001 lb per MMBtu of
                                 Matter.            heat input.
                                b. Hydrogen        0.00006 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  2.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  90 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.002 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
2. Stokers designed to burn     a. Particulate     0.001 lb per MMBtu of
 coal.                           Matter.            heat input.
                                b. Hydrogen        0.00006 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  2.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  7 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.003 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
3. Fluidized bed units          a. Particulate     0.001 lb per MMBtu of
 designed to burn coal.          Matter.            heat input.
                                b. Hydrogen        0.00006 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  2.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  30 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.00003 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
4. Stokers designed to burn     a. Particulate     0.008 lb per MMBtu of
 biomass.                        Matter.            heat input.
                                b. Hydrogen        0.004 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   560 ppm by volume on
                                                    a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.00005 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
5. Fluidized bed units          a. Particulate     0.008 lb per MMBtu of
 designed to burn biomass.       Matter.            heat input.
                                b. Hydrogen        0.004 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                                    of heat input.
                                d. CO............  40 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.007 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
6. Suspension burners/Dutch     a. Particulate     0.008 lb per MMBtu of
 Ovens designed to burn          Matter.            heat input.
 biomass.                       b. Hydrogen        0.004 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   1,010 ppm by volume
                                                    on a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.03 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
7. Fuel cells designed to burn  a. Particulate     0.008 lb per MMBtu of
 biomass.                        Matter.            heat input.
                                b. Hydrogen        0.004 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   270 ppm by volume on
                                                    a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.0005 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
8. Units designed to burn       a. Particulate     0.002 lb per MMBtu of
 liquid fuel.                    Matter.            heat input.
                                b. Hydrogen        0.0004 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  3.0E-07 lb per MMBtu
                                                    of heat input.
                                d. CO............  1 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.002 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.

[[Page 32067]]

 
9. Units designed to burn       a. Particulate     0.003 lb per MMBtu of
 other gases.                    Matter.            heat input.
                                b. Hydrogen        3.0E-06 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   1 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.009 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
------------------------------------------------------------------------

    As stated in Sec.  63.7500, you must comply with the following 
applicable emission limits:

    Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing
                       Boilers and Process Heaters
 [Units with heat input capacity of 10 million Btu per hour or greater]
------------------------------------------------------------------------
                                                     You must meet the
   If your boiler or process    For the following    following emission
 heater is in this subcategory   pollutants . . .     limits and work
             . . .                                 practice  standards .
                                                            . .
------------------------------------------------------------------------
1. Pulverized coal............  a. Particulate     0.02 lb per MMBtu of
                                 Matter.            heat input.
                                b. Hydrogen        0.02 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  3.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  90 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.004 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
2. Stokers designed to burn     a. Particulate     0.02 lb per MMBtu of
 coal.                           Matter.            heat input.
                                b. Hydrogen        0.02 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  3.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  50 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.003 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
3. Fluidized bed units          a. Particulate     0.02 lb per MMBtu of
 designed to burn coal.          Matter.            heat input.
                                b. Hydrogen        0.02 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  3.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  30 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.002 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
4. Stokers designed to burn     a. Particulate     0.02 lb per MMBtu of
 biomass.                        Matter.            heat input.
                                b. Hydrogen        0.006 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  9.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   560 ppm by volume on
                                                    a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.004 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
5. Fluidized bed units          a. Particulate     0.02 lb per MMBtu of
 designed to burn biomass.       Matter.            heat input.
                                b. Hydrogen        0.006 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  9.0E-07 lb per MMBtu
                                                    of heat input.
                                d. CO............  250 ppm by volume on
                                                    a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.02 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
6. Suspension burners/Dutch     a. Particulate     0.02 lb per MMBtu of
 Ovens designed to burn          Matter.            heat input.
 biomass.                       b. Hydrogen        0.006 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  9.0E-07 lb per MMBtu
                                                    of heat input.
                                d. CO............  1,010 ppm by volume
                                                    on a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.03 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
7. Fuel cells designed to burn  a. Particulate     0.02 lb per MMBtu of
 biomass.                        Matter.            heat input.
                                b. Hydrogen        0.006 lb per MMBtu of
                                 Chloride.          heat input.
                                c. Mercury.......  9.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   270 ppm by volume on
                                                    a dry basis
                                                    corrected to 3
                                                    percent oxygen (30-
                                                    day rolling average
                                                    for units 100 MMBtu/
                                                    hr or greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.02 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.

[[Page 32068]]

 
8. Units designed to burn       a. Particulate     0.004 lb per MMBtu of
 liquid fuel.                    Matter.            heat input.
                                b. Hydrogen        0.0009 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  4.0E-06 lb per MMBtu
                                                    of heat input.
                                d. CO............  1 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.002 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
9. Units designed to burn       a. Particulate     0.05 lb per MMBtu of
 other gases.                    Matter.            heat input.
                                b. Hydrogen        3.0E-06 lb per MMBtu
                                 Chloride.          of heat input.
                                c. Mercury.......  2.0E-07 lb per MMBtu
                                d. CO............   of heat input.
                                                   1 ppm by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (30-day rolling
                                                    average for units
                                                    100 MMBtu/hr or
                                                    greater, 3-run
                                                    average for units
                                                    less than 100 MMBtu/
                                                    hr).
                                e. Dioxin/Furan..  0.009 ng/dscm (TEQ)
                                                    corrected to 7
                                                    percent oxygen.
------------------------------------------------------------------------

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

      Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
   If your boiler is . . .         You must meet the following . . .
------------------------------------------------------------------------
1. An existing boiler or       Conduct a tune-up of the boiler
 process heater with heat       biennially as specified in Sec.
 input capacity of less than    63.7540.
 10 million Btu per hour.
2. A new or existing boiler    Conduct a tune-up of the boiler annually
 or process heater in either    as specified in Sec.   63.7540.
 the Gas 1 or Metal Process
 Furnace subcategory with
 heat input capacity of 10
 million Btu per hour or
 greater.
3. An existing boiler located  Must have an energy assessment performed
 at a major source facility.    on the major source facility by
                                qualified personnel which includes:
                                  (a) a visual inspection of the boiler
                                   system.
                               (b) establish operating characteristics
                                of the facility, energy system
                                specifications, operating and
                                maintenance procedures, and unusual
                                operating constraints,
                                  (c) identify major energy consuming
                                   systems,
                                  (d) a review of available
                                   architectural and engineering plans,
                                   facility operation and maintenance
                                   procedures and logs, and fuel usage,
                                  (e) a list of major energy
                                   conservation measures,
                                  (f) the energy savings potential of
                                   the energy conservation measures
                                   identified, and
                                  (g) a comprehensive report detailing
                                   the ways to improve efficiency, the
                                   cost of specific improvements,
                                   benefits, and the time frame for
                                   recouping those investments, and
                                  (h) a facility energy management
                                   program developed according to the
                                   ENERGY STAR guideline for energy
                                   management.
------------------------------------------------------------------------

    As stated in Sec.  63.7500, you must comply with the applicable 
operating limits:

  Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
                             Process Heaters
------------------------------------------------------------------------
If you demonstrate compliance   You must meet these operating limits . .
         using . . .                               .
------------------------------------------------------------------------
1. Wet scrubber control......  a. Maintain the minimum pressure drop and
                                liquid flow-rate at or above the
                                operating levels established during the
                                performance test according to Sec.
                                63.7530(c) and Table 7 to this subpart.
2. Fabric filter control.....  a. Install and operate a bag leak
                                detection system according to Sec.
                                63.7525 and operate the fabric filter
                                such that the bag leak detection system
                                alarm does not sound more than 5 percent
                                of the operating time during each 6-
                                month period; or
                               b. This option is for boilers and process
                                heaters that operate dry control
                                systems. Existing and new boilers and
                                process heaters must maintain opacity to
                                less than or equal to 10 percent (daily
                                block average).
3. Electrostatic precipitator  a. This option is for boilers and process
 control.                       heaters that operate dry control
                                systems. Existing and new boilers and
                                process heaters must maintain opacity to
                                less than or equal to 10 percent opacity
                                (daily block average); or

[[Page 32069]]

 
                               b. This option is only for boilers and
                                process heaters that operate additional
                                wet control systems. Maintain the
                                minimum voltage and secondary current or
                                total power input of the electrostatic
                                precipitator at or above the operating
                                limits established during the
                                performance test according to Sec.
                                63.7530(c) and Table 7 to this subpart.
4. Dry scrubber or carbon      Maintain the minimum sorbent or carbon
 injection control.             injection rate at or above the operating
                                levels established during the
                                performance test according to Sec.
                                63.7530(c) and Table 7 to this subpart.
5. Any other control type....  This option is for boilers and process
                                heaters that operate dry control
                                systems. Existing and new boilers and
                                process heaters must maintain opacity to
                                less than or equal to 10 percent opacity
                                (daily block average).
6. Fuel analysis.............  Maintain the fuel type or fuel mixture
                                such that the applicable emission rates
                                calculated according to Sec.
                                63.7530(d)(3), (4) and/or (5) is less
                                than the applicable emission limits.
------------------------------------------------------------------------

    As stated in Sec.  63.7520, you must comply with the following 
requirements for performance test for existing, new or reconstructed 
affected sources:

  Table 5 to Subpart DDDDD of Part 63--Performance Testing Requirements
------------------------------------------------------------------------
 To conduct a performance test
 for the following pollutant .    You must . . .        Using . . .
              . .
------------------------------------------------------------------------
1. Particulate Matter.........  a. Select          Method 1 in appendix
                                 sampling ports     A to part 60 of this
                                 location and the   chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       in appendix A to
                                 volumetric flow-   part 60 of this
                                 rate of the        chapter.
                                 stack gas.
                                c. Determine       Method 3A or 3B in
                                 oxygen and         appendix A to part
                                 carbon dioxide     60 of this chapter,
                                 concentrations     or ASME PTC 19, Part
                                 of the stack gas.  10 (1981) (IBR, see
                                                    Sec.   63.14(i)).
                                d. Measure the     Method 4 in appendix
                                 moisture content   A to part 60 of this
                                 of the stack gas.  chapter.
                                e. Measure the     Method 5 or 17
                                 particulate        (positive pressure
                                 matter emission    fabric filters must
                                 concentration.     use Method 5D) in
                                                    appendix A to part
                                                    60 of this chapter.
                                f. Convert         Method 19 F-factor
                                 emissions          methodology in
                                 concentration to   appendix A to part
                                 lb per MMBtu       60 of this chapter.
                                 emission rates.
2. Hydrogen chloride..........  a. Select          Method 1 in appendix
                                 sampling ports     A to part 60 of this
                                 location and the   chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       in appendix A to
                                 volumetric flow-   part 60 of this
                                 rate of the        chapter.
                                 stack gas.
                                c. Determine       Method 3A or 3B in
                                 oxygen and         appendix A to part
                                 carbon dioxide     60 of this chapter,
                                 concentrations     or ASME PTC 19, Part
                                 of the stack gas.  10 (1981) (IBR, see
                                                    Sec.   63.14(i)).
                                d. Measure the     Method 4 in appendix
                                 moisture content   A to part 60 of this
                                 of the stack gas.  chapter.
                                e. Measure the     Method 26 or 26A in
                                 hydrogen           appendix A to part
                                 chloride           60 of this chapter.
                                 emission
                                 concentration.
                                f. Convert         Method 19 F-factor
                                 emissions          methodology in
                                 concentration to   appendix A to part
                                 lb per MMBtu       60 of this chapter.
                                 emission rates.
3. Mercury....................  a. Select          Method 1 in appendix
                                 sampling ports     A to part 60 of this
                                 location and the   chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       in appendix A to
                                 volumetric flow-   part 60 of this
                                 rate of the        chapter.
                                 stack gas.
                                c. Determine       Method 3A or 3B in
                                 oxygen and         appendix A to part
                                 carbon dioxide     60 of this chapter,
                                 concentrations     or ASME PTC 19, Part
                                 of the stack gas.  10 (1981) (IBR, see
                                                    Sec.   62.14(i)).
                                d. Measure the     Method 4 in appendix
                                 moisture content   A to part 60 of this
                                 of the stack gas.  chapter.
                                e. Measure the     Method 29 in appendix
                                 mercury emission   A to part 60 of this
                                 concentration.     chapter or Method
                                                    101A in appendix B
                                                    to part 61 of this
                                                    chapter or ASTM
                                                    Method D6784-02
                                                    (IBR, see Sec.
                                                    63.14(b)).
                                f. Convert         Method 19 F-factor
                                 emissions          methodology in
                                 concentration to   appendix A to part
                                 lb per MMBtu       60 of this chapter.
                                 emission rates.
4. CO.........................  a. Select the      Method 1 in appendix
                                 sampling ports     A to part 60 of this
                                 location and the   chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 3A or 3B in
                                 oxygen and         appendix A to part
                                 carbon dioxide     60 of this chapter,
                                 concentrations     or ASTM D6522-00
                                 of the stack gas.  (IBR, see Sec.
                                                    63.14(b)), or ASME
                                                    PTC 19, Part 10
                                                    (1981) (IBR, see
                                                    Sec.   63.14(i)).
                                c. Measure the     Method 4 in appendix
                                 moisture content   A to part 60 of this
                                 of the stack gas.  chapter.
                                d. Measure the CO  Method 10 in appendix
                                 emission           A to part 60 of this
                                 concentration.     chapter.
5. Dioxin/Furan...............  a. Select the      Method 1 in appendix
                                 sampling ports     A to part 60 of this
                                 location and the   chapter.
                                 number of
                                 traverse points.

[[Page 32070]]

 
                                b. Determine       Method 3A or 3B in
                                 oxygen and         appendix A to part
                                 carbon dioxide     60 of this chapter,
                                 concentrations     or ASTM D6522-00
                                 of the stack gas.  (IBR, see Sec.
                                                    63.14(b)), or ASME
                                                    PTC 19, Part 10
                                                    (1981) (IBR, see
                                                    Sec.   63.14(i)).
                                c. Measure the     Method 4 in appendix
                                 moisture content   A to part 60 of this
                                 of the stack gas.  chapter.
                                d. Measure the     Method -- in appendix
                                 dioxin/furans      A to part 60 of this
                                 emission           chapter.
                                 concentration.
------------------------------------------------------------------------

    As stated in Sec.  63.7521, you must comply with the following 
requirements for fuel analysis testing for existing, new or 
reconstructed affected sources. However, equivalent methods may be used 
in lieu of the prescribed methods at the discretion of the source owner 
or operator:

     Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
To conduct a fuel analysis for
 the following pollutant . . .    You must . . .        Using . . .
 
------------------------------------------------------------------------
1. Mercury....................  a. Collect fuel    Procedure in Sec.
                                 samples.           63.7521(c) or ASTM
                                                    D2234-D2234M-03 (for
                                                    coal) (IBR, see Sec.
                                                      63.14(b)) or ASTM
                                                    D6323-98 (2003) (for
                                                    biomass) (IBR, See
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.7521(d) or
                                                    equivalent.
                                c. Prepare         SW-846-3050B (for
                                 composited fuel    solid samples) or SW-
                                 samples.           846-3020A (for
                                                    liquid samples) or
                                                    ASTM D2013-04 (for
                                                    coal) (IBR, see Sec.
                                                      63.14(b)) or ASTM
                                                    D5198-92 (2003) (for
                                                    biomass) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865-04 (for
                                 content of the     coal) (IBR, see Sec.
                                 fuel type.           63.24(b)) or ASTM
                                                    E711-87 (for
                                                    biomass) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                e. Determine       ASTM D3173-03 (IBR,
                                 moisture content   see Sec.   63.14(b))
                                 of the fuel type.  or ASTM E871-82
                                                    (1998) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                f. Measure         ASTM D6722-01 (for
                                 mercury            coal) (IBR, see Sec.
                                 concentration in     6314(b)) or SW-846-
                                 fuel sample.       7471A (for solid
                                                    samples) or SW-846-
                                                    7470A (for liquid
                                                    samples or
                                                    equivalent.
                                g. Convert         .....................
                                 concentration
                                 into units of
                                 pounds of
                                 pollutant per
                                 MMBtu of heat
                                 content.
2. Hydrogen Chloride..........  a. Collect fuel    Procedure in Sec.
                                 samples.           63.7521(c) or ASTM
                                                    D2234-D2234M-03 (for
                                                    coal) (IBR, see Sec.
                                                      63.14(b)) or ASTM
                                                    D6323-98 (2003) (for
                                                    biomass) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.7521(d) or
                                                    equivalent.
                                c. Prepare         SW-846-3050B (for
                                 composited fuel    solid samples) or SW-
                                 samples.           846-3020A (for
                                                    liquid samples) or
                                                    ASTM D2013-04 (for
                                                    coal) (IBR, see Sec.
                                                      63.14(b)) or ASTM
                                                    D5198-92 (2003) (for
                                                    biomass) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865-04 (for
                                 content of the     coal) (IBR, see Sec.
                                 fuel type * * *.     63.14(b)) or ASTM
                                                    E711-87 (1996) (for
                                                    biomass) (IBR, see
                                                    Sec.   63.14(b)) or
                                                    equivalent.
                                e. Determine       ASTM D3173-03 (IBR,
                                 moisture content   see Sec.   63.14(b))
                                 of the fuel type.  or ASTM E871-82
                                                    (1998) or
                                                    equivalent.
                                f. Measure         SW-846-9250 or ASTM
                                 chlorine           D6721-01 (for coal)
                                 concentration in   or ASTM E776-87
                                 fuel sample.       (1996) (for biomass)
                                                    (IBR, see Sec.
                                                    63.14(b)) or
                                                    equivalent.
                                g. Convert         .....................
                                 concentrations
                                 into units of
                                 pounds of
                                 pollutant per
                                 MMBtu of heat
                                 content.
------------------------------------------------------------------------

    As stated in Sec.  63.7520, you must comply with the following 
requirements for establishing operating limits:

[[Page 32071]]



                       Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
                                  And your operating                                           According to the
    If you have an applicable      limits are based     You must . . .        Using . . .          following
    emission limit for . . .           on . . .                                               requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Particulate matter or mercury  a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       pressure drop and   collect pressure
                                   parameters.         minimum pressure    liquid flow rate    drop and liquid
                                                       drop and minimum    monitors and the    flow-rate data
                                                       flow rate           particulate         every 15 minutes
                                                       operating limit     matter or mercury   during the entire
                                                       according to Sec.   performance test.   period of the
                                                         63.7530(c).                           performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average pressure
                                                                                               drop and liquid
                                                                                               flow-rate for
                                                                                               each individual
                                                                                               test run in the
                                                                                               three-run
                                                                                               performance test
                                                                                               by computing the
                                                                                               average of all
                                                                                               the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
                                  b. Electrostatic    i. Establish a      (1) Data from the   (a) You must
                                   precipitator        site-specific       pressure drop and   collect voltage
                                   operating           minimum voltage     liquid flow rate    and secondary
                                   parameters          and secondary       monitors and the    current or total
                                   (option only for    current or total    particulate         power input data
                                   units with          power input         matter or mercury   every 15 minutes
                                   additional wet      according to Sec.   performance test.   during the entire
                                   scrubber control).    63.7530(c).                           period of the
                                                                                               performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average voltage
                                                                                               and secondary
                                                                                               current or total
                                                                                               power input for
                                                                                               each individual
                                                                                               test run in the
                                                                                               three-run
                                                                                               performance test
                                                                                               by computing the
                                                                                               average of all
                                                                                               the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
2. Hydrogen Chloride............  a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       pH, pressure        collect pH,
                                   parameters.         minimum pressure    drop, and liquid    pressure drop,
                                                       drop and minimum    flow-rate           and liquid flow-
                                                       flow rate           monitors and the    rate data every
                                                       operating limit     hydrogen chloride   15 minutes during
                                                       according to Sec.   performance test.   the entire period
                                                         63.7530(c).                           of the
                                                                                               performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average pH,
                                                                                               pressure drop,
                                                                                               and liquid flow-
                                                                                               rate for each
                                                                                               individual test
                                                                                               run in the three-
                                                                                               run performance
                                                                                               test by computing
                                                                                               the average of
                                                                                               all the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
                                  b. Dry scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       sorbent injection   collect sorbent
                                   parameters.         minimum sorbent     rate monitors and   injection rate
                                                       injection rate      hydrogen chloride   data every 15
                                                       operating limit     performance test.   minutes during
                                                       according to Sec.                       the entire period
                                                         63.7530(c).                           of the
                                                                                               performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average sorbent
                                                                                               injection rate
                                                                                               for each
                                                                                               individual test
                                                                                               run in the three-
                                                                                               run performance
                                                                                               test by computing
                                                                                               the average of
                                                                                               all the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.7540, you must show continuous compliance 
with the emission limitations for affected sources according to the 
following:

[[Page 32072]]



Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
  If you must meet the following
 operating limits or work practice     You must demonstrate continuous
          standards . . .                    compliance by . . .
------------------------------------------------------------------------
1. Opacity........................  a. Collecting the opacity monitoring
                                     system data according to Sec.  Sec.
                                       63.7525(b) and 63.7535; and
                                    b. Reducing the opacity monitoring
                                     data to 6-minute averages; and
                                    c. Maintaining opacity to less than
                                     or equal to 10 percent (daily block
                                     average).
2. Fabric Filter Bag Leak           Installing and operating a bag leak
 Detection Operation.                detection system according to Sec.
                                      63.7525 and operating the fabric
                                     filter such that the requirements
                                     in Sec.   63.7540(a)(9) are met.
3. Wet Scrubber Pressure Drop and   a. Collecting the pressure drop and
 Liquid Flow-rate.                   liquid flow rate monitoring system
                                     data according to Sec.  Sec.
                                     63.7525 and 63.7535; and
                                    b. Reducing the data to 12-hour
                                     block averages; and
                                    c. Maintaining the 12-hour average
                                     pressure drop and liquid flow-rate
                                     at or above the operating limits
                                     established during the performance
                                     test according to Sec.
                                     63.7530(c).
4. Wet Scrubber pH................  a. Collecting the pH monitoring
                                     system data according to Sec.  Sec.
                                       63.7525 and 63.7535; and
                                    b. Reducing the data to 12-hour
                                     block averages; and
                                    c. Maintaining the 12-hour average
                                     pH at or above the operating limit
                                     established during the performance
                                     test according to Sec.
                                     63.7530(c).
5. Dry Scrubber Sorbent or Carbon   a. Collecting the sorbent or carbon
 Injection Rate.                     injection rate monitoring system
                                     data for the dry scrubber according
                                     to Sec.  Sec.   63.7525 and
                                     63.7535; and
                                    b. Reducing the data to 12-hour
                                     block averages; and
                                    c. Maintaining the 12-hour average
                                     sorbent or carbon injection rate at
                                     or above the operating limit
                                     established during the performance
                                     test according to Sec.  Sec.
                                     63.7530(c).
6. Electrostatic Precipitator       a. Collecting the secondary current
 Secondary Current and Voltage or    and voltage or total power input
 Total Power Input.                  monitoring system data for the
                                     electrostatic precipitator
                                     according to Sec.  Sec.   63.7525
                                     and 63.7535; and
                                    b. Reducing the data to 12-hour
                                     block averages; and
                                    c. Maintaining the 12-hour average
                                     secondary current and voltage or
                                     total power input at or above the
                                     operating limits established during
                                     the performance test according to
                                     Sec.  Sec.   63.7530(c).
7. Fuel Pollutant Content.........  a. Only burning the fuel types and
                                     fuel mixtures used to demonstrate
                                     compliance with the applicable
                                     emission limit according to Sec.
                                     63.7530(c) or (d) as applicable;
                                     and
                                    b. Keeping monthly records of fuel
                                     use according to Sec.   63.7540(a).
------------------------------------------------------------------------

    As stated in Sec.  63.7550, you must comply with the following 
requirements for reports:

       Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
------------------------------------------------------------------------
                                    The report must     You must submit
   You must submit a(n) . . .        contain . . .     the report . . .
------------------------------------------------------------------------
1. Compliance report............  a. Information      Semiannually
                                   required in Sec.    according to the
                                    63.7550(c)(1)      requirements in
                                   through (11); and   Sec.
                                                       63.7550(b).
                                  b. If there are no  ..................
                                   deviations from
                                   any emission
                                   limitation
                                   (emission limit
                                   and operating
                                   limit) that
                                   applies to you
                                   and there are no
                                   deviations from
                                   the requirements
                                   for work practice
                                   standards in
                                   Table 8 to this
                                   subpart that
                                   apply to you, a
                                   statement that
                                   there were no
                                   deviations from
                                   the emission
                                   limitations and
                                   work practice
                                   standards during
                                   the reporting
                                   period. If there
                                   were no periods
                                   during which the
                                   CMSs, including
                                   continuous
                                   emissions
                                   monitoring
                                   system,
                                   continuous
                                   opacity
                                   monitoring
                                   system, and
                                   operating
                                   parameter
                                   monitoring
                                   systems, were out-
                                   of-control as
                                   specified in Sec.
                                     63.8(c)(7), a
                                   statement that
                                   there were no
                                   periods during
                                   which the CMSs
                                   were out-of-
                                   control during
                                   the reporting
                                   period; and

[[Page 32073]]

 
                                  c. If you have a    ..................
                                   deviation from
                                   any emission
                                   limitation
                                   (emission limit
                                   and operating
                                   limit) or work
                                   practice standard
                                   during the
                                   reporting period,
                                   the report must
                                   contain the
                                   information in
                                   Sec.
                                   63.7550(d). If
                                   there were
                                   periods during
                                   which the CMSs,
                                   including
                                   continuous
                                   emissions
                                   monitoring
                                   system,
                                   continuous
                                   opacity
                                   monitoring
                                   system, and
                                   operating
                                   parameter
                                   monitoring
                                   systems, were out-
                                   of-control, as
                                   specified in Sec.
                                     63.8(c)(7), the
                                   report must
                                   contain the
                                   information in
                                   Sec.
                                   63.7550(e); and
                                  d. If you had a     ..................
                                   startup,
                                   shutdown, or
                                   malfunction
                                   during the
                                   reporting period
                                   and you took
                                   actions
                                   consistent with
                                   your startup,
                                   shutdown, and
                                   malfunction plan,
                                   the compliance
                                   report must
                                   include the
                                   information in
                                   Sec.
                                   63.10(d)(5)(i).
2. An immediate startup,          a. Actions taken    i. By fax or
 shutdown, and malfunction         for the event;      telephone within
 report if you had a startup,      and                 2 working days
 shutdown, or malfunction during  b. The information   after starting
 the reporting period that is      in Sec.             actions
 not consistent with your          63.10(d)(5)(ii).    inconsistent with
 startup, shutdown, and                                the plan; and
 malfunction plan, and the                            ii. By letter
 source exceeds any applicable                         within 7 working
 emission limitation in the                            days after the
 relevant emission standard.                           end of the event
                                                       unless you have
                                                       made alternative
                                                       arrangements with
                                                       the permitting
                                                       authority.
------------------------------------------------------------------------

    As stated in Sec.  63.7565, you must comply with the applicable 
General Provisions according to the following:

     Table 10 to Subpart DDDDD of Part 63--Applicability of General
                       Provisions to Subpart DDDDD
------------------------------------------------------------------------
                                                     Applies to subpart
          Citation                   Subject                DDDDD
------------------------------------------------------------------------
Sec.   63.1.................  Applicability.......  Yes.
Sec.   63.2.................  Definitions.........  Yes. Additional
                                                     terms defined in
                                                     Sec.   63.7575.
Sec.   63.3.................  Units and             Yes.
                               Abbreviations.
Sec.   63.4.................  Prohibited            Yes.
                               Activities and
                               Circumvention.
Sec.   63.5.................  Preconstruction       Yes.
                               Review and
                               Notification
                               Requirements.
Sec.   63.6(a), (b)(1)-       Compliance with       Yes.
 (b)(5), (b)(7), (c), (f)(2)-  Standards and
 (3), (g), (h)(2)-(h)(9),      Maintenance
 (i), (j).                     Requirements.
Sec.   63.6(e)(1), (e)(3),    Startup, shutdown,    No. Standards apply
 (f)(1), and (h)(1).           and malfunction       at all times,
                               requirements and      including during
                               Opacity/Visible       startup, shutdown,
                               Emission Limits.      and malfunction
                                                     events.
Sec.   63.7(a), (b), (c),     Performance Testing   Yes.
 (d), (e)(2)-(e)(9), (f),      Requirements.
 (g), and (h).
Sec.   63.7(e)(1)...........  Conditions for        No. Subpart DDDDD
                               conducting            specifies
                               performance tests..   conditions for
                                                     conducting
                                                     performance tests
                                                     at Sec.   63.7520.
Sec.   63.8.................  Monitoring            Yes.
                               Requirements.
Sec.   63.9.................  Notification          Yes.
                               Requirements.
Sec.   63.10(a), (b)(1),      Recordkeeping and     Yes.
 (b)(2)(i)-(iii), (b)(2)(vi)-  Reporting
 (xiv), (c), (d)(1)-(2),       Requirements.
 (e), and (f).
Sec.   63.10(b)(2)(iv)-(v),   ....................  No.
 (b)(3), and (d)(3)-(5).
Sec.   63.10(c)(15).........  Allows use of SSM     No.
                               plan.
Sec.   63.11................  Control Device        No.
                               Requirements.
Sec.   63.12................  State Authority and   Yes.
                               Delegation.
Sec.   63.13-63.16..........  Addresses,            Yes.
                               Incorporation by
                               Reference,
                               Availability of
                               Information,
                               Performance Track
                               Provisions.
Sec.   63.1(a)(5), (a)(7)-    Reserved............  No.
 (a)(9), (b)(2), (c)(3)-(4),
 (d), 63.6(b)(6), (c)(3),
 (c)(4), (d), (e)(2),
 (e)(3)(ii), (h)(3),
 (h)(5)(iv), 63.8(a)(3),
 63.9(b)(3), (h)(4),
 63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------

[FR Doc. 2010-10827 Filed 6-3-10; 8:45 am]
BILLING CODE 6560-50-P